UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
 þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Fiscal Year Ended September 30, 20082009
 
 o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Transition Period from           to          
 
Commission File Number 1-3880
 
National Fuel Gas Company
(Exact name of registrant as specified in its charter)
 
   
New Jersey13-1086010

(State or other jurisdiction of
incorporation or organization)		 13-1086010
(I.R.S. Employer
Identification No.)
6363 Main Street
Williamsville, New York
(Address of principal executive offices)		 14221
(Zip Code)
 
(716) 857-7000
Registrant’s telephone number, including area code
 
 
Securities registered pursuant to Section 12(b) of the Act:
 
   
  Name of
  Each Exchange
  on Which
Title of Each Class
 
Registered
 
Common Stock, $1 Par Value, and
Common Stock Purchase Rights		 New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 ofRegulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o     No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation 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 thisForm 10-K or any amendment to thisForm 10-K.  oþ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act. (Check one):
Large accelerated filer þAccelerated filer oNon-accelerated filer oSmaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Act).  Yes o     No þ
 
The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $3,768,755,000$2,414,082,000 as of March 31, 2008.2009.
 
Common Stock, $1 Par Value, outstanding as of October 31, 2008: 79,124,6442009: 80,560,665 shares.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the registrant’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.
 

 
Glossary of Terms
 
Frequently used abbreviations, acronyms, or terms used in this report:
 
National Fuel Gas Companies
National Fuel Gas Companies
 
CompanyThe Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
 
Data-TrackData-Track Account Services, Inc.
Distribution CorporationNational Fuel Gas Distribution Corporation
 
EmpireEmpire State Pipeline, Inc.
 
ESNEEnergy Systems North East, LLC
 
HighlandHighland Forest Resources, Inc.
 
HorizonHorizon Energy Development, Inc.
 
Horizon B.V.  Horizon Energy Development B.V.
 
Horizon LFGHorizon LFG, Inc.
 
Horizon PowerHorizon Power, Inc.
 
Leidy HubLeidy Hub, Inc.
Midstream CorporationNational Fuel Gas Midstream Corporation
 
Model CityModel City Energy, LLC
 
National FuelNational Fuel Gas Company
 
NFRNational Fuel Resources, Inc.
 
RegistrantNational Fuel Gas Company
 
SECISeneca Energy Canada Inc.
 
SenecaSeneca Resources Corporation
 
Seneca EnergySeneca Energy II, LLC
 
Supply CorporationNational Fuel Gas Supply Corporation
 
ToroToro Partners, LP
 
U.E. United Energy, a.s.
 
Regulatory Agencies
Regulatory Agencies
 
EPAUnited States Environmental Protection Agency
 
FASBFinancial Accounting Standards Board
 
FERCFederal Energy Regulatory Commission
 
NYDECNew York State Department of Environmental Conservation
NYPSCState of New York Public Service Commission
 
PaPUCPennsylvania Public Utility Commission
 
SECSecurities and Exchange Commission
 
Other
APB 18Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock
APB 25Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees
ARB 51Accounting Research Bulletin No. 51, Consolidated Financial Statements
 
BblBarrel (of oil)
 
BcfBillion cubic feet (of natural gas)
 
Bcfe (or Mcfe) — represents Bcf (or Mcf) EquivalentThe total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. National FuelThe Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
 
Board footA measure of lumberand/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.
 
BtuBritish thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
 
Capital expenditureRepresents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
 
Degree dayA measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
 
DerivativeA financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net, and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
 
Development costsCosts incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
 
Development wellA well drilled to a known producing formation in a previously discovered field.
 
DthDecatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
 
Exchange ActSecurities Exchange Act of 1934, as amended
 
Expenditures for long-lived assetsIncludes capital expenditures, stock acquisitionsand/or investments in partnerships.
 
ExploitationDevelopment of a field, including the location, drilling, completion and equipment of wells necessary to produce the commercially recoverable oil and gas in the field.
 
Exploration costsCosts incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
 
Exploratory wellA well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FIN FASB Interpretation Number
FIN 47FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations — an Interpretation of SFAS 143.
FIN 48FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an Interpretation of SFAS 109.
 
Firm transportationand/or storageThe transportationand/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
 
GAAP Accounting principles generally accepted in the United States of America
 
GoodwillAn intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
 
GridThe layout of the electrical transmission system or a synchronized transmission network.
 
HedgingA method of minimizing the impact of price, interest rate,and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
 
HubLocation where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
 
Interruptible transportationand/or storageThe transportationand/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
 
LIBORLondon Interbank Offered Rate
 
LIFOLast-in, first-out
 
MbblThousand barrels (of oil)
 
McfThousand cubic feet (of natural gas)
 
MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations
 
MDthThousand decatherms (of natural gas)
 
MMBtuMillion British thermal units
MMcfMillion cubic feet (of natural gas)
 
MMcfeMillion cubic feet equivalent
NGAThe Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
 
NYMEXNew York Mercantile Exchange.  An exchange which maintains a futures market for crude oil and natural gas.
 
Open SeasonA bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
 
Order 636An order issued by FERC entitled “Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation Under Part 284 of the Commission’s Regulations.”
 
PCBPolychlorinated Biphenyl
 
Proved developed reservesReserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
 
Proved undeveloped reservesReserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make thesethose reserves productive.
 
PRPPotentially responsible party
 
PUHCA 1935Public Utility Holding Company Act of 1935
 
PUHCA 2005Public Utility Holding Company Act of 2005
 
ReservesThe unproduced but recoverable oiland/or gas in place in a formation which has been proven by production.
 
RestructuringGenerally referring to partial ��deregulation”“deregulation” of the pipelineand/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundled”“unbundling”) of gas commodity service from transportation service for wholesale and large- volumelarge-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.
 
S&PStandard & Poor’s Ratings Service
SARStock-settled stock appreciation right
SFAS Statement of Financial Accounting Standards
SFAS 5Statement of Financial Accounting Standards No. 5, Accounting for Contingencies
SFAS 69Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities
SFAS 71Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation
SFAS 87Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions
SFAS 88Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
SFAS 106Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions.
SFAS 109Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
SFAS 112Statement of Financial Accounting Standards No. 112, Employers’ Accounting for Postemployment Benefits, an amendment of SFAS 5 and 43
SFAS 115Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities
SFAS 123Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation
SFAS 123RStatement of Financial Accounting Standards No. 123R, Share-Based Payment
SFAS 132RStatement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
SFAS 133Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities
SFAS 141RStatement of Financial Accounting Standards No. 141R, Business Combinations
SFAS 142Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets
SFAS 143Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations
SFAS 157Statement of Financial Accounting Standards No. 157, Fair Value Measurements
SFAS 158Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of SFAS 87, 88, 106, and 132R
SFAS 159Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115
SFAS 160Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51
SFAS 161Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133
 
Spot gas purchasesThe purchase of natural gas on a short-term basis.
 
Stock acquisitionsInvestments in corporations.
 
Unbundled serviceA service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
 
VEBAVoluntary Employees’ Beneficiary Association
 
WNCWeather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.
 

 
For the Fiscal Year Ended September 30, 20082009
 
CONTENTS
 
       
    Page
 
Part I
ITEM 1
 BUSINESS  3 
  The Company and its Subsidiaries  3 
  Rates and Regulation4
The Utility Segment  5 
  The UtilityPipeline and Storage Segment  5 
    The Pipeline and Storage Segment5
The Exploration and Production Segment  6 
  The Energy Marketing Segment6
All Other Category and Corporate Operations6
Discontinued Operations  7 
    The Timber SegmentSources and Availability of Raw Materials  7 
    All Other Category and Corporate OperationsCompetition  7 
    Discontinued Operations7
  Sources and Availability of Raw Materials7
  Competition8
Seasonality  9 
  Capital Expenditures 9
  Capital ExpendituresEnvironmental Matters9
Miscellaneous9
Executive Officers of the Company  10 
  Environmental Matters10
  Miscellaneous10
  Executive Officers of the Company11
ITEM 1A
 RISK FACTORS  1211 
ITEM 1B
 UNRESOLVED STAFF COMMENTS  1917 
ITEM 2
 PROPERTIES  1918 
 General Information on Facilities    General Information on Facilities1918 
 Exploration and Production Activities    Exploration and Production Activities2018 
ITEM 3
 LEGAL PROCEEDINGS  2322 
ITEM 4
 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS  2422 
 
Part II
ITEM 5
 MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES  2422 
ITEM 6
 SELECTED FINANCIAL DATA  2524 
ITEM 7
 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS  2725 
ITEM 7A
 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK  5862 
ITEM 8
 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA  5963 
ITEM 9
 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE  116125 
ITEM 9A
 CONTROLS AND PROCEDURES  116125 
ITEM 9B
 OTHER INFORMATION  116125 


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    Page
 
Part III
ITEM 10
 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE  116125 
ITEM 11
 EXECUTIVE COMPENSATION  117126 
ITEM 12
 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS  117126 
ITEM 13
 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE  118127 
ITEM 14
 PRINCIPAL ACCOUNTANT FEES AND SERVICES  118127 
 
Part IV
ITEM 15
 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES  118127 
SIGNATURES
  124133 
 EX-10.1
 EX-10.2
EX-10.3
EX-10.4
EX-10.5
 EX-12
 EX-21
 EX-23.1
 EX-23.2
 EX-31.1
 EX-31.2
 EX-32
 EX-99.1
 EX-99.2


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ThisForm 10-K contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements and important factors included in thisForm 10-K at Item 7, MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” and “may” and similar expressions.
 
PART I
 
Item 1  Business
 
The Company and its Subsidiaries
 
National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under the laws of the State of New Jersey. Except as otherwise indicated below, the Registrant owns directly or indirectly all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.
 
The Company is a diversified energy company and reports financial results for fivefour business segments.
 
1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 727,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.
 
2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire State Pipeline, Inc. (Empire), a New York joint venture between two wholly owned subsidiaries of the Company.corporation. Supply Corporation provides interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River and eastward to Ellisburg and Leidy, Pennsylvania, and (ii) 27 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields owned and operated jointly with other interstate gas pipeline companies. Empire, an intrastateinterstate pipeline company, acquired by the Company in 2003, transports natural gas for Distribution Corporation and for other utilities, large industrial customers and power producers in New York State. Empire owns the Empire Pipeline, which is a157-mile pipeline that extends from the United States/Canadian border at the Niagara River near Buffalo, New York to near Syracuse, New York. Empire is constructingYork, and the Empire Connector, project, which consists ofis a compressor station and a77-mile76-mile pipeline extension from near Rochester, New York to an interconnection near Corning, New York with the unaffiliated Millennium Pipeline project, which is also under construction.near Corning, New York. The Millennium Pipeline is expected to serveserves the New York City area upon its completion. Upon completion of thearea. The Empire Connector and Millennium Pipeline projects, which is currently expected to occur inwas placed into service on December 2008, the Company expects that Empire will become an interstate pipeline company and will merge into Empire Pipeline, Inc. as described below.10, 2008.
 
3. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas Louisiana, and Alabama,Louisiana, including offshore areas in federal


3

waters and some state waters. At September 30, 2008,2009, the Company had U.S. proved developed and undeveloped reserves of 46,19846,587 Mbbl of oil and 225,899248,954 MMcf of natural gas.


3

In 2007, Seneca sold its subsidiary, Seneca Energy Canada Inc. (SECI), which conducted exploration and production operations in the provinces of Alberta, Saskatchewan and British Columbia in Canada.
 
4. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation, which markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
 
5. The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a New York corporation, and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns two sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. At September 30, 2008, the Company owned 103,680 acres of timber property and managed an additional 3,122 acres of timber rights.
Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note JK — Business Segment Information.
 
The Company’s other direct wholly owned subsidiaries are not included in any of the fivefour reported business segments and consist ofinclude the following:following active companies:
 
• Highland Forest Resources, Inc. (Highland), a New York corporation which, together with a division of Seneca known as its Northeast Division, markets timber from New York and Pennsylvania land holdings, owns two sawmills in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. At September 30, 2009, the Company owned 103,317 acres of timber property and managed an additional 3,424 acres of timber rights;
 • Horizon Energy Development, Inc. (Horizon), a New York corporation formed to engage in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon’s wholly owned subsidiary, Horizon Energy Holdings, Inc., a New York corporation, which owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company that is in the process of winding up or selling certain power development projects in Europe;Europe. In July 2005, Horizon B.V. sold its entire 85.16% interest in United Energy, a.s., a district heating and electric generation business in the Czech Republic;
 
 • Horizon LFG, Inc. (Horizon LFG), a New York corporation engaged through subsidiaries in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Horizon LFG and one of its wholly owned subsidiaries own all of the partnership interests in Toro Partners, LP (Toro), a limited partnership which owns and operates short-distance landfill gas pipeline companies. The Company acquired Toro in June 2003;
• Leidy Hub, Inc. (Leidy Hub), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States;
• Data-Track Account Services, Inc. (Data-Track), a New York corporation formed to provide collection services principally for the Company’s subsidiaries;companies;
 
 • Horizon Power, Inc. (Horizon Power), a New York corporation which is an “exempt wholesale generator” under PUHCA 2005 and is developing or operating mid-range independent power production facilities and landfill gas electric generation facilities;
• Empire Pipeline, Inc., a New York corporation formed in 2005 to be the surviving corporation of a planned future merger with Empire, which is expected to occur after construction of the Empire Connector project (described below under the heading “Rates and Regulation” and under Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters”); and
 
 • National Fuel Gas Midstream Corporation (Midstream Corporation), a Pennsylvania corporation formed to build, own and operate natural gas processing and pipeline gathering facilities in the Appalachian region.
 
No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2008.2009.


4

 
Rates and Regulation
 
The Registrant is a holding company as defined under PUHCA 2005. PUHCA 2005 repealed PUHCA 1935, to which the Company was formerly subject, and granted the FERC and state public utility commissions access to certain books and records of companies in holding company systems. Pursuant to the FERC’s regulations under PUHCA 2005, the Company and its subsidiaries are exempt from the FERC’s books and records regulations under PUHCA 2005.
 
The Utility segment’s rates, services and other matters are regulated by the NYPSC with respect to services provided within New York and by the PaPUC with respect to services provided within Pennsylvania. For additional discussion of the Utility segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note C — Regulatory Matters.


4

The Pipeline and Storage segment’s rates, services and other matters are currently regulated by the FERC with respect to Supply Corporation and by the NYPSC with respect to Empire. The FERC has authorized Empire to construct and operate additional facilities (the Empire Connector project) and to become a FERC-regulated interstate pipeline company upon placement of those facilities into service, which is currently expected to occur in December 2008.FERC. For additional discussion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate and Regulatory Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note C — Regulatory Matters. For further discussion of the Empire Connector project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
 
The discussion under Item 8 at Note C — Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.
 
In addition, the Company and its subsidiaries are subject to the same federal, state and local (including foreign) regulations on various subjects, including environmental matters, to which other companies doing similar business in the same locations are subject.
 
The Utility Segment
 
The Utility segment contributed approximately 22.9%58.3% of the Company’s 20082009 net income available for common stock.
 
Additional discussion of the Utility segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials,” “Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Pipeline and Storage Segment
 
The Pipeline and Storage segment contributed approximately 20.1%47.0% of the Company’s 20082009 net income available for common stock.
 
Supply Corporation hasyear-to-year or longer service agreements for all of its firm storage capacity, totaling 68,408 MDth. The Utility segment has contracted for 27,865 MDth or 40.7% of the total firm storage capacity, and the Energy Marketing segment accounts for another 4,811 MDth or 7.1% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining 35,732 MDth or 52.2% of the total firm storage capacity. The majority of Supply Corporation’s storage and transportation services are performed under contracts that allow Supply Corporation or the shipper to terminate the contract upon six or twelve months’ notice effective at the end of the contract term. The contracts also typically include “evergreen” language designed to allow the contracts to extendyear-to-year at the end of the primary term. At the beginning of 2009, 72.0%2010, 82.9% of Supply Corporation’s total firm storage capacity was committed under contracts that, subject to 20082009 shipper or Supply Corporation notifications, could have been terminated effective in 2009.2010. Supply Corporation did not issue or


5

receive any such storage contract termination notifications in 2008.2009. The strong demand for market-area storage enabled Supply Corporation to eliminateprovide all of its remaining storage service rate discounts in 2007, and effective April 1, 2008, allyear-to-year or longer storage services were contractedin 2009 at the maximum tariff rates.
 
Supply Corporation’s firm transportation capacity is not limited to a fixed quantity, due to the diverse weblikeweb-like nature of its pipeline system, and is subject to change as the market identifies different transportation paths and receipt/delivery point combinations. Supply Corporation currently has firm transportation service agreements for approximately 2,1172,189 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,065 MDth per day or 50.3%48.7% of contracted transportation capacity, and the Energy Marketing and Exploration and Production segments represent another 102112 MDth per day or 4.8%5.1% of contracted transportation capacity. The remaining 9501,012 MDth or 44.9%46.2% of contracted transportation capacity is subject to firm contracts with nonaffiliated customers.
 
At the beginning of 2009, 49.3%2010, 52.7% of Supply Corporation’s contracted transportation capacity was committed under affiliate contracts that were scheduled to expire in 20092010 or, subject to 20082009 shipper or Supply Corporation notifications, could have been terminated effective in 2009.2010. Based on contract expirations and termination notices received in 20082009 for 20092010 termination, and taking into account any known contract


5

additions, contracted transportation capacity with affiliates is expected to decrease 0.3%increase 3.0% in 2009.2010. Similarly, 26.7%33.0% of contracted transportation capacity was committed under unaffiliated shipper contracts that were scheduled to expire in 20092010 or, subject to 20082009 shipper or Supply Corporation notifications, could have been terminated effective in 2009.2010. Based on contract expirations and termination notices received in 20082009 for 20092010 termination, and taking into account any known contract additions, contracted transportation capacity with unaffiliated shippers is expected to increase 9.4%5.3% in 2009.2010. This increase is due largely to the addition of compression at various facilities throughout the system as well as other projects designed to create incremental transportation capacity. Supply Corporation previously has been successful in marketing and obtaining executed contracts for available transportation capacity (at discounted rates when necessary), and expects this success to continue.
 
For the2008-20092009-2010 winter period, Empire has service agreements in place for the full amount of its firm transportation capacity to its existing delivery points, totaling approximately 547689 MDth per day.day (including capacity on the new Empire Connector facilities discussed below). Most of Empire’s firm contracted capacity (91.2%(93.0%) has been contracted as long-term full-year deals. A small numberTwo of those contracts are due to expire during fiscal 2009,2010, representing 1.4%just 0.1% of Empire’s firm contracted capacity. In addition, Empire has some seasonal (winter-only) contracts that extend for multiple years, representing 2.7%2.5% of Empire’s firm contracted capacity. One of those seasonal contracts is due to expire during fiscal 2009;2010, representing 1.1%just 0.1% of Empire’s firm contracted capacity. Arrangements for the remaining 6.1%4.5% of Empire’s firm contracted capacity are seasonalsingle-season or annualsingle-year contracts that expire before the end of fiscal 2009.during 2010 or early in 2011. Empire expects that all available capacity arising from expiring agreements will be re-contracted under newas seasonal or annualfull-year agreements. The Utility segment accounts for approximately 7.8%6.1% of Empire’s firm contracted capacity, and the Energy Marketing segment accounts for approximately 1.9%1.2% of Empire’s firm contracted capacity, with the remaining 90.3%92.7% of Empire’s firm contracted capacity subject to contracts with nonaffiliated customers.
 
Upon the completion of theEmpire’s new facilities (the Empire Connector project, Empire will have expansion capacity for the2008-2009 winter period.project) were placed into service on December 10, 2008. Empire has a firm service agreement for 150.7 MDth per day of this expansion capacity. This long-term full-year agreement represents approximately 60% of the Empire Connector expansionConnector’s total capacity. The Company continues to market the remaining capacity on both a firm and interruptible basis. None of this contracted expansion capacity will expire during fiscal 2009.2010.
 
Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Exploration and Production Segment
 
The Exploration and Production segment contributed approximately 54.6%incurred a net loss in 2009. The impact of this net loss in relation to the Company’s 20082009 net income available for common stock.stock was negative 10.2%. The net loss in the Exploration and Production segment was largely driven by an impairment charge of $182.8 million ($108.2 million after tax).


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Additional discussion of the Exploration and Production segment appears below under the headings “Discontinued Operations,” “Sources and Availability of Raw Materials” and “Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Energy Marketing Segment
 
The Energy Marketing segment contributed approximately 2.2%7.1% of the Company’s 20082009 net income available for common stock.
 
Additional discussion of the Energy Marketing segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Energy Marketing Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
The Timber Segment
The Timber segment’s contribution to the Company’s 2008 net income available for common stock was not significant.
Additional discussion of the Timber segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Timber Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
All Other Category and Corporate Operations
 
The All Other category and Corporate operations contributed approximately 0.2%incurred a net loss in 2009. The impact of this net loss in relation to the Company’s 20082009 net income available for common stock.stock was negative 2.2%.


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Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
Discontinued Operations
 
In August 2007, Seneca sold all of the issued and outstanding shares of SECI. SECI’s operations are presented in the Company’s financial statements as discontinued operations.
 
In July 2005, Horizon B.V. sold its entire 85.16% interest in United Energy, a.s. (U.E.), a district heating and electric generation business in the Czech Republic. United Energy’s operations are presented in the Company’s financial statements as discontinued operations.
Additional discussion of the Company’s discontinued operations appears in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
 
Sources and Availability of Raw Materials
 
Natural gas is the principal raw material for the Utility segment. In 2008,2009, the Utility segment purchased 76.076.8 Bcf of gas for core market demand.delivery to its customers. All such purchases were made from non-affiliated companies. Gas purchased from producers and suppliers in the southwestern United States and Canada under firm contracts (seasonal and longer) accounted for 89%56% of these purchases. Purchases of gas on the spot market (contractsunder contracts for one month or less)less accounted for 11%44% of the Utility segment’s 20082009 purchases. Purchases from Total Gas & Power North America Inc. (18%(20%), Chevron Natural Gas (17%(15%), BP Canada (14%) and ConocoPhillips Company (16%) and BP Canada (11%(12%) accounted for 62%61% of the Utility’s 20082009 gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2008.2009.
 
Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern, mid-continent and Appalachian regions of the United States as well as in Canada. Empire transports gas owned by its customers, whose gas originates in the southwestern and mid-continent regions of the United States as well as in Canada. Additional discussion of proposed pipeline projects appears below under “Competition: The Pipeline and Storage Segment” and in Item 7, MD&A.


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The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Note JK — Business Segment Information and Note OQ — Supplementary Information for Oil and Gas Producing Activities.
With respect to the Timber segment, Highland requires an adequate supply of timber to process in its sawmill and kiln operations. Fifty-two percent of the timber processed during 2008 in Highland’s sawmill operations came from land owned by the Company’s subsidiaries, and 48% came from outside sources. Timber cut for gas well drilling locations, access roads, and pipelines constituted an increasing portion of Highland’s timber supply, both from land owned by the Company’s subsidiaries and from outside sources. In addition, Highland purchased approximately 5.4 million board feet of green lumber to augment lumber supply for its kiln operations.
 
The Energy Marketing segment depends on an adequate supply of natural gas to deliver to its customers. In 2008,2009, this segment purchased 5762.5 Bcf of gas, including 5660.9 Bcf for core market demands.delivery to its customers. The remaining 11.6 Bcf largely represents gas used in operations. The gas purchased by the Energy Marketing segment originates in either the Appalachian or mid-continent regions of the United States or in Canada.
 
Competition
 
Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy. The natural gas industry has gone through various stages of regulation. Apart from environmental and state utility commission regulation, the natural gas industry has experienced considerable deregulation. This has enhanced the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, since some of the historical regulatory impediments to adding customers and responding to market forces have been removed. In addition, management believes that the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.
 
The electric industry has been moving toward a more competitive environment as a result of changes in federal law in 1992 and initiatives undertaken by the FERC and various states. It remains unclear what the impact of any further restructuring in response to legislation or other events may be.
 
The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.


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Competition: The Utility Segment
 
The changes precipitated by the FERC’s restructuring of the natural gas industry in Order No. 636, which was issued in 1992, continue to reshape the roles of the gas utility industry and the state regulatory commissions. InWith respect to gas commodity service, in both New York and Pennsylvania, Distribution Corporation has retained a substantial numbersmajority of small sales customers. Almost all large-volume load, however, is served by unregulated retail marketers. In New York, approximately 20% of Distribution Corporation’s small-volume residential and small commercial customers as sales customers. However, for many years almost all the industrial and a substantial number of commercial customers have purchasedpurchase their gas supplies from marketers and utilized Distribution Corporation’s gas transportation services. Regulators in both New York and Pennsylvania have adopted retail competition programs for natural gas supply purchases by the remaining utility sales customers. To date, the Utility segment’s traditional distribution function remains largely unchanged; however, in New York, the Utility segment has instituted a number of programs to accommodate more widespread customer choice.unregulated marketers. In Pennsylvania, the PaPUC issued a report in October 2005 that concluded “effective competition”is currently revising regulations and business practices to promote the growth of small-volume retail competition. Retail competition for gas commodity service does not existpose an acute competitive threat for Distribution Corporation because in both jurisdictions, LDC cost of service is recovered through distribution rates and charges, not through charges for gas commodity service. Over the longer run, however, rate design changes resulting from further customer migration to marketer service (e.g., “unbundling”) can expose utility companies such as Distribution Corporation to stranded costs and revenue erosion in the retail natural gas supply market statewide. On September 11, 2008, the PaPUC adopted a Final Order and Action Plan designed to “increase effective competition in the retail market for natural gas services.” The plan sets forth a scheduleabsence of action items for utilities and the PaPUC in order to remove “barriers in the market structure” that, in the opinion of the PaPUC, prevented the full participation of unregulated natural gas suppliers in Pennsylvania retail markets.compensating rate relief.
 
Competition for transportation service to large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.suppliers.


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The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible, high quality services. The Utility segment continues to develop or promote new sources and uses of natural gas or new services, rates and contracts. The Utility segment also emphasizes and provides high quality service to its customers.
 
Competition: The Pipeline and Storage Segment
 
Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position. Its facilities are located adjacent to Canada and the northeastern United States and provide part of the link between gas-consuming regions of the eastern United States and gas-producing regions of Canada and the southwestern, southern and other continental regions of the United States. This location offersNew productive areas in the Appalachian region related to the development of the Marcellus Shale formation, in addition to the aforementioned regions, offer the opportunity for increased transportation and storage services in the future.
 
Empire competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is well situated to provide transportation from Canadian sourced gas, and its facilities are readily expandable. These characteristics provide Empire the opportunity to compete for an increased share of the gas transportation markets. As noted above, Empire is constructinghas constructed the Empire Connector project, which will expandexpands its natural gas pipeline and enableenables Empire to serve new markets in New York and elsewhere in the Northeast. For further discussion of this project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
 
Competition: The Exploration and Production Segment
 
The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects.
 
To compete in this environment, Seneca originates and acts as operator on certain of its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both exploratory studies and drilling operations, and seeks market niches based on size, operating expertise and financial criteria.


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Competition: The Energy Marketing Segment
 
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy supply. Competition in this area is well developed with regard to price and services from local, regional and, more recently, national marketers.
Competition: The Timber Segment
With respect to the Timber segment, Highland competes with other sawmill operations and with other suppliers of timber, logs and lumber. These competitors may be local, regional, national or international in scope. This competition, however, is primarily limited to those entities which either process or supply high quality hardwood species such as cherry, oak and maple as veneer logs, saw logs, export logs or lumber ultimately used in the production of high-end furniture, cabinetry and flooring. The Timber segment sells its products in domestic and international markets.
 
Seasonality
 
Variations in weather conditions can materially affect the volume of gas delivered by the Utility segment, as virtually all of its residential and commercial customers use gas for space heating. The effect that this has on Utility segment margins in New York is mitigated by a WNC, which covers the eight-month period from October through May. Weather that is warmer than normal results in a surcharge being addedan upward adjustment to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills.downward adjustment, so that in either case projected operating costs calculated at normal temperatures will be recovered.
 
Volumes transported and stored by Supply Corporation and volumes transported by Empire may vary materially depending on weather, without materially affecting its revenues. Supply Corporation’s and Empire’s allowed rates are based on a straight fixed-variable rate


9

design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover only the variable costs associated with actual transportation or storage of gas.
 
Volumes transported by Empire may vary materially depending on weather, which can have a moderate effect on its revenues. Empire’s allowed rates currently are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover variable costs associated with actual transportation of gas, to recover return on equity, and to recover income taxes. When Empire becomes a FERC-regulated interstate pipeline company (which is currently expected to occur in December 2008), Empire’s allowed rates, like Supply Corporation’s, will be based on a straight fixed-variable design. Under that rate design, weather-related variations in transportation volumes will not materially affect revenues.
Variations in weather conditions materially affect the volume of gas consumed by customers of the Energy Marketing segment. Volume variations have a corresponding impact on revenues within this segment.
The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. Traditionally, the timber harvesting season occurs when timber growth is dormant and runs from approximately September to March. The operations conducted in the summer months typically focus on pulpwood and on thinning lower-grade or lower value trees from timber stands to encourage the growth of higher-grade or higher value trees.
 
Capital Expenditures
 
A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”
 
Environmental Matters
 
A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Environmental Matters” and in Item 8, Note HI — Commitments and Contingencies.
 
Miscellaneous
 
The Company and its wholly owned or majority-owned subsidiaries had a total of 1,9431,949 full-time employees at September 30, 2008.2009. This is a decrease of approximately one-half of one percent from the 1,952compares to 1,943 employees in the Company’s U.S. operations at September 30, 2007.2008.
 
In 2008 theThe Company entered into newhas agreements in place with collective bargaining units in New York. The new agreements went into effect in February 2008York and expire in February 2013. In November 2008 the Company entered into a new agreement with a collective bargaining unit in Pennsylvania. The agreement will go into effectagreements in April 2009 and expire in April 2014. An agreement covering employees in another collective bargaining unit in Pennsylvania isNew York are scheduled to expire in May 2009. In November 2008February 2013 and the Company reached a new agreement with the local leadership of that collective bargaining unit. The members of the collective bargaining unitagreements in Pennsylvania are scheduled to vote on the agreementexpire in December 2008.April 2014 and May 2014.
 
The Utility segment has numerous municipal franchises under which it uses public roads and certain otherrights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.
 
The Company makes its annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, and any amendments to those reports, available free of charge on the Company’s internet website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Company’s internet website is not part of thisForm 10-K or any other report filed with or furnished to the SEC.


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Executive Officers of the Company as of November 15, 2008(1)2009(1)
 
   
  Current Company
  Positions and
  Other Material
  Business Experience
Name and Age (as of
 During Past
November 15, 2008)2009)
 Five Years
 
David F. Smith
(55)(56)		 Chief Executive Officer of the Company since February 2008 and President of the Company since February 2006. Mr. Smith previously served as Chief Operating Officer of the Company from February 2006 through January 2008; President of Supply Corporation from April 2005 through June 2008; President of Empire from April 2005 through January 2008; Vice President of the Company from April 2005 through January 2006; President of Distribution Corporation from July 1999 to April 2005; and Senior Vice President of Supply Corporation from July 2000 to April 2005.
Ronald J. Tanski
(56)(57)		 Treasurer and Principal Financial Officer of the Company since April 2004; President of Supply Corporation since July 2008. Mr. Tanski previously served as President of Distribution Corporation from February 2006 through June 2008; Treasurer of Distribution Corporation from April 2004 through September 2008; Controller of the Company from February 2003 through March 2004;and Senior Vice President of Distribution Corporation from July 2001 through January 2006; and Controller of Distribution Corporation from February 1997 through March 2004.2006.
Matthew D. Cabell
(50)(51)		 President of Seneca since December 2006. Prior to joining Seneca, Mr. Cabell served as Executive Vice President and General Manager of Marubeni Oil & Gas (USA) Inc., an exploration and production company, from June 2003 to December 2006. From January 2002 to June 2003, Mr. Cabell served as a consultant assisting oil companies in upstream acquisition and divestment transactions as well as Gulf of Mexico entry strategy, first as an independent consultant and then as Vice President of Randall & Dewey, Inc., a major oil and gas transaction advisory firm. Mr. Cabell’s prior employers areemployer is not subsidiariesa subsidiary or affiliatesaffiliate of the Company.
Anna Marie Cellino
(55)(56)		 President of Distribution Corporation since July 2008. Ms. Cellino previously served as Secretary of the Company from October 1995 through June 2008; Secretary of Distribution Corporation from September 1999 through September 2008; and Senior Vice President of Distribution Corporation from July 2001 through June 2008.
Karen M. Camiolo
(49)(50)		 Controller and Principal Accounting Officer of the Company since April 2004; and Controller of Distribution Corporation and Supply Corporation since April 2004; and Chief Auditor of the Company from July 1994 through March 2004.
Carl M. Carlotti
(53)(54)		 Senior Vice President of Distribution Corporation since January 2008. Mr. Carlotti previously served as Vice President of Distribution Corporation from October 1998 to January 2008.
Paula M. Ciprich
(48)(49)		 Secretary of the Company since July 2008; General Counsel of the Company since January 2005; Secretary of Distribution Corporation since July 2008. Ms. Ciprich previously served as General Counsel of Distribution Corporation from February 1997 through February 2007 and as Assistant Secretary of Distribution Corporation from February 1997 through June 2008.
Donna L. DeCarolis
(49)(50)		 Vice President Business Development of the Company since October 2007. Ms. DeCarolis previously served as President of NFR from January 2005 to October 2007; Secretary of NFR from March 2002 to October 2007; and Vice President of NFR from May 2001 to January 2005.
John R. Pustulka
(56)(57)		 Senior Vice President of Supply Corporation since July 2001.
James D. Ramsdell
(53)(54)		 Senior Vice President of Distribution Corporation since July 2001.
 
 
(1)The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served or currently serve as officers or directors of other subsidiaries of the Company.


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Item 1A  Risk Factors
 
As a holding company, National Fuelthe Company depends on its operating subsidiaries to meet its financial obligations.
 
National FuelThe Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, National Fuelthe Company relies exclusively on repayments of principal and interest on intercompany loans made by National Fuelthe Company to its operating subsidiaries and income from dividends and other cash flow from the subsidiaries. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.
 
Recent disruptions in financialThe Company is dependent on credit markets may affect National Fuel’s ability to obtain financing or refinance maturing debt on reasonable terms and may have other adverse effects.successfully execute its business strategies.
 
Widely-documented disruptions in financialThe Company relies upon short-term bank borrowings, commercial paper markets have resulted in a severe tighteningand longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit availabilitysources may be cyclical and these capital sources may not remain available to the Company. Turmoil in the United States. Liquidity in credit markets has contracted significantly, making terms for certain financings less attractive. Ongoing turmoil in the credit markets may make it difficult for National Fuelthe Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, andor to refinance maturing debt on favorable terms. These difficulties could adversely affect National Fuel’sthe Company’s growth strategies, operations and financial performance.
National Fuel is dependent on bank credit facilities and continued access to capital markets to successfully execute its operating strategies.
In addition to its longer term debt that is issued to the public under its indentures, National Fuel relies upon shorter term bank borrowings and commercial paper to finance a portion of its operations. National Fuel is dependent on these capital sources to provide capital to its subsidiaries to allow them to acquire, maintain and develop their properties. The availability and cost of these credit sources is cyclical and these capital sources may not remain available to National Fuel or National Fuel may not be able to obtain money at a reasonable cost in the future. Recent access to the commercial paper markets has been on less favorable terms as a result of ongoing turmoil in the credit markets, and the commercial paper markets may not consistently be a reliable source of short-term financing for National Fuel in the future. National Fuel’sCompany’s ability to borrow under its credit facilities and commercial paper agreements, dependsand its ability to issue long-term debt under its indentures, depend on National Fuel’sthe Company’s compliance with its obligations under the facilities, agreements and agreements.indentures. In addition, all of National Fuel’sthe Company’s short-term bank loans are in the form of floating rate debt or debt that may have rates fixed for very short periods of time. At present, National Fuel has no active interest rate hedgestime, resulting in placeexposure to protect against interest rate fluctuations on short-term bank debt. In addition,in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on National Fuel’sthe Company’s short-term bank loans and the ability of National Fuelthe Company to issue commercial paper are affected by its debt credit ratings published by Standard & Poor’s Ratings Service (“S&P”), Moody’s Investors Service and Fitch Ratings Service. On October 15, 2008, National Fuel’s senior unsecuredA downgrade in the Company’s credit rating of BBB+ was placed on CreditWatch-with negative implications by S&P. A ratings downgrade could increase the interest cost of debt issued by National Fuelborrowing costs and decrease futurenegatively impact the availability of moneycapital from banks, commercial paper purchasers and other sources. National Fuel’s debt securities are currently rated at investment grade and the Company believes it is important to maintain investment grade credit ratings to conduct its business.
 
National FuelThe Company may be adversely affected by economic conditions and their impact on our suppliers and customers.
 
Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect National Fuel’sthe Company’s revenues and cash flows or restrict its future growth. Economic conditions in National Fuel’sthe Company’s utility service territories and energy marketing territories also impact its collections of accounts receivable. All of National Fuel’sthe Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets. These conditions could result in financial


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instability or other adverse effects at any of our suppliers or customers. For example, counterparties to National Fuel’sthe Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements.arrangements or contracts. Customers of National Fuel’sthe Company’s Utility and Energy Marketing segments may have particular trouble paying their bills during periods of declining economic activity and high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. Any of these events could have a material adverse effect on National Fuel’sthe Company’s results of operations, financial condition and cash flows.
 
The increasing costs of certain employee and retiree benefits could adversely affect National Fuel’s results.
National Fuel’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, National Fuel might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension and medical benefits could have an adverse effect on National Fuel’s financial results.
National Fuel’sCompany’s credit ratings may not reflect all the risks of an investment in its securities.
 
National Fuel’sThe Company’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. National Fuel’sThe


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Company’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in thisForm 10-K.
 
National Fuel’sThe Company’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
 
While National Fuelthe Company generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of National Fuel’sthe Company’s businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may affect its business in ways that the Company cannot predict.
 
In itsthe Company’s Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the PaPUC.FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or ifto the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.
 
In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have sought to establish competitive markets in which customers may purchase supplies of gas commodity from unregulated marketers, rather than fromin addition to utility companies. In June 1999, the Governor of Pennsylvania signed into law the Natural Gas Choice and Competition Act. The Act revised the Public Utility Code relating to the restructuring of the natural gas industry, to permit consumer choice of natural gas suppliers. The early programs instituted to comply with the Act did not result in significant change, and many residential customers currently continue to purchase natural gas from the utility companies. In October 2005, the PaPUC concluded that “effective competition” does not exist in the retail natural gas supply market statewide. On September 11, 2008, the PaPUC adopted a Final Order and Action Plan designed to “increase effective competition in the retail market for natural gas services.” The plan sets forth a schedule of action items for utilities and the PaPUC in order to remove “barriers in the market structure” that, in the opinion of the PaPUC, prevented the full participation of unregulated natural gas


13

suppliers in Pennsylvania retail markets. In New York, in August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail Energy Markets. This policy statement has a similar goal of encouraging customer choice of alternative natural gas providers. In 2005, the NYPSC stepped up itsTo date those efforts to encourage customer choice at the retail residential level, and customer choice activities increased in Distribution Corporation’s New York service territory. In April 2007, the NYPSC, noting that the retail energy marketplacehave been more successful in New York, is established and continuingwhere approximately 20% of Distribution Corporation’s retail sales customers purchase gas commodity from unregulated marketers, than in Pennsylvania, where retail competition remains a fledgling movement. The PaPUC, however, has undertaken recent measures to expand, commenced a review to determine if existing programs initially designed to promoteenhance competition had outlived their usefulness and whether thein that state. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation, because in both jurisdictions, it recovers its cost of programs currently fundedservice through distribution rates and charges, and not through anymark-up on the gas commodity purchased by utilityits customers. Over the longer run, however, rate payers should be shifteddesign changes resulting from further customer migration to market competitors. Increased retail choice activities,marketer service (“unbundling”) can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the extent they occur, may increase Distribution Corporation’s costabsence of doing business, put an additional portion of its business at regulatory risk, and create uncertainty for the future, all of which may make it more difficult to manage Distribution Corporation’s business profitably.compensating rate relief.
 
Both the NYPSC and the PaPUC have instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a “revenue decoupling mechanism” that renders Distribution Corporation’s New York division financially indifferent to the effects of conservation. In Pennsylvania, although a proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief.
 
In its PipelineNew York, aggressive generic statewide programs created under the label of efficiency or conservation continue to generate a sizable utility funding requirement for state agencies that administer those programs. Although utilities are authorized to recover the cost of efficiency and Storage segment, National Fuelconservation program funding through special rates and surcharges, the resulting upward pressure on customer rates, coupled with increased assessments and taxes, could affect future tolerance for traditional utility rate increases, especially if gas costs were to increase.
The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and to the jurisdiction of the NYPSC with respect to Empire.some transactions performed by other Company subsidiaries, including Seneca Resources, Distribution


12

Corporation and NFR. The FERC, has authorized Empire to construct and operate the Empire Connector project. When Empire completes construction and commences operations of the Empire Connector, Empire will at that time become a FERC-regulated pipeline company. The FERC and the NYPSC, among other things, approveapproves the rates that Supply Corporation and Empire respectively, may charge to their natural gas transportationand/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporation’s and Empire’s rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportationand/or storage customers, or if Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s or Empire’s earnings may decrease. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Company’s other subsidiaries are subject to the FERC’s penalty authority.
 
National Fuel’sThe Company’s liquidity, and in certain circumstances, its earnings, could be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.
 
Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Nevertheless, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of National Fuel’sthe Company’s capital resources. National FuelThe Company has issued commercial paper and used short-term borrowings in the past to temporarily finance storage inventories and purchased gas costs, and although National Fuelthe Company expects to do so in the future, it may not be able to access the markets for such borrowings at attractive interest rates or at all. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. Due to the nature of the regulatory process, there is a risk of a disallowance of full recovery of these costs during any period in which there has been a substantial upward spike in these costs. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings. In addition, even when Distribution Corporation is allowed full recovery of these purchased


14

gas costs, during periods when natural gas prices are significantly higher than historical levels, customers may have trouble paying the resulting higher bills, and Distribution Corporation’s bad debt expenses may increase and ultimately reduce earnings.
 
Changes in interest rates may affect National Fuel’sthe Company’s ability to finance capital expenditures and to refinance maturing debt.
 
National Fuel’sThe Company’s ability to finance capital expenditures and to refinance maturing debt will depend in part upon interest rates. The direction in which interest rates may move is uncertain. Declining interest rates have generally been believed to be favorable to utilities, while rising interest rates are generally believed to be unfavorable, because of the levels of debt that utilities may have outstanding. In addition, National Fuel’sthe Company’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, National Fuel’sthe Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, National Fuel’sthe Company’s ability to earn its authorized rate of return may be adversely impacted.
 
Decreased oil and natural gas prices could adversely affect revenues, cash flows and profitability.
 
National Fuel’sThe Company’s exploration and production operations are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, including natural disasters; the supply and price of foreign oil and natural gas; the level of consumer product demand; national and worldwide economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; political conditions in foreign countries; the price and availability of alternative fuels; the proximity to, and availability of capacity on transportation facilities; regional levels of supply and demand; energy conservation measures; and government


13

regulations, such as regulation of natural gas transportation, royalties, and price controls. National FuelThe Company sells most of its oil and natural gas at current market prices rather than through fixed-price contracts, although as discussed below, National Fuelthe Company frequently hedges the price of a significant portion of its future production in the financial markets. The prices National Fuelthe Company receives depend upon factors beyond National Fuel’sthe Company’s control, including the factors affecting price mentioned above. National FuelThe Company believes that any prolonged reduction in oil and natural gas prices would restrict its ability to continue the level of exploration and production activity National Fuelthe Company otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.
 
National FuelThe Company has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.
 
In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, National Fuel periodicallythe Company regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of National Fuel’sthe Company’s expected energy production during the upcoming12-month period. These contracts reduce exposure to subsequent price drops but can also limit National Fuel’sthe Company’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its volumes of gas stored underground. National Fuel’sThe Company’s Pipeline and Storage segment enters into hedging arrangements with respect to certain sales of efficiency gas, and the All Other category has hedging arrangements in place with respect to certain volumes of landfill gas committed for sale.gas.
 
Under applicable accounting rules, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines in which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of


15

certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would bemarked-to-market on the income statement without regard to an underlying physical transaction. Gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.
 
Use of energy commodity price hedges also exposes National Fuelthe Company to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements.
 
It is National Fuel’sthe Company’s policy that the use of commodity derivatives contracts comply with various restrictions in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. Similar restrictions apply in the Pipeline and Storage segment and the All Other category. National Fuelsegment. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose National Fuelthe Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.


14

You should not place undue reliance on reserve information because such information represents estimates.
 
ThisForm 10-K contains estimates of National Fuel’sthe Company’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by National Fuel’sthe Company’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating National Fuel’s oil and natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and natural gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to National Fuel’sthe Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of National Fuel’sthe Company’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
 
If conditions remain constant, then National Fuelthe Company is reasonably certain that its reserve estimates represent economically recoverable oil and natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from National Fuel’sthe Company’s proved reserves is the current market value of National Fuel’sthe Company’s estimated oil and natural gas reserves. In accordance with SEC requirements, National Fuelthe Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of National Fuel’sthe Company’s reserves.
 
Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to National Fuel’sthe Company’s reserve


16

estimates in the future. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the production and operating costs incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.
 
The amount and timing of actual future oil and natural gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce National Fuel’sthe Company’s earnings.
 
There are many risks in developing oil and natural gas, including numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of National Fuel’sthe Company’s Exploration and Production segment depends on its ability to develop additional oil and natural gas reserves that are economically recoverable, and its failure to do so may reduce National Fuel’sthe Company’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. National Fuel’sThe Company’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for oil and natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their


15

cancellation. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or National Fuelthe Company may not recover all or any portion of its investment. Without continued successful exploitation or acquisition activities, National Fuel’sthe Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. National FuelThe Company cannot assure you that it will be able to find or acquire additional reserves at acceptable costs.
 
Financial accounting requirements regarding exploration and production activities may affect National Fuel’sthe Company’s profitability.
 
National FuelThe Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, National Fuelthe Company must compare the level of its unamortized investment in oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses quarter-end spot prices for oil and natural gas (as adjusted for hedging). If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be “impaired,” and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require National Fuelthe Company to recognize an immediate expense in that quarter, and its earnings would be reduced. National Fuel’sThe Company’s Exploration and Production segment last recorded an impairment charge under the full cost method of accounting in 2006. Becausethe quarter ended December 31, 2008. If spot market prices at a subsequent quarter end are lower than prices at December 31, 2008, absent any changes in other factors affecting the present value of the variability in National Fuel’s investment infuture net revenue projected to be recovered from the Company’s oil and natural gas properties, and the volatile natureCompany would be required to record an additional impairment charge. Depending on the magnitude of commoditythe decrease in prices, National Fuel cannot predict when in the future it may againthat charge could be affected by such an impairment calculation.material.
 
Environmental regulation significantly affects National Fuel’sthe Company’s business.
 
National Fuel’sThe Company’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. Costs of compliance and liabilities could negatively affect National Fuel’sthe Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental


17

laws and regulations could require unexpected capital expenditures at National Fuel’s facilities.the Company’s facilities or delay or cause the cancellation of expansion projects or oil and natural gas drilling activities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect National Fuel’sthe Company’s business. Although National Fuelthe Company cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local regulations, National Fuel’sthe Company’s costs could increase if environmental laws and regulations become more strict.
 
The nature of National Fuel’sthe Company’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
 
National Fuel’sThe Company’s operations in its various segments are subject to inherent hazards and risks such as: fires; natural disasters; explosions; geological formations with abnormal pressures; blowouts during well drilling; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, National Fuel’sthe Company’s facilities, machinery, and equipment may be subject to sabotage. Any of these events could cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, or governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, National Fuelthe Company maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that National Fuelthe Company executes with contractors provide for the division of responsibilities between the contractor and National Fuel,the Company, and National Fuelthe Company seeks to obtain an indemnification from the contractor for certain of these risks. National FuelThe Company is not always able, however, to


16

secure written agreements with its contractors that contain indemnification, and sometimes National Fuelthe Company is required to indemnify others.
 
Insurance or indemnification agreements when obtained may not adequately protect National Fuelthe Company against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to National Fuel.the Company . In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.
 
Due to the significant cost of insurance coverage for named windstorms in the Gulf of Mexico, National Fuelthe Company determined that it was not economical to purchase insurance to fully cover its exposures related to such storms. It is possible that named windstorms in the Gulf of Mexico could have a material adverse effect on National Fuel’sthe Company’s results of operations, financial condition and cash flows.
 
Hazards and risks faced by National Fuel,the Company, and insurance and indemnification obtained or provided by National Fuel,the Company, may subject National Fuelthe Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against National Fuelthe Company or be resolved on unfavorable terms, the result of which could have a material adverse effect on National Fuel’sthe Company’s results of operations, financial condition and cash flows.
The increasing costs of certain employee and retiree benefits could adversely affect the Company’s results.
The Company’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, the Company might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension and medical benefits could have an adverse effect on the Company’s financial results.
 
Significant shareholders or potential shareholders may attempt to effect changes at National Fuelthe Company or acquire control over National Fuel,the Company, which could adversely affect National Fuel’sthe Company’s results of operations and financial condition.
 
In January 2008, National Fuelthe Company entered into an agreement with New Mountain Vantage GP, L.L.C. (“New Mountain”) and certain parties related to New Mountain, including the California Public Employees’ Retirement System (collectively, “Vantage”), to settle a proxy contest pertaining to the election of directors to National Fuel’sthe Company’s Board of Directors at National Fuel’sthe Company’s 2008 Annual Meeting of Stockholders. Pursuant to theThat settlement agreement National Fuel andexpired on September 15, 2009. Vantage agreed, among other things, to a standstill whereby, until September 2009, Vantage will not, among other things, acquire voting securities that would increase its beneficial ownership to more than 9.6% of National Fuel’s voting securities; engage in any proxy solicitations or advance any shareholder proposals; attempt to control National Fuel’s Board of Directors, management or


18

policies; call a meeting of shareholders; obtain additional representation to the Board of Directors; or effect the removal of any member of the Board of Directors. At the end of the standstill period, Vantage may again seek to effect changes at National Fuel or acquire control over National Fuel. In addition, other existing or potential shareholders may engage in proxy solicitations or advance shareholder proposals after the Company’s 2010 Annual Meeting of Stockholders, or otherwise attempt to effect changes or acquire control over National Fuel.the Company.
 
Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as changes in strategy or management, changes to the board of directors,financial restructuring, increased financial leverage,debt, special dividends, stock repurchases or sales of assets or the entire company. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting National Fuel’sthe Company’s operations and diverting the attention of National Fuel’sthe Company’s Board of Directors and senior management.management from the pursuit of business strategies. As a result, shareholder campaigns could adversely affect National Fuel’sthe Company’s results of operations and financial condition.
 
Item 1B  Unresolved Staff Comments
 
None


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Item 2  Properties
 
General Information on Facilities
 
The net investment of the Company in property, plant and equipment was $3.2$3.1 billion at September 30, 2008.2009. Approximately 62%63% of this investment was in the Utility and Pipeline and Storage segments, which are primarily located in western and central New York and northwestern Pennsylvania. The Exploration and Production segment, which has the next largest investment in net property, plant and equipment (35%(33%), is primarily located in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas Louisiana, and Alabama.Louisiana. The remaining net investment in property, plant and equipment consisted of the Timber segment (2%) which is located primarily in northwestern Pennsylvania, and All Other and Corporate operations (1%(4%). During the past five years, the Company has made additions to property, plant and equipment in order to expand and improve transmission and distribution facilities for both retail and transportation customers. Net property, plant and equipment has increased $163.1$125.3 million, or 5.5%4.2%, since 2003.2004. During 2007, the Company sold SECI, Seneca’s wholly owned subsidiary that operated in Canada. The net property, plant and equipment of SECI at the date of sale was $107.7 million. In addition, during 2005, the Company sold its majority interest in U.E., a district heating and electric generation business in the Czech Republic. The net property, plant and equipment of U.E. at the date of sale was $223.9 million.
 
The Utility segment had a net investment in property, plant and equipment of $1.1 billion at September 30, 2008.2009. The net investment in its gas distribution network (including 14,81914,837 miles of distribution pipeline) and its service connections to customers represent approximately 52% and 34%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2008.2009.
 
The Pipeline and Storage segment had a net investment of $826.5$839.4 million in property, plant and equipment at September 30, 2008.2009. Transmission pipeline represents 27%43% of this segment’s total net investment and includes 2,3712,364 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 21%20% of this segment’s total net investment and consist of 31 storage fields, four of which are jointly owned and operated with certain pipeline suppliers, and 429428 miles of pipeline. Net investment in storage facilities includes $94.8$89.7 million of gas stored underground-noncurrent, representing the cost of the gas utilized to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 2728 compressor stations with 75,10495,949 installed compressor horsepower that represent 11%10% of this segment’s total net investment in property, plant and equipment.
 
The Exploration and Production segment had a net investment in property, plant and equipment of $1.1$1.0 billion at September 30, 2008.


19

The Timber segment had a net investment in property, plant and equipment of $86.4 million at September 30, 2008. Located primarily in northwestern Pennsylvania, the net investment includes two sawmills, 103,680 acres of land and timber, and 3,122 acres of timber rights.2009.
 
The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet the Company’s 20082009 peak day sendout, including transportation service, of 1,6321,733 MMcf, which occurred on February 10, 2008.January 15, 2009. Withdrawals from storage of 768.3694.1 MMcf provided approximately 47.1%40.1% of the requirements on that day.
 
Company maps are included in exhibit 99.2 of thisForm 10-K and are incorporated herein by reference.
 
Exploration and Production Activities
 
The Company is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, in Wyoming, and in the Gulf Coast region of Texas Louisiana, and Alabama.Louisiana. Also, Exploration and Production operations were conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada, until the sale of these properties on August 31, 2007. Further discussion of the sale of the Canadian oil and gas properties is included in Item 8, Note IJ — Discontinued Operations. Further discussion of oil and gas producing activities is included in Item 8, Note OQ — Supplementary Information for Oil and Gas Producing Activities. Note OQ sets forth proved developed and undeveloped reserve information for Seneca.
Seneca’s proved developed and undeveloped natural gas reserves increased from 226 Bcf at September 30, 2008 to 249 Bcf at September 30, 2009. This increase is attributed primarily to extensions and discoveries (59.2 Bcf), primarily in the Appalachian region (49.2 Bcf). This increase was partially offset by production of


18

22.3 Bcf, negative revisions of previous estimates (9.6 Bcf) and sales of minerals in place (4.7 Bcf) in the Gulf Coast region. Seneca’s proved developed and undeveloped oil reserves increased from 46,198 Mbbl at September 30, 2008 to 46,587 Mbbl at September 30, 2009. This increase is attributed to purchases of minerals in place (2,115 Mbbl) in the West Coast region, extensions and discoveries (1,213 Mbbl), and revisions of previous estimates (449 Mbbl). These increases were largely offset by production (3,373 Mbbl), primarily occurring in the West Coast region (2,674 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 503 Bcfe at September 30, 2008 to 528 Bcfe at September 30, 2009.
Seneca’s proved developed and undeveloped natural gas reserves increased from 205 Bcf at September 30, 2007 to 226 Bcf at September 30, 2008. This increase is attributed primarily to extensions and discoveries (40.1 Bcf), primarily in the Appalachian region (31.3 Bcf). This increase was partially offset by production of 22.3 Bcf. Seneca’s proved developed and undeveloped oil reserves decreased from 47,586 Mbbl at September 30, 2007 to 46,198 Mbbl at September 30, 2008. This decrease is attributed to production (3,070 Mbbl), primarily occurring in Californiathe West Coast region (2,460 Mbbl) and sales of minerals in place (1,334 Mbbl). These decreases were partially offset by purchases of minerals in place (2,084 Mbbl) and extensions and discoveries (827 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 491 Bcfe at September 30, 2007 to 503 Bcfe at September 30, 2008. Seneca’s proved developed and undeveloped natural gas reserves decreased from 233 Bcf at September 30, 2006 to 205 Bcf at September 30, 2007. This decrease is attributed primarily to the sale of the Canadian gas properties (40.1 Bcf) and production of 26.3 Bcf. These decreases were partially offset by extensions and discoveries of 34.6 Bcf, primarily in the Appalachian region (29.7 Bcf). Seneca’s proved developed and undeveloped oil reserves decreased from 58,018 Mbbl at September 30, 2006 to 47,586 Mbbl at September 30, 2007. This decrease is attributed to revisions of previous estimates (5,963 Mbbl), primarily occurring in California, production (3,450 Mbbl) and the sale of the Canadian oil properties (1,458 Mbbl). On a Bcfe basis, Seneca’s proved developed and undeveloped reserves decreased from 581 Bcfe at September 30, 2006 to 491 Bcfe at September 30, 2007.
 
Seneca’s oil and gas reserves reported in Item 8 at Note OQ as of September 30, 20082009 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA), a statistical agency of the U.S. Department of Energy. The oil and gas reserve information reported to the EIA showed 204227 Bcf and 49,89947,630 Mbbl of gas and oil reserves, respectively, which differs from the reserve information summarized in Item 8 at Note O.Q. The reasons for this difference are as follows: (a) reserves are reported to the EIA on a calendar year basis, while reserves disclosed in Item 8 at Note OQ are shown on a fiscal year basis; (b) reserves reported to the EIA include only properties operated by Seneca, while reserves disclosed in Item 8 at Note OQ included both Seneca operated properties and non-operated properties in which Seneca has an interest; and (c) reserves are reported to the EIA on a gross basis versus the reserves disclosed in Item 8 at Note O,Q, which are reported on a net revenue interest basis.


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The following is a summary of certain oil and gas information taken from Seneca’s records. All monetary amounts are expressed in U.S. dollars.
 
Production
 
                        
 For The Year Ended September 30  For The Year Ended September 30
 2008 2007 2006  2009 2008 2007
United States
                     
Gulf Coast Region                     
Average Sales Price per Mcf of Gas $10.03  $6.58  $8.01  $4.54  $10.03  $6.58 
Average Sales Price per Barrel of Oil $107.27  $63.04  $64.10  $54.58  $107.27  $63.04 
Average Sales Price per Mcf of Gas (after hedging) $9.49  $6.87  $5.89  $5.28  $9.49  $6.87 
Average Sales Price per Barrel of Oil (after hedging) $98.56  $64.09  $47.46  $54.58  $98.56  $64.09 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.63  $1.08  $0.86  $1.53  $1.63  $1.08 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  38   40   36   38   38   40 
West Coast Region                     
Average Sales Price per Mcf of Gas $8.71  $6.54  $7.93  $3.91  $8.71  $6.54 
Average Sales Price per Barrel of Oil $98.17  $56.86  $56.80  $50.90  $98.17  $56.86 
Average Sales Price per Mcf of Gas (after hedging) $8.22  $6.82  $7.19  $7.37  $8.22  $6.82 
Average Sales Price per Barrel of Oil (after hedging) $77.64  $47.43  $37.69  $67.61  $77.64  $47.43 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $2.01  $1.54  $1.35 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  51   50   53 
Appalachian Region            
Average Sales Price per Mcf of Gas $9.73  $7.48  $9.53 
Average Sales Price per Barrel of Oil $97.40  $62.26  $65.28 
Average Sales Price per Mcf of Gas (after hedging) $8.85  $8.25  $8.90 
Average Sales Price per Barrel of Oil (after hedging) $97.40  $62.26  $65.28 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.77  $0.69  $0.69 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  22   17   15 
Total United States
            
Average Sales Price per Mcf of Gas $9.70  $6.82  $8.42 
Average Sales Price per Barrel of Oil $99.64  $58.43  $58.47 
Average Sales Price per Mcf of Gas (after hedging) $9.05  $7.25  $7.02 
Average Sales Price per Barrel of Oil (after hedging) $81.75  $51.68  $40.26 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.64  $1.23  $1.09 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  111   108   104 


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 For The Year Ended September 30  For The Year Ended September 30
 2008 2007 2006  2009 2008 2007
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.68  $2.01  $1.54 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  55   51   50 
Appalachian Region         
Average Sales Price per Mcf of Gas $5.52  $9.73  $7.48 
Average Sales Price per Barrel of Oil $56.15  $97.40  $62.26 
Average Sales Price per Mcf of Gas (after hedging) $8.69  $8.85  $8.25 
Average Sales Price per Barrel of Oil (after hedging) $56.15  $97.40  $62.26 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $0.89  $0.77  $0.69 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  24   22   17 
Total United States
         
Average Sales Price per Mcf of Gas $4.79  $9.70  $6.82 
Average Sales Price per Barrel of Oil $51.69  $99.64  $58.43 
Average Sales Price per Mcf of Gas (after hedging) $6.94  $9.05  $7.25 
Average Sales Price per Barrel of Oil (after hedging) $64.94  $81.75  $51.68 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.47  $1.64  $1.23 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  116   111   108 
Canada — Discontinued Operations
                     
Average Sales Price per Mcf of Gas $—  $6.09  $7.14  $—  $—  $6.09 
Average Sales Price per Barrel of Oil $—  $50.06  $51.40  $—  $—  $50.06 
Average Sales Price per Mcf of Gas (after hedging) $—  $6.17  $7.47  $—  $—  $6.17 
Average Sales Price per Barrel of Oil (after hedging) $—  $50.06  $51.40  $—  $—  $50.06 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $—  $1.94  $1.57  $—  $—  $1.94 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  —   21   26   —   —   21 
Total Company
                     
Average Sales Price per Mcf of Gas $9.70  $6.64  $8.04  $4.79  $9.70  $6.64 
Average Sales Price per Barrel of Oil $99.64  $57.93  $57.94  $51.69  $99.64  $57.93 
Average Sales Price per Mcf of Gas (after hedging) $9.05  $6.98  $7.15  $6.94  $9.05  $6.98 
Average Sales Price per Barrel of Oil (after hedging) $81.75  $51.58  $41.10  $64.94  $81.75  $51.58 
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $1.64  $1.35  $1.18  $1.47  $1.64  $1.35 
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)  111   129   130   116   111   129 

20

Productive Wells
 
                                                        
 Gulf Coast
 West Coast
 Appalachian
      Gulf Coast
 West Coast
 Appalachian
  
 Region Region Region Total Company  Region Region Region Total Company
At September 30, 2008
 Gas Oil Gas Oil Gas Oil Gas Oil 
At September 30, 2009
 Gas Oil Gas Oil Gas Oil Gas Oil
Productive Wells — Gross  25   42   —   1,437   2,641   6   2,666   1,485   20   42   —   1,510   2,848   6   2,868   1,558 
Productive Wells — Net  14   14   —   1,426   2,570   5   2,584   1,445   12   14   —   1,484   2,766   5   2,778   1,503 
 
Developed and Undeveloped Acreage
 
                                
 Gulf
 West
      Gulf
 West
    
 Coast
 Coast
 Appalachian
 Total
  Coast
 Coast
 Appalachian
 Total
At September 30, 2008
 Region Region Region Company 
At September 30, 2009
 Region Region Region Company
Developed Acreage                            
— Gross  113,934   11,360   531,743   657,037   113,934   15,118   532,872   661,924 
— Net  80,852   10,945   501,411   593,208   80,852   12,926   504,783   598,561 
Undeveloped Acreage                            
— Gross  142,118   —   458,894   601,012   142,118   19,002   458,182   619,302 
— Net  102,831   —   438,040   540,871   102,831   10,177   437,408   550,416 
Total Developed and Undeveloped Acreage            
— Gross  256,052   34,120   991,054   1,281,226 
— Net  183,683   23,103   942,191   1,148,977 
 
As of September 30, 2008,2009, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 38,811 acres in 2009 (23,289 net acres), 23,30234,887 acres in 2010 (11,754(16,764 net acres), 82,16590,456 acres in 2011 (67,472(70,162 net acres), 22,222 acres in 2012 (20,532 net acres), and 456,734471,737 acres thereafter (438,356(442,958 net acres).

22

Drilling Activity
 
                                          
 Productive Dry  Productive Dry
For the Year Ended September 30
 2008 2007 2006 2008 2007 2006  2009 2008 2007 2009 2008 2007
United States
                                          
Gulf Coast Region                                          
Net Wells Completed                                          
— Exploratory  1.14   1.31   2.94   0.37   1.42   0.85   0.29   1.14   1.31   —   0.37   1.42 
— Development  —   1.00   0.78   —   0.67   —   —   —   1.00   0.30   —   0.67 
West Coast Region                                          
Net Wells Completed                                          
— Exploratory  1.00   0.50   —   —   —   —   —   1.00   0.50   —   —   — 
— Development  62.00   58.99   92.98   1.00   2.00   1.00   27.00   62.00   58.99   —   1.00   2.00 
Appalachian Region                                          
Net Wells Completed                                          
— Exploratory  8.00   8.10   3.88   1.00   —   —   2.00   8.00   8.10   3.00   1.00   — 
— Development  186.00   184.00   140.58   —   2.00   1.75   250.00   186.00   184.00   —   —   2.00 
Total United States                                          
Net Wells Completed                                          
— Exploratory  10.14   9.91   6.82   1.37   1.42   0.85   2.29   10.14   9.91   3.00   1.37   1.42 
— Development  248.00   243.99   234.34   1.00   4.67   2.75   277.00   248.00   243.99   0.30   1.00   4.67 
Canada — Discontinued Operations
                                          
Net Wells Completed                                          
— Exploratory  —   6.38   12.60   —   —   1.35   —   —   6.38   —   —   — 
— Development  —   1.80   2.50   —   —   1.00   —   —   1.80   —   —   — 
Total
                                          
Net Wells Completed                                          
— Exploratory  10.14   16.29   19.42   1.37   1.42   2.20   2.29   10.14   16.29   3.00   1.37   1.42 
— Development  248.00   245.79   236.84   1.00   4.67   3.75   277.00   248.00   245.79   0.30   1.00   4.67 


21

Present Activities
 
                                
 Gulf
 West
      Gulf
 West
    
 Coast
 Coast
 Appalachian
 Total
  Coast
 Coast
 Appalachian
 Total
At September 30, 2008
 Region Region Region Company 
At September 30, 2009
 Region Region Region Company
Wells in Process of Drilling(1)                            
— Gross  2.00   1.00   148.00   151.00   —   —   118.00   118.00 
— Net  0.59   1.00   146.00   147.59   —   —   108.50   108.50 
 
 
(1)Includes wells awaiting completion.
 
Item 3  Legal Proceedings
 
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note HI — Commitments and Contingencies. In addition to these matters, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are


23

resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
 
Item 4  Submission of Matters to a Vote of Security Holders
 
No matter was submitted to a vote of security holders during the quarter ended September 30, 2008.2009.
 
PART II
 
Item 5  Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 8 at Note E — Capitalization and Short-Term Borrowings and Note NP — Market for Common Stock and Related Shareholder Matters (unaudited).
 
On July 2, 2008,1, 2009, the Company issued a total of 2,4002,800 unregistered shares of Company common stock to the eightseven non-employee directors of the Company then serving on the Board of Directors of the Company and receiving compensation under the Company’s Retainer Policy for Non-Employee Directors, 300400 shares to each such director. On September 30, 2009, the Company issued 65 unregistered shares of Company common stock to Frederic V. Salerno, a non-employee director of the Company, under the Company’s Retainer Policy for Non-Employee Directors. All of these unregistered shares were issued as partial consideration for such directors’ services during the quarter ended September 30, 2008.2009. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.


22

Issuer Purchases of Equity Securities
 
                 
        Total Number
  Maximum Number
 
        of Shares
  of Shares
 
        Purchased as
  that May
 
        Part of
  Yet Be
 
        Publicly Announced
  Purchased Under
 
  Total Number
  Average Price
  Share Repurchase
  Share Repurchase
 
  of Shares
  Paid per
  Plans or
  Plans or
 
Period
 Purchased(a)  Share  Programs  Programs(b) 
 
July 1-31, 2008  6,404  $54.02   —   1,332,725 
Aug. 1-31, 2008  544,982  $46.72   537,165   795,560 
Sept. 1-30, 2008  1,832,488  $45.08   1,824,541   6,971,019 
                 
Total  2,383,874  $45.48   2,361,706   6,971,019 
                 
                 
        Total Number
  Maximum Number
 
        of Shares
  of Shares
 
        Purchased as
  that May
 
        Part of
  Yet Be
 
        Publicly Announced
  Purchased Under
 
  Total Number
  Average Price
  Share Repurchase
  Share Repurchase
 
  of Shares
  Paid per
  Plans or
  Plans or
 
Period
 Purchased(a)  Share  Programs  Programs(b) 
 
July 1-31, 2009  9,709  $37.77   —   6,971,019 
Aug. 1-31, 2009  10,919  $44.52   —   6,971,019 
Sept. 1-30, 2009  8,269  $45.98   —   6,971,019 
                 
Total  28,897  $42.67   —   6,971,019 
                 
 
 
(a)Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes, and (iii)taxes. During the quarter ended September 30, 2009, the Company did not purchase any shares of its common stock of the Company purchased on the open market pursuant to the Company’sits publicly announced share repurchase program. SharesOf the 28,897 shares purchased other than through a publicly announced share repurchase program, totaled 6,404 in July 2008, 7,817 in August 2008 and 7,947 in September 2008 (a three-month total of 22,168). All of those shares26,682 were purchased for the Company’s 401(k) plans.plans and 2,215 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.
 
(b)In December 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. The Company completed the repurchase of the eight million shares during 2008. In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares of the Company’s common stock. The Company, had, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, such repurchases may be made in the future, if conditions improve. Such repurchases would be madeeither in the open market or through private transactions.


2423

 
Item 6  Selected Financial Data
 
                                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006 2005 2004  2009 2008 2007 2006 2005 
 (Thousands)  (Thousands) 
Summary of Operations
                                        
Operating Revenues $2,400,361  $2,039,566  $2,239,675  $1,860,774  $1,867,875  $2,057,852  $2,400,361  $2,039,566  $2,239,675  $1,860,774 
                      
Operating Expenses:                                        
Purchased Gas  1,235,157   1,018,081   1,267,562   959,827   949,452   1,001,782   1,235,157   1,018,081   1,267,562   959,827 
Operation and Maintenance  432,871   396,408   395,289   388,094   374,010   402,856   432,871   396,408   395,289   388,094 
Property, Franchise and Other Taxes  75,585   70,660   69,202   68,164   68,378   72,163   75,585   70,660   69,202   68,164 
Depreciation, Depletion and Amortization  170,623   157,919   151,999   156,502   159,184   173,410   170,623   157,919   151,999   156,502 
Impairment of Oil and Gas Producing Properties  182,811   —   —   —   — 
                      
  1,914,236   1,643,068   1,884,052   1,572,587   1,551,024   1,833,022   1,914,236   1,643,068   1,884,052   1,572,587 
Loss on Sale of Timber Properties  —   —   —   —   (1,252)
                      
Operating Income  486,125   396,498   355,623   288,187   315,599   224,830   486,125   396,498   355,623   288,187 
Other Income (Expense):                                        
Income from Unconsolidated Subsidiaries  6,303   4,979   3,583   3,362   805   3,366   6,303   4,979   3,583   3,362 
Impairment of Investment in Partnership  —   —   —   (4,158)  —   (1,804)  —   —   —   (4,158)
Other Income  6,576   7,376   4,936   2,825   12,744 
Interest Income  10,815   1,550   9,409   6,236   1,771   5,776   10,815   1,550   9,409   6,236 
Other Income  7,376   4,936   2,825   12,744   2,908 
Interest Expense on Long-Term Debt  (70,099)  (68,446)  (72,629)  (73,244)  (82,989)  (79,419)  (70,099)  (68,446)  (72,629)  (73,244)
Other Interest Expense  (3,870)  (6,029)  (5,952)  (9,069)  (6,354)  (7,497)  (3,870)  (6,029)  (5,952)  (9,069)
                      
Income from Continuing Operations Before Income Taxes  436,650   333,488   292,859   224,058   231,740   151,828   436,650   333,488   292,859   224,058 
Income Tax Expense  167,922   131,813   108,245   85,621   89,820   51,120   167,922   131,813   108,245   85,621 
                      
Income from Continuing Operations  268,728   201,675   184,614   138,437   141,920   100,708   268,728   201,675   184,614   138,437 
                      
Discontinued Operations:                                        
Income (Loss) from Operations, Net of Tax  —   15,479   (46,523)  25,277   24,666   —   —   15,479   (46,523)  25,277 
Gain on Disposal, Net of Tax  —   120,301   —   25,774   —   —   —   120,301   —   25,774 
                      
Income (Loss) from Discontinued Operations, Net of Tax  —   135,780   (46,523)  51,051   24,666   —   —   135,780   (46,523)  51,051 
                      
Net Income Available for Common Stock $268,728  $337,455  $138,091  $189,488  $166,586  $100,708  $268,728  $337,455  $138,091  $189,488 
                      


2524

                                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006 2005 2004  2009 2008 2007 2006 2005 
 (Thousands)  (Thousands) 
Per Common Share Data
                                        
Basic Earnings from Continuing Operations per Common Share $3.27  $2.43  $2.20  $1.66  $1.73  $1.26  $3.27  $2.43  $2.20  $1.66 
Diluted Earnings from Continuing Operations per Common Share $3.18  $2.37  $2.15  $1.63  $1.71  $1.25  $3.18  $2.37  $2.15  $1.63 
Basic Earnings per Common Share(1) $3.27  $4.06  $1.64  $2.27  $2.03  $1.26  $3.27  $4.06  $1.64  $2.27 
Diluted Earnings per Common Share(1) $3.18  $3.96  $1.61  $2.23  $2.01  $1.25  $3.18  $3.96  $1.61  $2.23 
Dividends Declared $1.27  $1.22  $1.18  $1.14  $1.10  $1.32  $1.27  $1.22  $1.18  $1.14 
Dividends Paid $1.26  $1.21  $1.17  $1.13  $1.09  $1.31  $1.26  $1.21  $1.17  $1.13 
Dividend Rate at Year-End $1.30  $1.24  $1.20  $1.16  $1.12  $1.34  $1.30  $1.24  $1.20  $1.16 
At September 30:                                        
Number of Registered Shareholders
  16,544   16,989   17,767   18,369   19,063   16,098   16,544   16,989   17,767   18,369 
                      
Net Property, Plant and Equipment
                                        
Utility $1,125,859  $1,099,280  $1,084,080  $1,064,588  $1,048,428  $1,144,002  $1,125,859  $1,099,280  $1,084,080  $1,064,588 
Pipeline and Storage  826,528   681,940   674,175   680,574   696,487   839,424   826,528   681,940   674,175   680,574 
Exploration and Production(2)  1,095,960   982,698   1,002,265   974,806   923,730   1,041,846   1,095,960   982,698   1,002,265   974,806 
Energy Marketing  98   102   59   97   80   71   98   102   59   97 
Timber  86,392   89,902   90,939   94,826   82,838 
All Other  11,946   16,735   17,394   18,098   21,172   99,787   98,338   106,637   108,333   112,924 
Corporate(3)  7,317   7,748   8,814   6,311   234,029 
Corporate  6,915   7,317   7,748   8,814   6,311 
                      
Total Net Plant $3,154,100  $2,878,405  $2,877,726  $2,839,300  $3,006,764  $3,132,045  $3,154,100  $2,878,405  $2,877,726  $2,839,300 
                      
Total Assets
 $4,130,187  $3,888,412  $3,763,748  $3,749,753  $3,738,103  $4,769,129  $4,130,187  $3,888,412  $3,763,748  $3,749,753 
                      
Capitalization
                                        
Comprehensive Shareholders’ Equity $1,603,599  $1,630,119  $1,443,562  $1,229,583  $1,253,701  $1,589,236  $1,603,599  $1,630,119  $1,443,562  $1,229,583 
Long-Term Debt, Net of Current Portion  999,000   799,000   1,095,675   1,119,012   1,133,317   1,249,000   999,000   799,000   1,095,675   1,119,012 
                      
Total Capitalization $2,602,599  $2,429,119  $2,539,237  $2,348,595  $2,387,018  $2,838,236  $2,602,599  $2,429,119  $2,539,237  $2,348,595 
                      
 
 
(1)Includes discontinued operations.
 
(2)Includes net plant of SECI discontinued operations as follows: $0 for 2009, 2008 and 2007, $88,023 for 2006, and $170,929 for 2005, and $142,860 for 2004.
(3)Includes net plant of the former international segment as follows: $29 for 2008, $38 for 2007, $27 for 2006, $20 for 2005, and $227,905 for 2004.2005.

26

 
Item 7  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
OVERVIEW
 
The Company is a diversified energy company and reports financial results for fivefour business segments. Refer to Item 1, Business, for a more detailed description of each of the segments. This Item 7, MD&A, provides information concerning:
 
 1. The critical accounting estimates of the Company;
 
 2. Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
 
 3. Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity;”
 
 4. Off-Balance Sheet Arrangements;

25

 5. Contractual Obligations; and
 
 6. Other Matters, including: (a) 20082009 and 2009projected 2010 funding for the Company’s pension and other post-retirement benefits, (b) realizability of deferred tax assets (c) disclosures and tables concerning market risk sensitive instruments, (d) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC regulated jurisdictions, (e) environmental matters, and (f) new authoritative accounting pronouncements.and financial reporting guidance.
 
The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.
 
Overall,For the year ended September 30, 2009 compared to the year ended September 30, 2008, the Company experienced a decrease in earnings of $168.0 million, primarily due to lower earnings in the Exploration and Production segment. The earnings decrease was a strong year for the Company. Income from continuing operations in 2008 benefited primarily from higher crude oil and natural gas pricesdriven largely by an impairment charge of $182.8 million ($108.2 million after tax) recorded in the Exploration and Production segment, combinedalong with an overall increase inreduced crude oil and natural gas production, primarily inprices. In the Appalachian region. These factors led to a $67.1 million increase in income from continuing operations compared to the prior year. In 2007, the Company recorded $135.8 million of income from discontinued operations, consisting of a $120.3 million gain, net of tax, on the sale of SECI and $15.5 million of income from SECI prior to its sale in August 2007. SECI, Seneca’s wholly owned subsidiary, was engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. Combining both income from continuing operations and discontinued operations, the Company’s net income available for common stock decreased $68.7 million in 2008 compared to the prior year. The Company’s earnings are discussed further in the Results of Operations section that follows.
The Company spent $414.5 million on capital expenditures during 2008, with approximately 46 percent being spent in the Exploration and Production segment, oil and 40 percent being spent in the Pipeline and Storage segment. Management continues to believe that these segments provide the best earnings growth opportunities for shareholders. In the Exploration and Production segment, the Company’s principal focus continues to be the development of its nearly one million acres in the Appalachian region along with continuedgas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Such costs are subject to a quarterly ceiling test prescribed by SECRegulation S-XRule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. At December 31, 2008, due to significant declines in crude oil and natural gas commodity prices (Cushing, Oklahoma West Texas Intermediate oil reported spot price of $44.60 per Bbl at December 31, 2008 versus a reported price of $100.70 per Bbl at September 30, 2008; Henry Hub natural gas reported spot price of $5.63 per MMBtu at December 31, 2008 versus a reported price of $7.12 per MMBtu at September 30, 2008), the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the Gulf and West Coast regions. In the Pipeline and Storage segment, the majorityimpairment charge mentioned above. (Note — Because actual pricing of the expenditures wereCompany’s various producing properties varies depending on their location, the actual various prices received for construction costssuch production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative of current prices.) At September 30, 2009, the quoted Cushing, Oklahoma spot price for West Texas Intermediate oil was $70.46 per Bbl ($69.82 per Bbl at June 30, 2009 and $49.64 per Bbl at March 31, 2009) and the quoted spot price for natural gas was $3.30 per MMBtu ($3.88 per MMBtu at June 30, 2009 and $3.63 per MMBtu at March 31, 2009). At September 30, 2009, the ceiling exceeded the book value of the Empire Connector project. The Empire Connector is anticipated to be ready to commence serviceCompany’s oil and gas properties by approximately $212 million (and approximately $247 million and $37 million at June 30, 2009 and March 31, 2009, respectively). If natural gas prices used in December 2008 on or before the in-service dateceiling test calculation at September 30, 2009 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Millennium Pipeline. The Company’s capital expenditure program is discussed furtheroil and gas properties by approximately $165 million. If crude oil prices used in the Capital Resourcesceiling test calculation at September 30, 2009 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and Liquidity section that follows.gas properties by approximately $160 million. If both natural gas and crude oil prices used in the ceiling test calculation at September 30, 2009 were lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $113 million. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation.
 
Despite the positives mentioneddecrease in earnings discussed above, the economyCompany’s balance sheet consisted of the United Statesa capitalization structure of 56% equity and 44% debt at September 30, 2009. With its April 2009 issuance of $250.0 million of 8.75% notes due in May 2019, management believes that it has become constrained by significant volatility and turmoilenhanced its liquidity position at a time when there is still uncertainty in the capital and credit markets. The government’s Troubled Asset Relief Program and decreases in federal funds rates have not been enough to stem the reluctance on the part of lenders to extend credit to businesses. In the current period these events have not had a material impact on the Company, although further disruption in the markets and tightening of credit availability could negatively impact future periods. At September 30, 2008,2009, the Company had a strong balance sheet and liquidity. The Company had no outstandingdid not have any short-term notes payable to banks or commercial paper at that date.borrowings outstanding. However, since that date, the Company has borrowed short-term funds under its credit lines and through the commercial paper marketcontinues to fund working capital needs. The Company maintainsmaintain a number of individual uncommitted or


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discretionary lines of credit with certain financial institutions for general corporate purposes. These credit lines, which aggregate to $420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million, thatwhich commitment extends through September 30, 2010.


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During 2006,The Company’s liquidity position will become increasingly important over the next three years. The Company anticipates spending $413 million for capital expenditures in 2010. In addition, the Company began repurchasing outstanding shareshas identified possible additional projects where capital expenditures could amount to $723 million in 2011 and $816 million in 2012. The majority of common stock underthese expenditures have been targeted for the Exploration and Production segment, where the Company anticipates spending $255 million in 2010 ($224 million in Appalachia). Depending on drilling success in 2010, commodity pricing, and, subject to approval of the Company’s Board of Directors, spending could reach $417 million in 2011 ($385 million in Appalachia), and $497 million in 2012 ($444 million in Appalachia). The significant rise in estimated capital expenditures in the Exploration and Production segment, specifically in the Appalachian region, can be attributed to a share repurchase program authorized bystrong emphasis on developing natural gas properties in the Marcellus Shale. The emphasis on Marcellus Shale development will carry over into the Pipeline and Storage segment, which is anticipating the need for additional pipeline and storage capacity as Marcellus Shale production comes on line. Pipeline and Storage segment capital expenditures are anticipated to be $51 million in 2010, with opportunities to spend up to $227 million in 2011 and $240 million in 2012, depending on market acceptance of the proposed projects, contractual commitments from shippers, and approval from the Company’s Board of Directors. The program authorizedprojects being considered in the Company to repurchase up to an aggregate amountPipeline and Storage segment are discussed in detail in the Investing Cash Flow section of eight million shares. This threshold was reached during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008.Capital Resources and Liquidity section that follows. The Company stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, such repurchases may be made in the future if conditions improve.
During 2009, the Company expects to finance itsanticipates financing these capital expenditure program, dividends, and operating expenses (including Retirement Plan and other post-retirement benefit funding)expenditures with cash from operations, proceeds from the sale of assets,and/or short-term borrowings. As oil and gas commodity prices have decreased significantly from their highs during 2008, it is possible that the Company may have to rely more heavily on short-term borrowings to meet its cash needs. It is also possible that the Company may choose to reduce its 2009 capital expenditures.and long-term debt.
 
With the turmoil in the credit markets has come a significant decline in the stock markets. This has had a significant impact on the asset values of the Company’s Retirement Plan and its VEBA trusts and 401(h) accounts. The Company anticipates funding $15.0 million to $20.0 million to the Retirement Plan and $25.0 million to $30.0 million to its VEBA trusts and 401(h) accounts during 2009. However, under the current funding requirements of the Pension Protection Act, should market conditions at September 30, 2008 remain unchanged, contributions in future years could increase significantly. This issue is discussed further in the Other Matters section that follows.
CRITICAL ACCOUNTING ESTIMATES
 
The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements 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. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
 
Oil and Gas Exploration and Development Costs.  In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.


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The Company believes that determining the amount of the Company’s proved reserves is a critical accounting estimate. Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on aunits-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.


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In addition to depletion under theunits-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SECRegulation S-XRule 4-10. The ceiling test , which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. Because of the decline in the price of natural gas during the third and fourth quarters of 2006, the book value of the Company’s Canadian oil and gas properties exceeded the ceiling at both June 30, 2006 and September 30, 2006. Consequently, SECI recorded impairment charges of $62.4 million ($39.5 million after-tax) in the third quarter of 2006 and $42.3 million ($29.1 million after-tax) in the fourth quarter of 2006. These impairment charges are included in the loss from discontinued operations for 2006 due to the sale of SECI during 2007. At September 30, 2008, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $500 million. DeclinesBecause of declines in commodity prices since that date have reducedsubsequent to September 30, 2008, the ceiling. Using more upbook value of the Company’s oil and gas properties exceeded the ceiling at December 31, 2008. The quoted Cushing, Oklahoma spot price for West Texas Intermediate oil had declined from a reported price of $100.70 per Bbl at September 30, 2008 to date pricinga reported price of $6$44.60 per McfBbl at December 31, 2008. The quoted Henry Hub spot price for natural gas and $60had declined from a reported price of $7.12 per barrel for crude oil, the ceilingMMBtu at September 30, 2008 to a reported price of $5.63 per MMBtu at December 31, 2008. Consequently, the Company recorded an impairment charge of $182.8 million ($108.2 million after-tax) during the quarter ended December 31, 2008. (Note — Because actual pricing of the Company’s various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative of current prices.) At September 30, 2009, the quoted Cushing, Oklahoma spot price for West Texas Intermediate oil was $70.46 per Bbl ($69.82 per Bbl at June 30, 2009 and $49.64 per Bbl at March 31, 2009) and the quoted spot price for natural gas was $3.30 per MMBtu ($3.88 per MMBtu at June 30, 2009 and $3.63 per MMBtu at March 31, 2009). At September 30, 2009, the ceiling exceeded the book value of the Company’s oil and gas properties by approximately $212 million (and approximately $247 million and $37 million at June 30, 2009 and March 31, 2009, respectively). If natural gas prices used in the ceiling test calculation at September 30, 2009 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $80$165 million. If crude oil prices used in the ceiling test calculation at September 30, 2009 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $160 million. If both natural gas and crude oil prices used in the ceiling test calculation at September 30, 2009 were lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $113 million. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation.
 
It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
 
UponIn accordance with the adoption of SFAS 143 on October 1, 2002,current authoritative guidance for asset retirement obligations, the Company recordedrecords an asset retirement obligation representingfor plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalizedcapitalizes such costs in property, plant and equipment (i.e. the full cost pool). Prior toUnder the adoption of SFAS 143,current authoritative guidance for asset retirement obligations, since plugging and abandonment costs were accounted for solely through the Company’s units-of-production depletion calculation. An estimate of such costs was added to the depletion base, which alsoare already included capitalized costs in the full cost pool, and estimated future expenditures to be incurred in developing proved reserves. With the adoption of SFAS 143, plugging and abandonment costs are alreadyunits-of-production depletion calculation


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included in capitalized costs and the units-of-production depletion calculation has been modified to excludeexcludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
 
PriorAs discussed above, the full cost method of accounting provides a ceiling to the adoptionamount of SFAS 143,costs that can be capitalized in calculatingthe full cost pool. In accordance with current authoritative guidance, since the full cost pool includes an amount associated with plugging and abandoning the wells, as discussed in the preceding paragraph, the calculation of the full cost ceiling the Company reducedno longer reduces the future net cash flows from proved oil and gas reserves by the estimated plugging and abandonment costs. Such future net cash flows would then be compared to capitalized costs in the full cost pool, with any excess capitalized costs being expensed. With the adoptionan estimate of SFAS 143, since the full cost pool now includes an amount associated with plugging and abandoning the wells, the calculation of the full cost ceiling has been changed so that future net cash flows from proved oil and gas reserves are no longer reduced by the estimated plugging and abandonment costs.
 
Regulation.  The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to SFAS 71,the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows the Company to defer expenses and income on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the ratesetting process in a period different from the period in which they would have been reflected in the income statement 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. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its 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 the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note C — Regulatory Matters.
 
Accounting for Derivative Financial Instruments.  The Company, in its Exploration and Production segment, Energy Marketing segment, and Pipeline and Storage segment, and All Other category, uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments are categorized as price swap agreements no cost collars and futures contracts. The Company, in its Pipeline and Storage segment, previously used an interest rate collar to limit interest rate fluctuations on certain variable rate debt. In accordance with the provisions of SFAS 133,authoritative guidance for derivative instruments and hedging activities, the Company accounted for these instruments as effective cash flow hedges or fair value hedges. In 2007, the Company discontinued hedge accounting for the interest rate collar, which resulted in a gain being recognized. Gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective based on the effectiveness testing,mark-to-market gains or losses from the derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction.
 
The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The Company adopted the authoritative guidance for fair valuesvalue measurements during the quarter ended December 31, 2008. As such, the fair value of such derivative financial instruments is determined under the provisions of this guidance. The fair value of exchange traded derivative financial instruments is determined from Level 1 inputs, which are quoted prices in active markets. The Company determines the fair value of non exchange-traded derivative financial instruments are based on valuations determinedan internal model, which uses both observable and unobservable inputs other than quoted prices. These inputs are considered Level 2 or Level 3 inputs. All derivative financial instrument assets and liabilities are evaluated for the probability of default by either the counterparties. The Company used a model to substantiatecounterparty or the values reported by the counterparties. At September 30, 2008, the Company established a credit reserve of $0.6 millionCompany. Credit reserves are applied against the asset recorded on its books for non-exchange traded derivative financial instruments. The credit reserve was determined by applying default probabilities to the anticipated cash flows that the Company is expecting from its counterparties.fair values of such assets or liabilities. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments.
 
Pension and Other Post-Retirement Benefits.  The amounts reported in the Company’s financial statements related to its pension and other post-retirement benefits are determined on an actuarial basis, which uses many assumptions in the calculation of such amounts. These assumptions include the discount rate, the expected


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return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected


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annual rate of increase in per capita cost of covered medical and prescription benefits. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. The expected return on plan assets assumption used by the Company reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. Changes in actuarial assumptions and actuarial experience, including deviations between actual versus expected return on plan assets, could have a material impact on the amount of pension and post-retirement benefit costs and funding requirements experienced by the Company. However, the Company expects to recover substantially all of its net periodic pension and other post-retirement benefit costs attributable to employees in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate, as discussed above under “Regulation.” Pension and post-retirement benefit costs for the Utility and Pipeline and Storage segments, as determined under the authoritative guidance for pensions and postretirement benefits, represented 97% and 93%, respectively,90% of the Company’s total pension and post-retirement benefit costs as determined under SFAS 87 and SFAS 106 for the years ended September 30, 20082009 and 2007.2008.
 
Changes in actuarial assumptions and actuarial experience could also have an impact on the benefit obligation and the funded status related to the Company’s pension and other post-retirement benefits and could impact the Company’s equity. For example, the discount rate was changed from 6.25% in 2007 to 6.75% in 2008.2008 to 5.50% in 2009. The change in the discount rate from 20072008 to 2008 reduced2009 increased the Retirement Plan projected benefit obligation by $38.6$102.6 million and the accumulated post-retirement benefit obligation by $26.3$60.9 million. Other examples include actual versus expected return on plan assets, which has an impact on the funded status of the plans, and actual versus expected benefit payments, which has an impact on the pension plan projected benefit obligation and the accumulated post-retirement benefit obligation. For 2008,2009, actual versus expected return on plan assets resulted in a decrease to the funded status of the Retirement Plan ($94.2157.5 million) and the VEBA trusts and 401(h) accounts ($77.294.0 million). The actual versus expected benefit payments for 20082009 caused an increase of $0.1 million to the projected benefit obligation and a decrease of $3.6$2.2 million to the accumulated post-retirement benefit obligation, respectively.obligation. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants is 119 years for the Retirement Plan and 138 years for those eligible for other post-retirement benefits. For further discussion of the Company’s pension and other post-retirement benefits, refer to Other Matters in this Item 7, which includes a discussion of funding for the current year and the adoption of SFAS 158,FASB revised accounting guidance for defined benefit pensions and other postretirement plans, and to Item 8 at Note GH — Retirement Plan and Other Post Retirement Benefits.


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RESULTS OF OPERATIONS
 
EARNINGS
2009 Compared with 2008
The Company’s earnings were $100.7 million in 2009 compared with earnings of $268.7 million in 2008. The decrease in earnings of $168.0 million is primarily the result of lower earnings in the Exploration and Production, Pipeline and Storage and Utility segments and the All Other category, slightly offset by a lower loss in the Corporate category and higher earnings in the Energy Marketing segment, as shown in the table below. In the discussion that follows, note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by several events in 2009 and 2008, including:
2009 Events
• A non-cash $182.8 million impairment charge ($108.2 million after tax) recorded during the quarter ended December 31, 2008 for the Exploration and Production segment’s oil and gas producing properties;
• A $2.8 million impairment in the value of certain landfill gas assets in the All Other category;
• A $1.1 million impairment in the value of the Company’s 50% investment in ESNE (recorded in the All Other category), a limited liability company that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania; and
• A $2.3 million death benefit gain on life insurance policies recognized in the Corporate category.
2008 Event
• A $0.6 million gain in the All Other category associated with the sale of Horizon Power’s gas-powered turbine.
 
2008 Compared with 2007
 
The Company’s earnings were $268.7 million in 2008 compared with earnings of $337.5 million in 2007. As previously discussed, the Company presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as discontinued operations. The Company’s earnings from continuing operations were $268.7 million in 2008 compared with $201.7 million in 2007. The Company’s earnings from discontinued operations were $135.8 million in 2007. The increase in earnings from continuing operations is primarily the result of higher earnings in the Exploration and Production and Utility segments and the All Other category, slightly offset by lower earnings in the Corporate category and the Timber, Pipeline and Storage and Energy Marketing segments, as shown in the table below. In the discussion that follows, note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings from continuing operations and discontinued operations were impacted by several events inthe 2008 event discussed above and the following 2007 including:events:
2008 Events
• A $0.6 million gain in the All Other category associated with the sale of Horizon Power’s gas-powered turbine;
 
2007 Events
 
 • A $120.3 million gain on the sale of SECI, which was completed in August 2007. This amount is included in earnings from discontinued operations;
 
 • A $4.8 million benefit to earnings in the Pipeline and Storage segment due to the reversal of a reserve established for all costs incurred related to the Empire Connector project recognized during June 2007;
 
 • A $1.9 million benefit to earnings in the Pipeline and Storage segment associated with the discontinuance of hedge accounting for Empire’s interest rate collar; and
 
 • A $2.3 million benefit to earnings in the Energy Marketing segment related to the resolution of a purchased gas contingency.
2007 Compared with 2006
The Company’s earnings were $337.5 million in 2007 compared with earnings of $138.1 million in 2006. As previously discussed, the Company has presented its Canadian operations in the Exploration and Production segment (in conjunction with the sale of SECI) as discontinued operations. The Company’s earnings from continuing operations were $201.7 million in 2007 compared with $184.6 million in 2006. The Company’s earnings from discontinued operations were $135.8 million in 2007 compared with a loss of $46.5 million in 2006. The increase in earnings from continuing operations of $17.1 million is primarily the result of higher earnings in the Exploration and Production, Utility, Pipeline and Storage, and Energy Marketing segments and the Corporate and All Other categories, slightly offset by lower earnings in the Timber segment, as shown in the table below. The increase in earnings from discontinued operations primarily resulted from the gain on the sale of SECI recognized in 2007 as well as the non-recurrence of $68.6 million of impairment charges recognized in 2006 related to the Exploration and Production segment’s Canadian oil and gas assets. Earnings from continuing operations and discontinued operations were impacted by several events discussed above and the following 2006 events:


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2006 Events
• $68.6 million of impairment charges related to the Exploration and Production segment’s Canadian oil and gas assets under the full cost method of accounting using natural gas pricing at June 30, 2006 and September 30, 2006;
• An $11.2 million benefit to earnings in the Exploration and Production segment ($6.1 million in continuing operations and $5.1 million in discontinued operations) related to income tax adjustments recognized during 2006; and
• A $2.6 million benefit to earnings in the Utility segment related to the correction of Distribution Corporation’s calculation of the symmetrical sharing component of New York’s gas adjustment rate.
Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.
 
Earnings (Loss) by Segment
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands)  (Thousands) 
Utility $61,472  $50,886  $49,815  $58,664  $61,472  $50,886 
Pipeline and Storage  54,148   56,386   55,633   47,358   54,148   56,386 
Exploration and Production  146,612   74,889   67,494   (10,238)  146,612   74,889 
Energy Marketing  5,889   7,663   5,798   7,166   5,889   7,663 
Timber  107   3,728   5,704 
              
Total Reported Segments  268,228   193,552   184,444   102,950   268,121   189,824 
All Other  5,672   2,564   359   (2,071)  5,779   6,292 
Corporate  (5,172)  5,559   (189)  (171)  (5,172)  5,559 
              
Total Earnings from Continuing Operations  268,728   201,675   184,614   100,708   268,728   201,675 
Earnings (Loss) from Discontinued Operations  —   135,780   (46,523)
Earnings from Discontinued Operations  —   —   135,780 
              
Total Consolidated $268,728  $337,455  $138,091  $100,708  $268,728  $337,455 
              
 
UTILITY
 
Revenues
 
Utility Operating Revenues
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands)  (Thousands) 
Retail Revenues:                        
Residential $876,677  $848,693  $993,928  $850,088  $876,677  $848,693 
Commercial  135,361   136,863   166,779   128,520   135,361   136,863 
Industrial  7,419   8,271   13,484   7,213   7,419   8,271 
              
  1,019,457   993,827   1,174,191   985,821   1,019,457   993,827 
              
Off-System Sales  58,225   9,751   —   3,740   58,225   9,751 
Transportation  113,901   102,534   92,569   111,483   113,901   102,534 
Other  18,686   14,612   14,003   11,980   18,686   14,612 
              
 $1,210,269  $1,120,724  $1,280,763  $1,113,024  $1,210,269  $1,120,724 
              


33

Utility Throughput — million cubic feet (MMcf)
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
Retail Sales:                        
Residential  57,463   60,236   59,443   58,835   57,463   60,236 
Commercial  9,769   10,713   10,681   9,551   9,769   10,713 
Industrial  552   727   985   515   552   727 
              
  67,784   71,676   71,109   68,901   67,784   71,676 
              
Off-System Sales  5,686   1,355   —   513   5,686   1,355 
Transportation  64,267   62,240   57,950   59,751   64,267   62,240 
              
  137,737   135,271   129,059   129,165   137,737   135,271 
              


32

Degree Days
 
                                        
       Percent (Warmer)
        Percent (Warmer)
       Colder Than        Colder Than
Year Ended September 30
   Normal Actual Normal Prior Year    Normal Actual Normal Prior Year
2009:  Buffalo   6,692   6,701   0.1%  6.8%
  Erie   6,243   6,176   (1.1)%  6.9%
2008:  Buffalo   6,729   6,277   (6.7)%  0.1%  Buffalo   6,729   6,277   (6.7)%  0.1%
  Erie   6,277   5,779   (7.9)%  (3.8)%  Erie   6,277   5,779   (7.9)%  (3.8)%
2007:  Buffalo   6,692   6,271   (6.3)%  5.1%  Buffalo   6,692   6,271   (6.3)%  5.1%
  Erie   6,243   6,007   (3.8)%  5.6%  Erie   6,243   6,007   (3.8)%  5.6%
2006:  Buffalo   6,692   5,968   (10.8)%  (9.4)%
  Erie   6,243   5,688   (8.9)%  (8.9)%
 
2009 Compared with 2008
Operating revenues for the Utility segment decreased $97.2 million in 2009 compared with 2008. This decrease largely resulted from a $54.5 million decrease in off-system sales revenue (see discussion below), a $33.6 million decrease in retail gas sales revenues, a $2.4 million decrease in transportation revenues, and a $6.7 million decrease in other operating revenues.
The decrease in retail gas sales revenues of $33.6 million was largely a function of the recovery of lower gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues). The recovery of lower gas costs resulted from a much lower cost of purchased gas. See further discussion of purchased gas below under the heading “Purchased Gas.” The decrease in transportation revenues of $2.4 million was primarily due to a 4.5 Bcf decrease in transportation throughput, largely the result of customer conservation efforts and the poor economy.
In the New York jurisdiction, the NYPSC issued an order providing for an annual rate increase of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was adopted that shifts a greater amount of cost recovery into the minimum bill amount, thus spreading the recovery of such costs more evenly throughout the year. As a result of this rate order, retail and transportation revenues for 2009 were $2.2 million lower than revenues for 2008.
The Utility segment had off-system sales revenues of $3.7 million and $58.2 million for 2009 and 2008, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins in 2009 and 2008. The decrease in off-system sales revenue stems from Order No. 717 (“Final Rule”), which was issued by the FERC on October 16, 2008. The Final Rule seemingly held that a local distribution company making off-system sales on unaffiliated pipelines would be engaging in “marketing” that would require compliance with the FERC’s standards of conduct. Accordingly, pending clarification of this issue from the FERC, as of November 1, 2008, Distribution Corporation ceased off-system sales activities. On October 15, 2009, the FERC released OrderNo. 717-A, which clarified that a local distribution company making off-system sales of gas that has been transported on non-affiliated pipelines is not subject to the standards of conduct. In light of and in reliance on this clarification, Distribution Corporation determined that it may resume engaging in off-system sales on non-affiliated pipelines. Such off-system sales resumed in November 2009.
The decrease in other operating revenues of $6.7 million is largely related to amounts recorded in 2008 pursuant to rate settlements approved by the NYPSC. In accordance with these settlements, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the “cost mitigation reserve”) to offset certain specific expense items. In 2008, Distribution Corporation utilized $5.6 million of the cost mitigation reserve, which increased other operating revenues, to recover previous undercollections of pension expenses. In 2009, Distribution Corporation utilized only $0.2 million of the cost mitigation reserve. The impact of this $5.4 million decrease in other operating revenues was offset by an equal decrease to operation and maintenance expense (thus there is no earnings impact).


33

2008 Compared with 2007
 
Operating revenues for the Utility segment increased $89.5 million in 2008 compared with 2007. This increase largely resulted from a $48.5 million increase in off-system sales revenue (see discussion below), a $25.6 million increase in retail gas sales revenues, an $11.3 million increase in transportation revenues, and a $4.1 million increase in other operating revenues.
 
The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues), which more than offset the revenue impact of lower retail sales volumes, as shown in the table above. See further discussion of purchased gas below under the heading “Purchased Gas.” This change was also affected by a base rate increase in the Pennsylvania jurisdiction (effective January 2007) that increased operating revenues by $4.0 million for 2008. The increase is included within both retail and transportation revenues in the table above.
 
In the New York jurisdiction, the NYPSC issued an order providing for an annual rate increase of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was adopted that shifts a greater amount of cost recovery into the minimum bill amount, thus spreading the recovery of such costs more evenly throughout the year. This rate design change resulted in lower retail and transportation revenues (exclusive of the impact of higher gas costs) during the winter months compared to the prior year and higher retail and transportation revenues in the spring and summer months compared to the prior year. On a cumulative basis for 2008, the impact of this rate order has been to lower operating revenues by $1.4 million. It is expected that there will be an increase in retail and transportation revenue in the first quarter of 2009 compared to the prior year as a result of the rate design change. The increase in transportation revenues was also due to a 2.0 Bcf increase in transportation throughput, largely the result of the migration of customers from retail sales to transportation service.
 
As reported in 2006, onOn November 17, 2006 the U.S. Court of Appeals vacated and remanded the FERC’s Order No. 2004 regarding affiliate standards of conduct, with respect to natural gas pipelines. The Court’s


34

decision became effective on January 5, 2007, and on January 9, 2007, the FERC issued Order No. 690, its Interim Rule, designed to respond to the Court’s decision. In Order No. 690, as clarified by the FERC on March 21, 2007, the FERC readopted, on an interim basis, certain provisions that existed prior to the issuance of Order No. 2004 that had made it possible for the Utility segment to engage in certain off-system sales without triggering the adverse consequences that would otherwise arise under the Order No. 2004 standards of conduct. As a result, the Utility segment resumed engaging in off-system sales on non-affiliated pipelines as of May 2007, resulting in total off-system sales revenues of $58.2 million and $9.8 million for 2008 and 2007, respectively. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins in 2008 and 2007.
 
The increase in other operating revenues of $4.1 million is largely related to amounts recorded pursuant to rate settlements approved by the NYPSC. In accordance with these settlements, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the “cost mitigation reserve”) to offset certain specific expense items. In 2008, Distribution Corporation utilized $5.6 million of the cost mitigation reserve, which increased other operating revenues, to recover previous undercollections of pension expenses. The impact of that increase in other operating revenues was offset by an equal amount of operation and maintenance expense (thus there is no earnings impact).
 
2007 Compared with 2006
Operating revenues for the Utility segment decreased $160.0 million in 2007 compared with 2006. This decrease largely resulted from a $180.4 million decrease in retail gas sales revenues. This decrease was partially offset by a $10.0 million increase in transportation revenues and a $9.8 million increase in off-system sales revenues.
The decrease in retail gas sales revenues for the Utility segment was largely a function of the recovery of lower gas costs (gas costs are recovered dollar for dollar in revenues), which more than offset the revenue impact of higher retail sales volumes, as shown in the table above. See further discussion of purchased gas below under the heading “Purchased Gas.” This decrease was offset slightly by a base rate increase in the Pennsylvania jurisdiction, effective January 2007, which increased operating revenues by $8.5 million for 2007. The increase is included within both retail and transportation revenues in the table above.
The increase in transportation revenues was primarily due to a 4.3 Bcf increase in transportation throughput, largely due to the migration of retail sales customers to transportation service. The corresponding $10.0 million increase in transportation revenues would have been greater if not for a $3.9 million out-of-period adjustment recorded in the first quarter of 2006 to correct Distribution Corporation’s calculation of the symmetrical sharing component of New York’s gas adjustment rate.
The increase in off-system sales revenue is due to the resumption of off-system sales in May 2007 pursuant to FERC authorization, as discussed above.
Purchased Gas
 
The cost of purchased gas is the Company’s single largest operating expense. Annual variations in purchased gas costs are attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses.
 
Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation, Empire and six other upstream pipeline companies, for long-term gas supplies with a combination of producers and marketers, and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation satisfies a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation’s average cost of purchased gas, including the cost of transportation and storage, was $8.17 per Mcf in 2009, a


34

decrease of 27% from the average cost of $11.23 per Mcf in 2008. The average cost of purchased gas in 2008 an increase ofwas 12% fromhigher than the average cost of $10.04 per Mcf in 2007. The average cost of purchased gas in 2007 was 17% lower than the average cost of $12.07 per Mcf in 2006. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.


35

Earnings
2009 Compared with 2008
The Utility segment’s earnings in 2009 were $58.7 million, a decrease of $2.8 million when compared with earnings of $61.5 million in 2008.
In the New York jurisdiction, earnings decreased by $3.0 million. This was primarily due to an increase in interest expense ($2.9 million) stemming from the borrowing by the New York jurisdiction of Distribution Corporation of a portion of the Company’s April 2009 debt issuance. The April 2009 debt was issued at a significantly higher interest rate than the interest rates on debt that had matured in March 2009. The negative earnings impact of the December 28, 2007 rate order discussed above ($1.4 million) and routine regulatory adjustments ($0.7 million) also contributed to the decrease. The decrease was partially offset by a $2.6 million overall reduction in operating expenses (mostly other post-retirement benefits and pension expense).
In the Pennsylvania jurisdiction, earnings increased by $0.2 million. This was primarily due to the positive earnings impact of colder weather ($2.1 million), routine regulatory adjustments ($0.5 million) and lower operating expenses ($0.9 million). A decrease in normalized usage per account ($2.3 million), a higher effective tax rate ($1.4 million) and an increase in interest expense ($0.2 million) partially offset these increases. The phrase “usage per account” refers to the average gas consumption per customer account after factoring out any impact that weather may have had on consumption.
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. For 2009, the WNC reduced earnings by approximately $0.2 million, as the weather was colder than normal. For 2008, the WNC preserved earnings of approximately $2.5 million, as the weather was warmer than normal.
 
2008 Compared with 2007
 
The Utility segment’s earnings in 2008 were $61.5 million, an increase of $10.6 million when compared with earnings of $50.9 million in 2007.
 
In the New York jurisdiction, earnings increased by $6.9 million. This was primarily due to a $3.6 million overall decrease in operating expenses (mostly other post-retirement benefits and bad debt expense), higher non-cash interest income on a pension-related regulatory asset ($2.6 million), a decrease in property, franchise, and other taxes ($0.9 million), a decrease in depreciation expense ($0.8 million), lower income tax expense ($0.7 million), lower interest expense ($0.2 million), and increased usage per account ($0.5 million). The impact of these items more than offset lower base rates due to the rate design change described above ($0.9 million), and routine regulatory adjustments that reduced earnings by $1.8 million.
 
In the Pennsylvania jurisdiction, earnings increased by $3.7 million. This was primarily due to a base rate increase ($2.6 million) that became effective January 2007, an increase in normalized usage ($1.3 million), a decrease in bad debt expense ($1.1 million), and a decrease in property, franchise, and other taxes ($0.3 million). Warmer weather ($1.6 million) partially offset these increases.
 
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (WNC).WNC. The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. In 2008 and 2007, the WNC preserved earnings of approximately $2.5 million and $2.3 million, respectively, as the weather was warmer than normal.
2007 Compared with 2006
The Utility segment’s earnings in 2007 were $50.9 million, an increase of $1.1 million when compared with earnings of $49.8 million in 2006.
In the New York jurisdiction, earnings decreased by $6.2 million. This was primarily due to lower interest income ($4.5 million). The New York division’s current rate agreement with the NYPSC allows the Company to accrue interest on a pension-related regulatory asset. The amount of interest that can be accrued is reduced as the funded status of the pension plan improves. The fair market value of the pension plan assets exceeded the accumulated benefit obligation at September 30, 2007 resulting in a significant reduction in the interest accrual on this regulatory asset. The out-of-period symmetrical sharing adjustment discussed above ($2.6 million), higher bad debt and other operating costs ($0.8 million), higher property taxes ($0.6 million), and higher interest expense ($0.5 million) also contributed to this decrease. The positive impact associated with a lower effective tax rate ($1.9 million) and increased usage per account ($1.9 million) partially offset the overall decrease.
In the Pennsylvania jurisdiction, earnings increased by $7.3 million. This was primarily due to a base rate increase ($5.5 million) that became effective January 2007, colder weather ($2.5 million), and the positive impact associated with a lower effective tax rate ($1.1 million). Higher intercompany and other interest expense ($0.8 million), coupled with a decrease in normalized usage ($0.3 million), partially offset these increases.
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a WNC. The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. In 2007 and 2006, the WNC preserved earnings of approximately $2.3 million and $6.2 million, respectively, as the weather was warmer than normal.


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PIPELINE AND STORAGE
 
Revenues
 
Pipeline and Storage Operating Revenues
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands)  (Thousands) 
Firm Transportation $122,321  $118,771  $118,551  $139,034  $122,321  $118,771 
Interruptible Transportation  4,330   4,161   4,858   3,175   4,330   4,161 
              
  126,651   122,932   123,409   142,209   126,651   122,932 
              
Firm Storage Service  67,020   66,966   66,718   66,711   67,020   66,966 
Interruptible Storage Service  14   169   39   20   14   169 
              
  67,034   67,135   66,757   66,731   67,034   67,135 
       
Other  22,871   21,899   24,186   10,333   22,871   21,899 
              
 $216,556  $211,966  $214,352  $219,273  $216,556  $211,966 
              
 
Pipeline and Storage Throughput — (MMcf)
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
Firm Transportation  353,173   351,113   363,379   356,771   353,173   351,113 
Interruptible Transportation  5,197   4,975   11,609   4,070   5,197   4,975 
              
  358,370   356,088   374,988   360,841   358,370   356,088 
              
2009 Compared with 2008
Operating revenues for the Pipeline and Storage segment increased $2.7 million in 2009 as compared with 2008. The increase was primarily due to a $15.6 million increase in transportation revenue primarily due to higher revenues from the Empire Connector and new contracts for transportation service. Partially offsetting this increase, efficiency gas revenues decreased $11.5 million (reported as a part of other revenue in the table above). The majority of this decrease was due to significantly lower gas prices in 2009 as compared to 2008. Under Supply Corporation’s tariff with suppliers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas to cover compressor fuel costs and other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as inventory. That inventory is later sold to customers. The excess gas that is retained as inventory represents efficiency gas revenue to Supply Corporation.
 
2008 Compared with 2007
 
Operating revenues for the Pipeline and Storage segment increased $4.6 million in 2008 as compared with 2007. The majority of the increase was the result of increased transportation revenues ($3.7 million) due to the fact that the Pipeline &and Storage segment was able to renew existing contracts at higher rates due to favorable market conditions for transportation service associated with storage. In addition, there were increased efficiency gas revenues ($0.8 million) reported as part of other revenues in the table above. The majority of this increase wasprimarily due to higher gas prices in the current year.
 
2007 Compared with 2006Earnings
 
Operating revenues for the2009 Compared with 2008
The Pipeline and Storage segment decreased $2.4segment’s earnings in 2009 were $47.4 million, a decrease of $6.7 million when compared with earnings of $54.1 million in 2007 as compared with 2006, which was due mostly to a decrease in other revenues ($2.3 million).2008. The decrease in other revenues iswas primarily due to the earnings impact


36

associated with a $4.2 million decrease in efficiency gas revenues. Thisrevenues ($7.5 million), as discussed above. In addition, higher interest expense ($5.1 million), higher depreciation expense ($1.5 million), and a decrease in the allowance for funds used during construction ($2.0 million) also contributed to the decrease in earnings. The increase in interest expense can be attributed to higher debt balances and a higher average interest rate on borrowings. The increase in the average interest rate stems from the borrowing of a portion of the Company’s April 2009 debt issuance. The increase in depreciation expense can be attributed primarily to a revision of accumulated depreciation combined with the increased depreciation associated with placing the Empire Connector in service in December 2008. The decease in the allowance for funds used during construction was due to completion of the Company’s recent settlement withEmpire Connector project in December 2008. Whereas the FERC, which decreased efficiency gas retainage allowances. Offsetting this decrease, there was a $1.4 million increase in other revenues attributableallowance for funds used during construction related to the lease termination fee adjustmentEmpire Connector project was recorded throughout 2008, it was only recorded for three months in 2006 (an intercompany transaction) for2009. These earnings decreases were partially offset by the Company’s former headquarters, which did not recur in 2007. While Supply Corporation’searnings impact associated with higher transportation volumes decreased during the year, volume fluctuations generally do not have a significant impact on revenues ($9.7 million), as a result of Supply Corporation’s straight-fixed variable rate design.
Earningsdiscussed above.
 
2008 Compared with 2007
 
The Pipeline and Storage segment’s earnings in 2008 were $54.1 million, a decrease of $2.2 million when compared with earnings of $56.4 million in 2007. The main factors contributing to this decrease were higher operation and maintenance expenses ($6.1 million), primarily caused by the non-recurrence in 2008 of a reversal of a reserve for preliminary survey costs related to the Empire Connector project during 2007


37

($ ($4.8 million). In addition, there was a $1.9 million positive earnings impact during 2007 associated with the discontinuance of hedge accounting for Empire’s interest rate collar that did not recur during 2008, and the Pipeline and Storage segment experienced higher interest costs ($1.5 million). These earnings decreases were offset by the earnings impact associated with higher transportation revenues ($2.4 million), an increase in the allowance for funds used during construction ($4.2 million) and the earnings impact associated with higher efficiency gas revenues ($0.5 million).
 
2007 Compared with 2006
The Pipeline and Storage segment’s earnings in 2007 were $56.4 million, an increase of $0.8 million when compared with earnings of $55.6 million in 2006. The main factor contributing to this increase was the reversal of a reserve for preliminary survey costs ($4.8 million) related to the Empire Connector project. Based on the signing of a service agreement with KeySpan Gas East Corporation during the quarter ended June 30, 2007, management determined that it was probable that the project would go forward and that such preliminary survey costs were properly capitalizable in accordance with the FERC’s Uniform System of Accounts and SFAS 71. In addition, there was a $2.5 million increase in earnings associated with the decrease in depreciation expense as a result of the most recent settlement with the FERC, which reduced depreciation rates. There was also a $1.9 million positive earnings impact associated with the discontinuance of hedge accounting for Empire’s interest rate collar. On December 8, 2006, Empire repaid $22.8 million of secured debt. The interest costs of this secured debt were hedged by the interest rate collar. Since the hedged transaction was settled and there will be no future cash flows associated with the secured debt, the unrealized gain in accumulated other comprehensive income associated with the interest rate collar was reclassified to the income statement. These earnings increases were offset by higher interest expense ($3.2 million), the earnings impact associated with lower efficiency gas revenues ($2.7 million), a $1.5 million increase in operating costs (primarily post-retirement benefit costs), and the earnings decrease associated with a higher effective tax rate ($0.9 million).
EXPLORATION AND PRODUCTION
 
Revenues
 
Exploration and Production Operating Revenues
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands)  (Thousands) 
Gas (after Hedging) from Continuing Operations $202,153  $143,785  $126,969  $154,582  $202,153  $143,785 
Oil (after Hedging) from Continuing Operations  250,965   167,627   134,307   219,046   250,965   167,627 
Gas Processing Plant from Continuing Operations  49,090   37,528   42,252   24,686   49,090   37,528 
Other from Continuing Operations  (944)  1,147   3,072   432   (944)  1,147 
Intrasegment Elimination from Continuing Operations(1)  (34,504)  (26,050)  (31,704)  (15,988)  (34,504)  (26,050)
              
Operating Revenues from Continuing Operations $466,760  $324,037  $274,896  $382,758  $466,760  $324,037 
              
Operating Revenues from Canada — Discontinued Operations $—  $50,495  $71,984  $—  $—  $50,495 
              
 
 
(1)Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging) from Continuing Operations” in the table above that is sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense.


3837

 
Production Volumes
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
Gas Production(MMcf)
                        
Gulf Coast  11,033   10,356   9,110   9,886   11,033   10,356 
West Coast  4,039   3,929   3,880   4,063   4,039   3,929 
Appalachia  7,269   5,555   5,108   8,335   7,269   5,555 
              
Total Production from Continuing Operations  22,341   19,840   18,098   22,284   22,341   19,840 
Canada — Discontinued Operations  —   6,426   7,673   —   —   6,426 
              
Total Production  22,341   26,266   25,771   22,284   22,341   26,266 
              
Oil Production(Mbbl)
                        
Gulf Coast  505   717   685   640   505   717 
West Coast  2,460   2,403   2,582   2,674   2,460   2,403 
Appalachia  105   124   69   59   105   124 
              
Total Production from Continuing Operations  3,070   3,244   3,336   3,373   3,070   3,244 
Canada — Discontinued Operations  —   206   272   —   —   206 
              
Total Production  3,070   3,450   3,608   3,373   3,070   3,450 
              
 
Average Prices
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
Average Gas Price/Mcf
                        
Gulf Coast $10.03  $6.58  $8.01  $4.54  $10.03  $6.58 
West Coast $8.71  $6.54  $7.93  $3.91  $8.71  $6.54 
Appalachia $9.73  $7.48  $9.53  $5.52  $9.73  $7.48 
Weighted Average for Continuing Operations $9.70  $6.82  $8.42  $4.79  $9.70  $6.82 
Weighted Average After Hedging for Continuing Operations(1) $9.05  $7.25  $7.02  $6.94  $9.05  $7.25 
Canada — Discontinued Operations $—  $6.09  $7.14  $—  $—  $6.09 
Average Oil Price/Barrel (bbl)
                        
Gulf Coast $107.27  $63.04  $64.10  $54.58  $107.27  $63.04 
West Coast(2) $98.17  $56.86  $56.80  $50.90  $98.17  $56.86 
Appalachia $97.40  $62.26  $65.28  $56.15  $97.40  $62.26 
Weighted Average for Continuing Operations $99.64  $58.43  $58.47  $51.69  $99.64  $58.43 
Weighted Average After Hedging for Continuing Operations(1) $81.75  $51.68  $40.26  $64.94  $81.75  $51.68 
Canada — Discontinued Operations $—  $50.06  $51.40  $—  $—  $50.06 
 
 
(1)Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note FG — Financial Instruments in Item 8 of this report.
 
(2)Includes low gravity oil which generally sells for a lower price.
2009 Compared with 2008
Operating revenues from continuing operations for the Exploration and Production segment decreased $84.0 million in 2009 as compared with 2008. Gas production revenue after hedging from continuing operations decreased $47.6 million primarily due to a $2.11 per Mcf decrease in weighted average prices after hedging. Gas production from continuing operations was virtually flat with the prior year as production


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decreases in the Gulf Coast region were substantially offset by production increases in the Appalachian region. The decrease in gas production from continuing operations that occurred in the Gulf Coast region (1,147 MMcf) was a result of lingering shut-ins caused by Hurricanes Edouard, Gustav and Ike in September 2008. While Seneca’s properties sustained only superficial damage from the hurricanes, two significant producing properties were shut-in for a significant portion of the current fiscal year due to repair work on third party pipelines and onshore processing facilities. One of the properties was back on line by March 31, 2009 and the other property was back on line by the end of April 2009. The increase in gas production from continuing operations in the Appalachian region of 1,066 MMcf resulted from additional wells drilled throughout fiscal 2008 that came on line in 2009. Oil production revenue after hedging from continuing operations decreased $31.9 million due to a $16.81 per barrel decrease in weighted average prices after hedging, which more than offset an increase in oil production from continuing operations of 303,000 barrels (primarily from the West Coast and Gulf Coast regions). In addition, there was a $5.9 million decrease in gross processing plant revenues from continuing operations (net of eliminations) due to a reduction in the commodity prices of residual gas and liquids sold at Seneca’s processing plants in the West Coast and Appalachian regions.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
 
2008 Compared with 2007
 
Operating revenues from continuing operations for the Exploration and Production segment increased $142.7 million in 2008 as compared with 2007. Oil production revenue after hedging from continuing operations increased $83.3 million due primarily to a $30.07 per barrel increase in weighted average prices after hedging, which more than offset a decrease in oil production of 174,000 barrels. Gas production revenue


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after hedging from continuing operations increased $58.4 million due to a $1.80 per Mcf increase in weighted average prices after hedging and a 2,501 MMcf increase in production.production from continuing operations. The increase in gas production from continuing operations occurred primarily in the Appalachian region (1,714 MMcf), consistent with increased drilling activity in the region. The Gulf Coast region also contributed significantly to the increase in natural gas production from continuing operations (677 MMcf). Production from new fields in 2008 (primarily in the High Island area) outpaced declines in production from some existing fields, period to period. Production in this region would have been higher if not for the hurricane activity during the month of September 2008. As a result of hurricanes Edouard, Gustav and Ike, production was shut in for much of the month of September, resulting in estimated lost production of approximately 804 MMcf of natural gas and 45 Mbbl of oil. While Seneca’s properties sustained only superficial damage from the hurricanes, approximately 50% of the pre-hurricane production remains shut-in due to repair work on third party pipelines and onshore processing facilities. The majority of this production is anticipated to return by December 1, 2008.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
2007 Compared with 2006
Operating revenues from continuing operations for the Exploration and Production segment increased $49.1 million in 2007 as compared with 2006. Oil production revenue after hedging increased $33.3 million due primarily to an $11.42 per barrel increase in weighted average prices after hedging, which more than offset a slight decrease in oil production of 92,000 barrels. Gas production revenue after hedging increased $16.8 million in 2007 as compared with 2006. An increase in gas production of 1,742 MMcf and an increase in weighted average prices after hedging of $0.23 per Mcf both contributed to the increase. The increase in gas production occurred primarily in the Gulf Coast region (1,246 MMcf). During the quarter ended December 31, 2005, Seneca experienced significant production delays due largely to the impact of hurricane damage to pipeline infrastructure in the Gulf of Mexico. Seneca had substantially all of its pre-hurricane Gulf of Mexico production back on line at the beginning of fiscal 2007. Production also increased in this segment’s Appalachian region (447 MMcf), primarily due to increased drilling in this region during 2007, as highlighted in Item 2 under “Exploration and Production Activities.”
 
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
 
Earnings
2009 Compared with 2008
The Exploration and Production segment’s loss from continuing operations for 2009 was $10.2 million, compared with earnings from continuing operations of $146.6 million for 2008, a decrease of $156.8 million. The decrease in earnings is primarily the result of an impairment charge of $108.2 million, as discussed above. In addition, lower crude oil prices, lower natural gas prices, and lower natural gas production decreased earnings by $36.9 million, $30.6 million, and $0.3 million, respectively, while higher crude oil production increased earnings by $16.1 million. Lower interest income ($5.5 million) and higher operating expenses ($1.7 million) further reduced earnings. In addition, there was a $3.8 million decrease in earnings caused by a reduction in the commodity prices of residual gas and liquids sold at Seneca’s processing plants in the West Coast and Appalachian regions. The decrease in interest income is due to lower interest rates and lower temporary cash investment balances. The increase in operating expenses is due to an increase in bad debt expense as a result of a customer’s bankruptcy filing, and higher personnel costs in the Appalachian region. These earnings decreases were partially offset by lower interest expense ($5.4 million), lower lease operating costs ($2.6 million), lower depletion expense ($0.9 million), and lower income tax expense ($4.2 million). The


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decline in interest expense is primarily due to a lower average amount of debt outstanding. The reduction in lease operating expenses is primarily due to a reduction in steam fuel costs in the West Coast region and lower production taxes in the Gulf Coast region. The decrease in depletion is primarily due to a lower full cost pool balance after the impairment charge taken during the quarter ended December 31, 2008.
 
2008 Compared with 2007
 
The Exploration and Production segment’s earnings from continuing operations for 2008 were $146.6 million, an increase of $71.7 million when compared with earnings from continuing operations of $74.9 million for 2007. Higher crude oil prices, higher natural gas prices and higher natural gas production increased earnings by $60.0 million, $26.2 million and $11.8 million, respectively, while lower crude oil production decreased earnings by $5.8 million. Higher lease operating costs ($11.9 million), higher depletion expense ($9.1 million), higher income tax expense ($1.1 million) and higher general and administrative and other operating expenses ($6.2 million) also negatively impacted earnings. Lower interest expense and higher interest income of $6.6 million and $0.7 million, respectively, partially offset these decreases to earnings. The increase in lease operating costs resulted from thestart-up of production at the High Island 24L field in October 2007, higher steaming costs in California, and an increase in costs associated with a higher number of producing properties in Appalachia. The increase in depletion expense was caused by higher production and an increase in the depletable base. The increase in general and administrative and other operating expenses resulted from an increase in staffing and associated costs for the growing Appalachia division combined with the recognition of actual plugging costs in excess of previously accrued amounts.


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2007 Compared with 2006
 
The Exploration and Production segment’s earnings from continuing operations for 2007 were $74.9 million, an increase of $7.4 million when compared with earnings from continuing operations of $67.5 million for 2006. Higher crude oil prices, higher natural gas production and higher natural gas prices increased earnings by $24.1 million, $7.9 million and $3.0 million, respectively. These increases were partly offset by the non-recurrence of $6.1 million of tax benefits recognized during 2006, as well as by higher depletion expense and higher lease operating expense of $7.2 million and $4.6 million, respectively. Slightly lower crude oil production and higher general and administrative expenses also decreased earnings by $2.4 million and $0.6 million, respectively. Earnings were also negatively impacted by higher income tax expense ($6.3 million).
ENERGY MARKETING
 
Revenues
 
Energy Marketing Operating Revenues
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands)  (Thousands) 
Natural Gas (after Hedging) $551,243  $413,405  $496,769  $398,205  $551,243  $413,405 
Other  (11)  207   300   116   (11)  207 
              
 $551,232  $413,612  $497,069  $398,321  $551,232  $413,612 
              
 
Energy Marketing VolumesVolume
 
             
  Year Ended September 30 
  2008  2007  2006 
 
Natural Gas — (MMcf)  56,120   50,775   45,270 
             
  Year Ended September 30
  2009 2008 2007
 
Natural Gas — (MMcf)  60,858   56,120   50,775 
2009 Compared with 2008
Operating revenues for the Energy Marketing segment decreased $152.9 million in 2009 as compared with 2008. The decrease is primarily due to lower gas sales revenue, due to a lower average price of natural gas that was recovered through revenues. This decline was somewhat offset by an increase in volume sold. The increase in sales volume is largely attributable to colder weather as well as an increase in sales transactions undertaken at the Niagara pipeline delivery point to offset certain basis risks that the Energy Marketing segment was exposed to under certain fixed basis commodity purchase contracts for Appalachian production. Such offsetting transactions had the effect of increasing revenue and volume sold with minimal impact to earnings.
 
2008 Compared with 2007
 
Operating revenues for the Energy Marketing segment increased $137.6 million in 2008 as compared with 2007. The increase is primarily due to higher gas sales revenue, as a result of an increase in the price of natural gas that was recovered through revenues, coupled with an increase in volumes.volume sold. The increase in volumesvolume is


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primarily attributable to an increase in volumesvolume sold to low-margin wholesale customers, as well as an increase in the number of commercial and industrial customers served by the Energy Marketing segment. The increase in volumesvolume also reflects certain sales transactions undertaken at the Niagara pipeline delivery point to offset certain basis risks that the Energy Marketing segment was exposed to under certain fixed basis commodity purchase contracts. Thecontracts for Appalachian production. Such offsetting purchase and sale transactions had the effect of increasing revenue and volumesvolume sold with minimal impact to earnings.
 
2007 Compared with 2006Earnings
 
Operating revenues for the2009 Compared with 2008
The Energy Marketing segment decreased $83.5segment’s earnings in 2009 were $7.2 million, an increase of $1.3 million when compared with earnings of $5.9 million in 2007 as compared2008. Higher margin of $1.5 million combined with 2006. The decrease primarily reflects lower gas sales revenueoperating costs of $0.4 million (primarily due to a decreasedecline in bad debt expense) are responsible for the increase in earnings. These increases were partially offset by higher income tax expense of $0.4 million in 2009 as compared to 2008. The increase in margin was primarily driven by lower pipeline transportation fuel costs due to lower natural gas commodity prices, for the periodan unfavorable pipeline imbalance resolution in fiscal 2008 that were recovered through revenues,did not recur in fiscal 2009, and improved average margins per Mcf, partially offset in part by an increase in volumes. The increase in volumes was duehigher pipeline reservation charges related to the addition of certain large, low-margin commercial and industrial customers, an increase in sales to wholesale customers, and colder weather.
Earningsadditional storage capacity.
 
2008 Compared with 2007
 
The Energy Marketing segment’s earnings in 2008 were $5.9 million, a decrease of $1.8 million when compared with earnings of $7.7 million in 2007. Higher operating costs of $1.1 million (primarily due to an increase in bad debt expense) coupled with lower marginsmargin of $1.1 million are primarily responsible for the decrease in earnings. A major factor in the margin decrease is the non-recurrence of a purchased gas expense


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adjustment recorded during the quarter ended March 31, 2007. During that quarter, the Energy Marketing segment reversed an accrual for $2.3 million of purchased gas expense due to a resolution of a contingency. The increase in volumesvolume noted above, the profitable sale of certain gas held as inventory, and the marketing flexibility that the Energy Marketing segment derives from its contracts for significant storage capacity partially offset the margin decrease associated with the purchased gas adjustment.
 
2007 Compared with 2006
The Energy Marketing segment’s earnings in 2007 were $7.7 million, an increase of $1.9 million when compared with earnings of $5.8 million in 2006. Higher margins of $2.3 million are responsible for the increase in earnings. The increase in margin is mainly the result of a $2.3 million reversal of an accrual for purchased gas expense related to the resolution of a contingency during 2007. While volumes increased, as noted above, much of this increase in volume is related to sales to low margin customers.
TIMBER
Revenues
Timber Operating Revenues
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands) 
 
Log Sales $19,989  $21,927  $23,077 
Green Lumber Sales  4,864   5,097   7,123 
Kiln-Dried Lumber Sales  22,914   27,908   32,809 
Other  1,749   3,965   2,020 
             
  $49,516  $58,897  $65,029 
             
Timber Board Feet
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands) 
 
Log Sales  9,272   8,660   9,527 
Green Lumber Sales ��9,747   9,358   10,454 
Kiln-Dried Lumber Sales  13,425   14,778   16,862 
             
   32,444   32,796   36,843 
             
2008 Compared with 2007
Operating revenues for the Timber segment decreased $9.4 million in 2008 as compared with 2007. Unfavorable market conditions for cherry logs and lumber combined with wet weather conditions that hampered harvesting were the main factors causing the decrease. The decrease consisted of a $5.0 million decline in kiln-dried lumber sales. The decrease in kiln-dried lumber sales was due to both a decline in the market price of kiln-dried lumber as well as a 1,353,000 board feet decline in kiln-dried lumber sales volumes (primarily kiln-dried cherry lumber sales volumes). Log sales also decreased $1.9 million primarily due to a decline in cherry veneer log sales volumes of 328,000 board feet. Cherry veneer logs are more valuable and sell at higher prices than other species and have the largest impact on overall log sales revenue. In addition, in 2007 the Timber segment sold 3.1 million board feet of timber rights and recorded a gain of $1.6 million in other revenues. This event did not recur in 2008.


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2007 Compared with 2006
Operating revenues for the Timber segment decreased $6.1 million in 2007 as compared with 2006. This decrease is attributed to unfavorable weather conditions primarily during the fall of 2006 and the spring of 2007 that greatly limited the harvesting of logs. These conditions consisted of warm, wet weather that made it difficult to bring logging trucks into the forests. Weather conditions were significantly more favorable throughout fiscal 2006. These unfavorable conditions for harvesting resulted in a decline in log sales of $1.2 million or 867,000 board feet. There was also a decline in both green lumber and kiln-dried lumber sales of $2.0 million and $4.9 million, respectively, primarily because there were fewer logs available for processing. Declines in market prices for the cherry and maple species also contributed to the decrease in green lumber and kiln-dried lumber sales. Additionally, the processing of a greater amount of lumber species other than cherry (due to the mix of species on the areas being harvested) contributed to the decline in kiln-dried lumber sales since lumber species other than cherry are sold at a lower price than kiln-dried cherry lumber. Offsetting the decreases discussed above, other revenues increased $1.9 million largely due to the sale of 3.1 million board feet of timber rights ($1.6 million).
Earnings
2008 Compared with 2007
The Timber segment earnings in 2008 were $0.1 million, a decrease of $3.6 million when compared with earnings of $3.7 million in 2007. The decrease was primarily due to lower margins from lumber, log and timber rights sales ($4.2 million) as a result of the decline in revenues noted above. This decrease was partially offset by the earnings benefit associated with a lower effective tax rate ($0.8 million).
2007 Compared with 2006
The Timber segment earnings in 2007 were $3.7 million, a decrease of $2.0 million when compared with earnings of $5.7 million in 2006. The decrease was primarily due to lower margins from lumber and log sales ($2.5 million) as a result of the decline in revenues noted above, as well as higher general and administrative expenses of $0.3 million. Partially offsetting this decrease was a decline in depletion expense of $1.2 million. The decrease in depletion expense reflects the cutting of more low cost or no cost basis timber from Company owned land as well as the overall decrease in logs harvested.
ALL OTHER AND CORPORATE OPERATIONS
 
All Other and Corporate operations primarily includes the operations of Highland, Seneca’s Northeast Division, Midstream Corporation, Horizon LFG, Horizon Power, former International segment activity and corporate operations. Highland and Seneca’s Northeast Division market timber from their New York and Pennsylvania land holdings, own two sawmill operations in northwestern Pennsylvania and process timber consisting primarily of high quality hardwoods. Midstream Corporation is a Pennsylvania corporation formed to build, own and operate natural gas processing and pipeline gathering facilities in the Appalachian region. Horizon LFG owns and operates short-distance landfill gas pipeline companies. Horizon Power’s activity primarily consists of equity method investments in Seneca Energy, Model City and ESNE. Horizon Power has a 50% ownership interest in each of these entities. The income from these equity method investments is reported as Income from Unconsolidated Subsidiaries on the Consolidated Statements of Income. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania.
 
Earnings
 
2009 Compared with 2008
All Other and Corporate operations had a loss of $2.2 million in 2009, a decrease of $2.8 million compared with earnings of $0.6 million for 2008. The decrease in earnings was largely attributable to lower margins from lumber, log and timber rights sales ($2.5 million), lower margins from Horizon LFG ($1.6 million), lower interest income ($0.6 million), lower income from Horizon Power’s investments in unconsolidated subsidiaries


41

($2.0 million), and higher interest expense ($3.1 million). The decrease in margins from lumber, log and timber rights sales is a result of a decline in revenues due to unfavorable market conditions. The decrease in margins from Horizon LFG is due to the decrease in the price of gas and lower volumes due to the poor economy. The increase in interest expense was primarily the result of higher borrowings at a higher interest rate (mostly due to the $250 million of 8.75% notes that were issued in April 2009). In addition, during 2009, ESNE, an unconsolidated subsidiary of Horizon Power, recorded an impairment charge of $3.6 million. Horizon Power’s 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis). In 2009, Horizon LFG recorded an impairment charge of $4.6 million on its landfill gas assets ($2.8 million on an after-tax basis). Also, Horizon Power recognized a gain on the sale of a turbine ($0.6 million) during 2008 that did not recur in 2009. These earnings decreases were partially offset by lower operating costs ($4.9 million). In 2008, the proxy contest with New Mountain Vantage GP, L.L.C. led to an increase in operating costs, which did not recur in 2009. In addition, lower income tax expense ($4.3 million) and a gain on life insurance policies held by the Company ($2.3 million) further offset the earnings decrease.
The impairment charge of $4.6 million recorded by Horizon LFG during 2009 (as discussed above) was comprised of a $2.6 million reduction in intangible assets related to long-term gas purchase contracts and a $2.0 million reduction in property, plant and equipment. The impairment was recorded due to the loss of the primary customer at a landfill gas site and the anticipated shut-down of the site. This impairment charge reduced the recorded value of intangible assets and property, plant and equipment associated with this site to zero at September 30, 2009.
The impairment charge of $3.6 million recorded by ESNE during 2009 (as discussed above) was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power.
2008 Compared with 2007
 
All Other and Corporate operations had earnings of $0.5$0.6 million in 2008, a decrease of $7.6$11.3 million compared with earnings of $8.1$11.9 million for 2007. The positive earnings impact of higher income from unconsolidated subsidiaries ($0.9 million) and a gain on the sale of a turbine by Horizon Power ($0.6 million) were more than offset by higher operating costs ($6.15.9 million), higher income tax expense ($1.70.9 million), lower interest income ($1.5 million) and lower interest incomemargins from lumber, log and timber rights sales ($1.34.2 million). The increase in operating costs is primarily the result of the proxy contest with New Mountain Vantage GP, L.L.C.


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The decrease in margins from lumber, log and timber rights sales is a result of a decline in revenues due to unfavorable market conditions and wet weather conditions that hampered harvesting. In addition, in 2007, Compared with 2006
All OtherSeneca’s Northeast Division sold 3.1 million board feet of timber rights and Corporate operations had earningsrecorded a gain of $8.1$1.6 million in 2007, an increase of $7.9 million compared with earnings of $0.2 million for 2006. This improvement was largely due to an increaseother revenues, which did not recur in interest income of $4.1 million (primarily intercompany interest). In the All Other category, Horizon LFG’s earnings benefited from higher margins of $1.0 million in 2007 as compared to 2006, and Horizon Power’s income from unconsolidated subsidiaries increased $0.9 million, also contributing to the increase in earnings. The Corporate and All Other categories also had an earnings benefit associated with lower income tax expense ($2.0 million).2008.
 
INTEREST INCOME
Interest income was $5.0 million lower in 2009 as compared to 2008. Lower cash investment balances in the Exploration and Production segment and lower interest rates on such investments were the primary factors contributing to this decrease.
 
Interest income was $9.3 million higher in 2008 as compared to 2007. The main reason for this increase was a $4.0 million increase in interest income on a pension-related regulatory asset in the Utility segment’s New York jurisdiction. The Exploration and Production segment also contributed $3.8 million to this increase as a result of the investment of cash proceeds from the sale of SECI in August 2007.
 
Interest income was $7.9 million lower in 2007 as compared to 2006. As discussed in the Utility earnings section above, the main reason for this decrease was a $7.4 million decrease in interest income on a pension-related regulatory asset in the Utility segment’s New York jurisdiction.
OTHER INCOME
 
Other income was $0.8 million lower in 2009 as compared to 2008. This decrease is attributed to a $1.7 million decrease in the allowance for funds used during construction in the Pipeline and Storage segment associated with the Empire Connector project. Horizon Power recognized a $0.9 million pre-tax gain on the sale of a turbine during 2008 that did not recur in 2009. These decreases were partially offset by a death benefit gain on life insurance policies of $2.3 million recognized in the Corporate category during 2009.


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Other income was $2.4 million higher in 2008 as compared to 2007. This increase is primarily attributed to thea $4.2 million increase in the allowance for funds used during construction in the Pipeline and Storage segment associated with the Empire Connector projectproject. It also reflects a $0.9 million pre-tax gain on the sale of $4.2 million. This increase wasa turbine during 2008. These increases were partially offset by the non-recurrence of a death benefit gain on life insurance proceeds of $1.9 million recognized in the Corporate category in 2007.
Other income was $2.1 million higher in 2007 as compared to 2006. The increase is attributed to a death benefit gain on life insurance proceeds of $1.9 million recognized in the Corporate category.
 
INTEREST CHARGES
 
Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis:
Interest on long-term debt increased $9.3 million in 2009 as compared to 2008. The increase in 2009 was primarily the result of a higher average amount of long-term debt outstanding combined with higher average interest rates. In April 2009, the Company issued $250 million of 8.75% senior, unsecured notes due in May 2019. This increase was partially offset by the repayment of $100 million of 6% medium-term notes that matured in March 2009.
 
Interest on long-term debt increased $1.7 million in 2008 as compared to 2007. The increase in 2008 was primarily the result of a higher average amount of long-term debt outstanding. In April 2008, the Company issued $300 million of 6.5% senior, unsecured notes due in April 2018. This increase was partially offset by the repayment of $200 million of 6.303% medium-term notes that matured on May 27, 2008.
 
Interest on long-term debt decreased $4.2Other interest charges increased $3.6 million in 2007 as2009 compared to 2006.2008. The increase in 2009 was primarily caused by a $2.3 million increase in interest expense on regulatory deferrals (primarily deferred gas costs) in the Utility segment’s New York jurisdiction combined with a $0.7 million decrease in 2007 was primarily the result of a lower average amount of long-term debt outstanding. In addition,allowance for borrowed funds used during construction related to the Company recognized a $1.9 million benefit to interest expense as a result of the discontinuance of hedge accounting for Empire’s interest rate collar, as discussed above under Pipeline and Storage. The underlying long-term debt associated with this interest rate collar was repaid in December 2006 and the unrealized gain recorded in accumulated other comprehensive income associated with the interest rate collar was reclassified to interest expense during the quarter ended December 31, 2006.Empire Connector project.
 
Other interest charges decreased $2.2 million in 2008 compared to 2007. Other interest charges did not change significantly in 2007 as compared to 2006. The decrease in 2008 was primarily caused by a $1.7 million increase in the allowance for borrowed funds used during construction related to the Empire Connector project.


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CAPITAL RESOURCES AND LIQUIDITY
 
The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
 
Sources (Uses) of Cash
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Millions)    (Millions)   
Provided by Operating Activities $482.8  $394.2  $471.4  $609.4  $482.8  $394.2 
Capital Expenditures  (397.7)  (276.7)  (294.2)  (309.9)  (397.7)  (276.7)
Investment in Partnership  —   (3.3)  — 
Investment in Subsidiary, Net of Cash Acquired  (34.9)  —   — 
Investment in Partnerships  (1.3)  —   (3.3)
Net Proceeds from Sale of Foreign Subsidiaries  —   232.1   —   —   —   232.1 
Cash Held in Escrow  58.4   (58.2)  —   (2.0)  58.4   (58.2)
Net Proceeds from Sale of Oil and Gas Producing Properties  5.9   5.1   —   3.6   5.9   5.1 
Other Investing Activities  4.4   (0.8)  (3.2)  (2.8)  4.4   (0.8)
Reduction of Long-Term Debt  (200.0)  (119.6)  (9.8)  (100.0)  (200.0)  (119.6)
Net Proceeds from Issuance of Long-Term Debt  296.6   —   —   247.8   296.6   — 
Issuance of Common Stock  17.4   17.5   23.3 
Net Proceeds from Issuance of Common Stock  28.2   17.4   17.5 
Dividends Paid on Common Stock  (103.7)  (100.6)  (98.2)  (104.2)  (103.7)  (100.6)
Excess Tax Benefits Associated with Stock- Based Compensation Awards  16.3   13.7   6.5   5.9   16.3   13.7 
Shares Repurchased under Repurchase Plan  (237.0)  (48.1)  (85.2)  —   (237.0)  (48.1)
Effect of Exchange Rates on Cash  —   (0.1)  1.4   —   —   (0.1)
              
Net Increase (Decrease) in Cash and Temporary Cash Investments $(56.6) $55.2  $12.0  $339.8  $(56.6) $55.2 
              
 
OPERATING CASH FLOW
 
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, impairment of investment in partnership, deferred income taxes, income or loss from unconsolidated subsidiaries net of cash distributions and gain on sale of discontinued operations.
 
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation’sthe straight fixed-variable rate design.design used by Supply Corporation and Empire.
 
Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.
 
Net cash provided by operating activities totaled $609.4 million in 2009, an increase of $126.6 million compared with the $482.8 million provided by operating activities in 2008. The increase is primarily due to the timing of gas cost recovery in the Utility segment. As gas prices decreased significantly during 2009, the Company’s Utility segment experienced an over-recovery of gas costs that is reflected in Amounts Payable to Customers on the Company’s Consolidated Balance Sheet at September 30, 2009. At September 30, 2008, the


44

Company’s Utility segment was in an under-recovery position. It is expected that the over-recovery at September 30, 2009 will be passed back to customers in 2010.
Net cash provided by operating activities totaled $482.8 million in 2008, an increase of $88.6 million compared with the $394.2 million provided by operating activities in 2007. The increase is partially due to lower working capital requirements inIn the Utility segment.segment, lower cash payments for gas costs offset partially by lower cash receipts for retail and transportation services resulted in higher cash provided by operations. In the Exploration and Production segment, cash provided by operations increased due to higher cash receipts from the sale of oil and gas production, largely a result of higher commodity prices,prices. This increase in the Exploration and Production segment was partially offset by thea decrease in cash provided by operations that resulted from the sale of SECI, a discontinued operation, in August 2007. OffsettingCash provided by operating activities from SECI was $0.3 million in 2007. Partially offsetting these increases, were higher working capital requirements in the Energy Marketing segment.segment experienced a decrease in cash provided by operations due to the timing of gas cost recovery.


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INVESTING CASH FLOW
 
Expenditures for Long-Lived Assets
 
The Company’s expenditures from continuing operations for long-lived assets totaled $339.2 million, $414.5 million and $250.9 million in 2008.2009, 2008 and 2007, respectively. The table below presents these expenditures:
 
     
  Year Ended
 
  September 30,
 
  2008 
  Total Expenditures
 
  For Long-Lived
 
  Assets 
  (Millions) 
 
Utility $57.5 
Pipeline and Storage(1)  165.5 
Exploration and Production  192.2 
Timber  1.4 
All Other and Corporate  0.3 
Eliminations(2)  (2.4)
     
  $414.5 
     
             
  Year Ended September 30 
  2009  2008  2007 
     (Millions)    
 
Utility:            
Capital Expenditures $56.2  $57.5  $54.2 
Pipeline and Storage:            
Capital Expenditures  50.1(1)  165.5(1)  43.2 
Exploration and Production:            
Capital Expenditures  188.3(2)  192.2   146.7 
Investment in Subsidiary  34.9(3)  —   — 
All Other and Corporate:            
Capital Expenditures  8.7(4)  1.7   3.5 
Investment in Partnerships  1.3   —   3.3 
Eliminations  (0.3)(5)  (2.4)(6)  — 
             
Total Expenditures from Continuing Operations $339.2  $414.5  $250.9(7)
             
 
 
(1)Amount includesfor 2009 excludes $16.8 million of accrued capital expenditures related to the Empire Connector project.project accrued at September 30, 2008 and paid during the year ended September 30, 2009. This amount was included in 2008 capital expenditures shown in the table above, but was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. The amount has been included in the Consolidated Statement of Cash Flows at September 30, 2009.
(2)Amount for 2009 includes $9.1 million of accrued capital expenditures, the majority of which was in the Appalachian region. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 20082009 since it represents a non-cash investing activity at that date.
 
(2)(3)Investment amount is net of $4.3 million of cash acquired.
(4)Amount for 2009 includes $0.7 million of accrued capital expenditures related to the construction of the Midstream Covington Gathering System. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since it represents a non-cash investing activity at that date.


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(5)Represents $0.3 million of capital expenditures in the Pipeline and Storage segment for the purchase of pipeline facilities from the Appalachian region of the Exploration and Production segment during the quarter ended December 31, 2008.
(6)Represents $2.4 million of capital expenditures included in the Appalachian region of the Exploration and Production segment for the purchase of storage facilities, buildings, and base gas from Supply Corporation during the quarter ended March 31, 2008.
(7)Excludes expenditures for long-lived assets associated with discontinued operations of $29.1 million.
 
Utility
 
The majority of the Utility capital expenditures for 2009, 2008 and 2007 were made for replacement of mains and main extensions, as well as for the replacement of service lines.
 
Pipeline and Storage
 
The majority of the Pipeline and Storage segment’s capital expenditures for 2009 and 2008 were related to the Empire Connector project, costs, which is discussed below under Estimated Capital Expenditures,was placed into service on December 10, 2008, as well as for additions, improvements, and replacements to this segment’s transmission and gas storage systems. The majority of the Pipeline and Storage segment’s capital expenditures for 2007 were made for additions, improvements, and replacements to this segment’s transmission and gas storage systems. The Empire Connector project was completed for a cost of approximately $192 million. The Company capitalized Empire Connector project costs of $27.3 million, $149.2 million and $15.5 million for the years ended September 30, 2009, 2008 and 2007, respectively.
 
Exploration and Production
 
In 2009, the Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $18.3 million for the Gulf Coast region, substantially all of which was for the off-shore program in the shallow waters of the Gulf of Mexico, $31.4 million for the West Coast region and $138.6 million for the Appalachian region. These amounts included approximately $24.2 million spent to develop proved undeveloped reserves.
In July 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, purchased Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition includes $2.0 million held in escrow at September 30, 2009. Seneca placed this amount in escrow as part of the purchase price, and in accordance with the purchase agreement, this amount will remain in escrow for one year from the closing of the transaction provided there are no pending disputes or actions regarding obligations and liabilities required to be satisfied or discharged by Ivanhoe Energy. This purchase complements the segment’s existing oil producing assets in the Midway Sunset Field in California. This acquisition was funded with cash on hand.
In 2008, the Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $63.6 million for the Gulf Coast region, substantially all of which was for the off-shore program in the shallow waters of the Gulf of Mexico, $62.8 million for the West Coast region and $65.8 million for the Appalachian region. These amounts included approximately $25.4 million spent to develop proved undeveloped reserves. The Appalachian region capital expenditures include $2.4 million for the purchase of storage facilities, buildings, and base gas from Supply Corporation, as shown in the table above.
 
In 2007, the Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $66.2 million for the Gulf Coast region, substantially all of which was for the off-shore program in the Gulf of Mexico, $41.4 million for the West Coast region and $39.1 million for the Appalachian region. These amounts included approximately $30.3 million spent to develop proved undeveloped reserves.


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TimberAll Other and Corporate
 
TheIn 2009, the majority of the Timber segmentAll Other and Corporate category’s expenditures for long-lived assets were for the construction of Midstream Corporation’s Covington Gathering System, as discussed below. Expenditures for long-lived assets for 2009 also included a $1.3 million capital contribution made by NFG Midstream Processing, LLC in the Whitetail Processing plant, as discussed below.
In 2008, the majority of the All Other and Corporate category’s expenditures for long-lived assets were for construction of a lumber sorter for Highland’s sawmill operations that was placed into service in October 2007, as well as for purchases of equipment for Highland’s sawmill and kiln operations.


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All Other and Corporate
In March 2008, Additionally, Horizon Power sold a gas-powered turbine in March 2008 that it had planned to use in the development of a co-generation plant. Horizon Power received proceeds of $5.3 million and recorded a pre-tax gain of $0.9 million associated with the sale.
 
In 2007, the All Other and Corporate category expenditures for long-lived assets included a $3.3 million capital contribution to Seneca Energy by Horizon Power. Seneca Energy generates and sells electricity using methane gas obtained from landfills owned by outside parties. Horizon Power funded its capital contributions with short-term borrowings. Additionally, the All Other and Corporate category expenditures for long-lived assets also were for the construction of two new kilns that were placed into service during the quarter ended June 30, 2007, as well as construction of a lumber sorter for Highland’s sawmill operations.
Estimated Capital Expenditures
 
The Company’s estimated capital expenditures for the next three years are:
 
                        
 Year Ended September 30  Year Ended September 30 
 2009 2010 2011  2010 2011 2012 
 (Millions)    (Millions)   
Utility $58.0  $60.0  $56.0  $60.0  $58.0  $58.0 
Pipeline and Storage  73.0   76.0   46.0   51.0   227.0   240.0 
Exploration and Production(1)  285.0   227.0   244.0   255.0   417.0   497.0 
Timber  1.0   1.0   1.0 
All Other  47.0   21.0   21.0 
              
 $417.0  $364.0  $347.0  $413.0  $723.0  $816.0 
              
 
 
(1)Includes estimated expenditures for the years ended September 30, 2009, 2010, 2011 and 20112012 of approximately $48 million, $42 million, $56 million and $18$28 million, respectively, to develop proved undeveloped reserves.
 
Utility
Estimated capital expenditures for the Utility segment in 20092010 will be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment.
 
Pipeline and Storage
Estimated capital expenditures for the Pipeline and Storage segment in 20092010 will be concentrated on the completion of the Empire Connector project as discussed below, the replacement of transmission and storage lines, the reconditioning of storage wells and improvements of compressor stations.
 
The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. Construction of the Empire Connector, a pipeline designed to transport up to approximately 250 MDth of natural gas per day that will connect the Empire Pipeline with the Millennium Pipeline, began in September 2007. The Empire Connector is anticipated to be ready to commence service in December 2008, on or before the in-service date of the Millennium Pipeline. Refer to the Rate and Regulatory Matters section that follows for further discussion of this matter. The total cost to the Company of the Empire Connector project is estimated at $187 million, after giving effect to sales tax exemptions worth approximately $3.7 million. As of September 30, 2008, the Company had incurred approximately $164.7 million in costs related to this project. Of this amount, $145.0 million, $13.7 million and $2.0 million were incurred during the years ended September 30, 2008, 2007 and 2006, respectively. All project costs incurred as of September 30, 2008 have been capitalized as Construction Work in Progress. The Company anticipates financing the remaining cost of this project with cash from operations.
In light of the rapidly growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus Shale producing area — Supply Corporation recently completedand Empire are actively pursuing several expansion projects. Supply Corporation is moving forward with two strategic compressor horsepower expansions, both supported by signed precedent agreements with Appalachian producers, designed to move anticipated Marcellus production gas to markets beyond Supply Corporation’s pipeline system.
The first strategic horsepower expansion project involves new compression along Supply Corporation’s Line N, increasing that line’s capacity into Texas Eastern’s Holbrook Station in southwestern Pennsylvania


47

(“Line N Expansion Project”). This project is designed and contracted for 150,000 Dth/day of firm transportation, and will allow anticipated Marcellus production located in the vicinity of Line N to flow south and access markets off Texas Eastern’s system, with a projected in-service date of November 2011. Supply Corporation is in the process of preparing an Open SeasonNGA Section 7(c) application to the FERC for approval of the Line N Expansion Project. The preliminary cost estimate for the Line N Expansion Project is $23 million. The forecasted expenditures for this project over the next three years are as follows: $0.9 million in 2010, $18.5 million in 2011, and $3.6 million in 2012. These expenditures are included as Pipeline and Storage estimated capital expenditures in the table above. As of September 30, 2009, less than $0.1 million has been spent to study the Line N Expansion Project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2009.
The second strategic horsepower expansion project involves the addition of compression at Supply Corporation’s existing interconnect with Tennessee Gas Pipeline at Lamont, Pennsylvania, with a projected in-service date of May 2010 (“Lamont Project”). The Lamont Project is designed and contracted for 40,000 Dth/day of firm transportation and will afford shippers a transportation path from their anticipated Marcellus production located in Elk and Cameron Counties, Pennsylvania to markets attached to Tennessee Gas Pipeline’s 300 Line. The Lamont Project will not require an NGA Section 7(c) application, and will instead be constructed under Supply Corporation’s existing blanket construction certificate authority from the FERC. The preliminary cost estimate for the Lamont Project is $6 million, all of which is forecasted to occur in 2010. These expenditures are included as Pipeline and Storage estimated capital expenditures in the table above. As of September 30, 2009, less than $0.1 million has been spent to study the Lamont Project, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2009.
In addition, Supply Corporation continues to actively pursue its largest planned expansion, theWest-to-East/Appalachian Lateral (“AppLat”) pipeline project. The AppLatAppalachian Lateral project is expected to be routed through areas in Pennsylvania where producers are actively drilling and are seeking market access for their newly discovered reserves. The AppLatAppalachian Lateral will complement Supply’sSupply Corporation’s original West to East (“W2E”) project, which was designed to transport Rockies gas supply from Clarington, Ohio to the Ellisburg/Leidy/Corning area and includes the Tuscarora-to-Corning facilities previously referred to as the Tuscarora Extension.area. The AppLatAppalachian Lateral will transport gas supply from Pennsylvania’s producing area to the Overbeck area of Supply Corporation’s existing system, wherefrom which some of the facilities associated with the W2E project will move the gas to eastern market points, including Leidy, Pennsylvania, and to interconnections with Millennium and Empire at Corning.Corning, New York. Preliminary engineering routing analysis, project cost estimate and rate design have been completed, and prospective shippers have been offered precedent agreements for their consideration. This project will require an NGA Section 7(c) application, which Supply Corporation has not filed. The capital cost of all phases of the Appalachian Lateral/W2E transportation projects is estimated to be in the range of $750 million to $1 billion. As of September 30, 2009, approximately $0.6 million has been spent to study the Appalachian Lateral/W2E transportation projects, which has been included in preliminary survey and investigation charges and has been fully reserved for at September 30, 2009.
Supply Corporation anticipates the development of the W2E/Appalachian Lateral project will occur in phases, and based on requests from the Marcellus producing community for transportation service commencing as early as 2011, Supply Corporation began a binding Open Season on August 26, 2009. This Open Season offered transportation capacity on two initial phases (“Phase I” and “Phase II”) of the W2E pipeline project. The capital cost of these two phases is estimated to be $257 million. Phase I is designed to transport approximately 200,000 Dth/day from the Marcellus producing area through a new32-mile pipeline to be constructed through Elk, Cameron, and Clinton Counties to the Leidy Hub, with an anticipated in-service date of late 2011. Phase II, with a late 2012 projected in-service date, consists of an additional 50 miles of new pipeline and compression extending through Clearfield and Jefferson Counties to Supply Corporation’s Line K system and would provide additional transportation capacity of at least 300,000 Dth/day. The forecasted expenditures for Phase I and Phase II of this project over the next three years are as follows: $6.0 million in 2010, $108.0 million in 2011, and $143.0 million in 2012. These expenditures are included as Pipeline and Storage estimated capital expenditures in the table above.
This binding Open Season concluded on October 8, 2009 with significant participation by Marcellus producers. Supply Corporation received binding requests for 175,000 Dth/day of firm transportation capacity


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and expects to execute the signed precedent agreements submitted by those Marcellus producers. Supply Corporation is pursuing post-Open Season capacity requests for the remaining Phase I and Phase II capacity and expects to continue marketing efforts for all sections of the W2E and Appalachian Lateral projects. The timeline associated with the W2E and Appalachian Lateral projects will depend on market development.
 
In conjunction with the W2EAppalachian Lateral and AppLatW2E transportation projects, Supply Corporation has plans to develop new storage capacity by pursuing expansion ofexpanding certain of its existing storage facilities. The expansion of these


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fields which Supply Corporation is marketing through a recently completed Open Season concurrent with its AppLat Open Season, could provide incremental storage capacity of approximately 8.5 MMDth of incremental storage capacity withand incremental withdrawal deliverability of up to 121 MDth of natural gas per day, with service commencing asin early as 2011.2013. Supply Corporation expects that the availability of this incremental storage capacity will complement the Appalachian Lateral/W2E and AppLat pipeline transportation projects and help meetbalance the demand for storage created by the prospective increasedincreasing flow of Appalachian and Rockies gas supply intothrough the western Pennsylvania area, although traditionaland the growing demand for gas supplieson the east coast. This storage expansion project will also be able to take advantage of this incrementalrequire an NGA Section 7(c) application, which Supply Corporation has not yet filed. Preliminary cost estimates for the storage capacity.
The timeline associated with Supply Corporation’s pipeline and storage projects depends on market development. The capital cost of the AppLat/W2Eexpansion project is $78 million. The forecasted expenditures for this project over the next three years are as follows: $0.4 million in 2010, $0.2 million in 2011, and $67.1 million in 2012. These expenditures are included as Pipeline and Storage estimated to be approximately $800 million, and is expected to be financed by a combination of debt and equity.capital expenditures in the table above. As of September 30, 2008, $0.2 million has been spent to study the W2E and AppLat projects, and2009, approximately $0.6$1.0 million has been spent to study the storage expansion project. Costs associated with these projects haveproject, which has been included in preliminary survey and investigation charges and havehas been fully reserved for at September 30, 2008. Supply Corporation has not yet filed2009. The timeline associated with the W2E and Appalachian Lateral projects and any related storage development will depend on market development.
On October 1, 2009, Empire posted an Open Season for an expansion project that will provide at least 200,000 Dth/day of incremental firm transportation capacity from anticipated Marcellus production at new and existing interconnection(s) along its recently completed Empire Connector line and along a proposed16-mile 24” pipeline extension into Tioga County, Pennsylvania. Empire’s preliminary cost estimate for the Tioga County Extension Project is approximately $43 million. This project would enable Marcellus producers to deliver their gas at existing Empire interconnections with Millennium Pipeline at Corning, New York, with TransCanada Pipeline at Chippawa, and with utility and power generation markets along its path, as well as to a planned new interconnection with Tennessee Gas Pipeline’s 200 Line (Zone 5) in Ontario County, New York. Empire completed a non-binding Open Season on October 23, 2009 for capacity in the Tioga County Extension Project, and is in the process of negotiating binding precedent agreements with shippers who participated in the Open Season, representing more than adequate capacity to support the project facilities. Following successful negotiations, Empire will file an NGA Section 7(c) application with the FERC for approval of this project, and anticipates that these facilities will be placed in-service on or after September 1, 2011. The forecasted expenditures for this project over the authority to build either pipelinenext two years are as follows: $2.0 million in 2010 and $41.0 million in 2011. These expenditures are included as Pipeline and Storage estimated capital expenditures in the table above. As of September 30, 2009, no preliminary survey and investigation charges had been expended on this project, orbut those activities began in October of 2009 and will be fully reserved in the periods they occur. The timeline associated with the Tioga County Extension Project will depend on the completion of shipper precedent agreements.
The Company anticipates financing the Line N Expansion Project, the Lamont Project, Phase I and Phase II of the W2E/Appalachian Lateral project, the storage expansion.expansion project, and the Tioga County Extension Project, all of which are discussed above, with a combination of cash from operations, short-term debt, and long-term debt.
Exploration and Production
 
Estimated capital expenditures in 20092010 for the Exploration and Production segment include approximately $35.0$14.0 million for the Gulf Coast region, substantially all of which is for the off-shore program in the Gulf of Mexico, $53.6$17.0 million for the West Coast region and $196.3$224.0 million for the Appalachian region. The Company anticipates drilling 55 to 75 gross wells in the Marcellus Shale during 2010.
 
Estimated capital expenditures in 20092011 for the Exploration and Production segment include approximately $5.0 million for the Gulf Coast region, substantially all of which is for the off-shore program in the TimberGulf of


49

Mexico, $27.0 million for the West Coast region and $385.0 million for the Appalachian region. The Company anticipates drilling 100 to 130 gross wells in the Marcellus Shale during 2011.
Estimated capital expenditures in 2012 for the Exploration and Production segment include approximately $12.0 million for the Gulf Coast region, substantially all of which is for the off-shore program in the Gulf of Mexico, $41.0 million for the West Coast region and $444.0 million for the Appalachian region. The Company anticipates drilling 120 to 150 gross wells in the Marcellus Shale during 2012.
All Other and Corporate
Estimated capital expenditures in 2010 for the All Other and Corporate category will primarily be concentrated onfor the purchaseconstruction of new equipment, vehiclesanticipated gathering systems, including the construction of Midstream Corporation’s Covington Gathering System, as discussed below.
NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, is constructing a gathering system in Tioga County, Pennsylvania. The project, called the Covington Gathering System, is to be constructed in two phases. The first phase was completed and improvementsplaced in service in November 2009. The second phase is anticipated to facilities forbe placed in service in 2010. When completed, the system will consist of approximately 15 miles of gathering system at a cost of $15 million to $18 million. As of September 30, 2009, the Company has spent approximately $8.1 million in costs related to this segment’s lumber yard, sawmill and kiln operations.project.
NFG Midstream Processing, LLC, another wholly owned subsidiary of Midstream Corporation, has a 35% ownership in the Whitetail Processing Plant. The plant is currently under construction with completion expected in the fall of 2009. The total project cost is estimated at $4 million. Once completed, the plant will extract natural gas liquids from local production. As of September 30, 2009, the Company invested $1.3 million related to the construction of the plant.
The Company anticipates funding the Midstream Corporation projects with cash from operationsand/or short-term borrowings.
 
The Company continuously evaluates capital expenditures and investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber or natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.
 
FINANCING CASH FLOW
 
The Company did not have any outstanding short-term notes payable to banks or commercial paper at September 30, 2008.2009. However, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporationsand/or partnerships,gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which aggregate to $420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million that extends through September 30, 2010.
 
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At September 30, 2008,2009, the Company’s debt to capitalization ratio (as calculated under the facility) was .41..44. The constraints specified in the


50

committed credit facility would permit an additional $1.88$1.7 billion in short-termand/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could


48

borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations. At September 30, 2009, the Company’s long-term debt ratings were: BBB (S&P), Baa1 (Moody’s Investor Service), and A- (Fitch Ratings Service). At September 30, 2009, the Company’s commercial paper ratings were:A-2 (S&P),P-2 (Moody’s Investor Service), and F2 (Fitch Ratings Service).
 
Under the Company’s existing indenture covenants, at September 30, 2008,2009, the Company would have been permitted to issue up to a maximum of $1.3 billion$435.0 million in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience another impairment of oil and gas properties in the future, it is possible that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness. This would not preclude the Company from issuing new indebtedness to replace maturing debt.
 
The Company’s 1974 indenture, pursuant to which $199.0$99.0 million (or 18%7.9%) of the Company’s long-term debt (as of September 30, 2008)2009) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
 
The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2008,2009, the Company had no debt outstanding under the committed credit facility.
 
The Company’s embedded cost of long-term debt was 6.95% at September 30, 2009 and 6.5% at September 30, 2008 and 6.4% at September 30, 2007.2008. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
 
In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private placement exempt from registration under the Securities Act of 1933. In February 2009, the Company exchanged the notes for economically identical notes registered under the Securities Act of 1933. The notes have a term of 10 years, with a maturity date in April 2018. The holders of the notes may require the Company to repurchase their notes in the event of a change in control at a price equal to 101% of the principal amount. In addition,amount in the Company is requiredevent of both a change in control and a ratings downgrade to either offer to exchange the notes for substantially similar notes as are registered under the Securities Act of 1933 or, in certain circumstances, register the resale of the notes.a rating below investment grade. The Company used $200.0 million of the proceeds of the issuance to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008. In November 2008 the Company filed a registration statement with the SEC in connection with the Company’s plan to offer to exchange the notes for substantially similar registered notes. The Company will seek to have the SEC declare the registration statement effective as of a date coinciding with or following the date of this report.
 
In April 2009, the Company issued $250.0 million of 8.75% notes due in March 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. These notes were registered under the Securities Act of 1933. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company’s 6.0% medium-term notes on March 1, 2009. After this debt issuance, the Company’s


51

embedded cost of long-term debt increased from 6.5% to 6.95%. If the Company were to issue long-term debt today, its borrowing costs might be expected to be in the range of 6.0% to 7.0% depending on their maturity date.
On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company maycould repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares.shares of the Company’s common stock. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, suchSuch repurchases may be maderesume in the future if conditions improve. Allfuture. The share repurchases mentioned above were funded with cash provided by operating activitiesand/or through the use of the Company’s lines of credit.
 
The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.


49

OFF-BALANCE SHEET ARRANGEMENTS
 
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $32.3$27.8 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $3.0 million. The Company has guaranteed 50%, or $1.5 million, of these capital lease commitments.
 
CONTRACTUAL OBLIGATIONS
 
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2008,2009, and the twelve-month periods over which they occur:
 
                                                       
 Payments by Expected Maturity Dates  Payments by Expected Maturity Dates
 2009 2010 2011 2012 2013 Thereafter Total  2010 2011 2012 2013 2014 Thereafter Total
 (Millions)        (Millions)    
Long-Term Debt, including interest expense(1) $167.5  $65.0  $252.2  $191.4  $282.3  $565.0  $1,523.4  $86.9  $274.0  $213.2  $304.2  $48.7  $888.5  $1,815.5 
Operating Lease Obligations $6.0  $4.6  $3.6  $3.2  $2.5  $12.4  $32.3  $5.4  $3.9  $3.3  $2.4  $2.3  $10.5  $27.8 
Capital Lease Obligations $0.5  $0.4  $0.4  $0.2  $—  $—  $1.5 
Purchase Obligations:                                                 
Gas Purchase Contracts(2) $745.8  $122.3  $14.5  $10.3  $10.3  $83.8  $987.0  $478.0  $63.0  $29.2  $6.7  $6.7  $49.3  $632.9 
Transportation and Storage Contracts $47.4  $45.7  $41.1  $36.7  $11.3  $16.9  $199.1  $42.2  $38.8  $37.4  $33.5  $33.1  $27.0  $212.0 
Empire Connector Project Obligations $13.5  $—  $—  $—  $—  $—  $13.5 
Other $12.4  $10.5  $4.2  $4.0  $3.5  $12.6  $47.2  $25.1  $9.0  $4.1  $3.4  $3.3  $12.0  $56.9 
 
 
(1)Refer to Note E — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense.
 
(2)Gas prices are variable based on the NYMEX prices adjusted for basis.
 
The Company has other long-term obligations recorded on its Consolidated Balance Sheets that are not reflected in the table above. Such long-term obligations include pension and other post-retirement liabilities, asset retirement obligations, deferred income tax liabilities, various regulatory liabilities, derivative financial instrument liabilities and other deferred credits (the majority of which consist of liabilities for a non-qualified benefit plan, deferred compensation liabilities, environmental liabilities, workers compensation liabilities and liabilities for income tax uncertainties).


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The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the consolidated balance sheetConsolidated Balance Sheets in accordance with SFAS 133the authoritative guidance (see Item 7, MD&A under the heading “Critical Accounting Estimates — Accounting for Derivative Financial Instruments”); (ii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts due on those obligations each month are included on the consolidated balance sheetConsolidated Balance Sheets as a current liability; and (iii) other obligations which are reflected on the consolidated balance sheet.Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them in the table above.
 
OTHER MATTERS
 
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note HI — Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
 
The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) that covers a majority of the Company’s employees. The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it will continue making contributions to the Retirement Plan. During 2008,2009, the Company contributed $16.0 million to the Retirement Plan. The Company anticipates that the


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annual contribution to the Retirement Plan in 20092010 will be in the range of $15.0$20.0 million to $20.0$30.0 million. As a result of the recent downturn in the stock markets and general economic conditions, itIt is likely that the Company will have to fund larger amounts to the Retirement Plan subsequent to 20092010 in order to be in compliance with the Pension Protection Act of 2006. The Company expects that all subsidiaries having employees covered by the Retirement Plan will make contributions to the Retirement Plan. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through short-term borrowings or through cash from operations.
 
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and 401(h) accounts over the last several years and anticipates that it will continue making contributions to the VEBA trusts and 401(h) accounts. During 2008,2009, the Company contributed $29.1$25.5 million to its VEBA trusts and 401(h) accounts. The Company anticipates that the annual contribution to its VEBA trusts and 401(h) accounts in 20092010 will be in the range of $25.0 million to $30.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments.
 
As of September 30, 2009, the Company recorded a deferred tax asset relating to a federal net operating loss carryover of $25.1 million. This carryover, which is available as a result of an acquisition, expires in varying amounts between 2023 and 2029. Although this loss carryover is subject to certain annual limitations, no valuation allowance was recorded because of management’s determination that the amount will be fully utilized during the carryforward period.
MARKET RISK SENSITIVE INSTRUMENTS
 
Energy Commodity Price Risk
 
The Company, in its Exploration and Production segment, Energy Marketing segment and Pipeline and Storage segment, and All Other category, uses various derivative financial instruments (derivatives), including price swap agreements no cost collars and futures contracts, as part of the Company’s overall energy commodity price risk management strategy. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price


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of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 20082009 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.
Beginning in fiscal 2009, the Company adopted the authoritative guidance for fair value measurements. In accordance with the adoption of this guidance, the Company has identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level 3 derivative assets relate to oil swap agreements used to hedge forecasted sales at a specific location (southern California). The Company’s internal model that is used to calculate fair value applies a historical basis differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to this sales location. Given the high level of historical correlation between NYMEX prices and prices at this sales location, the Company does not believe that the fair value recorded by the Company would be significantly different from what it expects to receive upon settlement. The fair value of the Level 3 derivative assets was reduced by $0.7 million based upon the Company’s assessment of counterparty credit risk. The Company applied default probabilities to the anticipated cash flows that it was expecting from its counterparties to calculate the credit reserve.
The Level 3 assets amount to $27.0 million at September 30, 2009 and represent 60.2% of the Derivative Financial Instruments Assets or 5.9% of the Total Assets as shown in Item 8 at Note F — Fair Value Measurements at September 30, 2009.
During fiscal 2009, the Company transferred $8.1 million of derivative assets from Level 3 assets to Level 2 assets. The majority of these assets related to natural gas swaps on southern California natural gas production. The Company also transferred $0.8 million of derivative liabilities from Level 3 liabilities to Level 2 liabilities. These liabilities related to certain natural gas swaps on Gulf of Mexico natural gas production. These transfers occurred because the Company was able to obtain and utilize forward-looking, observable basis differential information for the hedges at these locations.
The Company uses the crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative assets (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of the existing guidance for derivative instruments and hedging activities.
The increase in the net fair value of the Level 3 positions from October 1, 2008 to September 30, 2009, as shown in Item 8 at Note F, was attributable to a significant decrease in the commodity price of crude oil during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at September 30, 2009.
 
The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2008.2009. At September 30, 2008,2009, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2011.2012.
 
Natural Gas Price Swap Agreements
 
                                
 Expected Maturity Dates    Expected Maturity Dates   
 2009 2010 2011 Total  2010 2011 2012 Total 
Notional Quantities (Equivalent Bcf)  11.8   3.3   0.0(1)  15.1   16.3   12.9   8.8   38.0 
Weighted Average Fixed Rate (per Mcf) $9.35  $10.89  $10.55  $9.69  $6.91  $7.22  $7.48  $7.15 
Weighted Average Variable Rate (per Mcf) $8.10  $8.74  $9.30  $8.24  $6.15  $7.34  $7.56  $6.88 
(1)The Energy Marketing segment has natural gas swap agreements covering approximately 40,000 Mcf in 2011.


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Of the total Bcf above, 0.6 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $8.08 per Mcf. The remaining 37.4 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $7.13 per Mcf.
 
Crude Oil Price Swap Agreements
 
                                
 Expected Maturity Dates    Expected Maturity Dates  
 2009 2010 2011 Total  2010 2011 2012 Total
Notional Quantities (Equivalent bbls)  1,260,000   600,000   60,000   1,920,000   1,692,000   648,000   348,000   2,688,000 
Weighted Average Fixed Rate (per bbl) $83.12  $102.52  $125.25  $90.50  $74.59  $66.54  $62.95  $71.14 
Weighted Average Variable Rate (per bbl) $103.08  $104.17  $105.21  $103.49  $59.38  $62.63  $64.30  $60.80 
 
At September 30, 2008,2009, the Company would have received from its respective counterparties an aggregate of approximately $20.3$10.4 million to terminate the natural gas price swap agreements outstanding at that date. The Energy Marketing segment also used natural gas swaps to hedge basis risk on their fixed price purchase commitments. At September 30, 2008, the Company had natural gas basis swap agreements covering 1.4 Bcf at a weighted average fixed rate of $0.47 (per Mcf) and a weighted average variable rate of $0.64 (per Mcf). These natural gas swap agreements are treated as fair value hedges and the Company would have had to pay $0.2 million at September 30, 2008 to terminate the agreements. The Company would have had to payreceived from its respective counterparties an aggregate of approximately $0.8$27.0 million to its counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2008.2009.
 
At September 30, 2007,2008, the Company had natural gas price swap agreements covering 13.215.1 Bcf at a weighted average fixed rate of $8.20$9.69 per Mcf. The Company also had crude oil price swap agreements covering 1,485,0001,920,000 bbls at a weighted average fixed rate of $57.35$90.50 per bbl.
 
The following table discloses the net contract volumesvolume purchased (sold), weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2008,2009, the Company held no futures contracts with maturity dates extending beyond 2012.
 
Futures Contracts
 
                                    
 Expected Maturity Dates  Expected Maturity Dates 
 2009 2010 2011 2012 Total  2010 2011 2012 Total 
Net Contract Volumes Purchased (Sold)
(Equivalent Bcf)		  2.1   0.3   —(1)  —(1)  2.4 
Net Contract Volume Purchased (Sold) (Equivalent Bcf)  3.9   1.0   —(1)  4.9 
Weighted Average Contract Price (per Mcf) $10.02  $9.59  $8.05  $8.68  $9.99  $6.72  $7.02  $8.15  $6.74 
Weighted Average Settlement Price (per Mcf) $9.41  $9.85  $7.49  $8.27  $9.43  $6.42  $6.84  $8.77  $6.45 
 
 
(1)The Energy Marketing segment has purchased 7 and 611 futures contracts (1 contract = 2,500 Dth) for 2011 and 2012, respectively.2012.
 
At September 30, 2008,2009, the Company had long (purchased) futures contracts covering 11.6 Bcf of gas extending through 2012 at a weighted average contract price of $6.37 per Mcf and a weighted average settlement price of $6.07 per Mcf. They are accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed to due to the fixed price gas sales commitments that it enters into with residential, commercial and industrial customers. The Company would have had to pay $3.5 million to terminate these futures contracts at September 30, 2009.
At September 30, 2009, the Company had short (sold) futures contracts covering 6.7 Bcf of gas extending through 2011 at a weighted average contract price of $7.37 per Mcf and a weighted average settlement price of $6.07 per Mcf. Of this amount, 5.8 Bcf is accounted for as cash flow hedges as these contracts relate to the anticipated sale of natural gas by the Energy Marketing segment. The remaining 0.9 Bcf is accounted for as fair value hedges used to hedge against falling prices, a risk to which the Energy Marketing segment is exposed to due to the fixed price gas purchase commitments that it enters into with its natural gas suppliers. The Company would have received $8.7 million to terminate these futures contracts.contracts at September 30, 2009.
 
At September 30, 2007,2008, the Company had futures contracts covering 2.82.4 Bcf (net long position) at a weighted average contract price of $9.11$9.99 per Mcf.
 
The Company may be exposed to credit risk on someany of the derivatives disclosed above.derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management


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performs a credit check, and then on an ongoinga quarterly basis monitors counterparty credit exposure. Management has obtained guarantees from manyThe majority of the parent companies of the respectiveCompany’s counterparties to its derivatives.are financial institutions and energy traders. The Company hasover-the-counter swap positions with ten counterparties. At September 30, 2008,2009, the Company had eleven counterparties for its over the counter derivative financial instruments and no individual counterparty represented greater than 42% of total credit risk (measured as volumes hedged by an individual counterparty as a percentagethat were in gain positions with eight of the Company’s total over the counter volumes hedged).counterparties. The Company recordedhad derivative financial instruments that were in loss positions with the other two counterparties. The Company had $26.6 million of credit exposure with one counterparty (which is rated A1 (Moody’s Investor Service), A (S&P), and A+ (Fitch Ratings Service) as of September 30, 2009). On average for those financial instruments that were in a $0.6gain position, the Company had $1.8 million reductionof credit exposure per counterparty with the other seven counterparties that were in a gain position. The Company had not received any collateral from the counterparties at September 30, 2009 since the Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
As of September 30, 2009, eight of the ten counterparties to the fair market valueCompany’s outstanding derivative instrument contracts (specifically theover-the-counter swaps) had a common credit-risk-related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (the lower of the S&P or Moody’s Debt Rating), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position and the Company’s credit rating declined, then additional hedging collateral deposits would be required. At September 30, 2009, these credit-risk related contingency features were not triggered since the Company had assets of $37.9 million related to derivative financial instruments with the eight counterparties.
For its exchange traded futures contracts, which are in an asset position, the Company had paid $0.8 million in hedging collateral as of September 30, 2009. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on its assessment of counterparty credit risk. This credit reserve was determined by applying default probabilities to the anticipated cash flowsopen positions (i.e. those positions that the Companyhave been settled for cash) and margin requirements. (This is expecting from its counterparties.discussed in Note A under Hedging Collateral Deposits.)


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Interest Rate Risk
 
The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt as well as the other long-term debt of certain of the Company’s subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2008:2009:
 
                                                     
 Principal Amounts by Expected Maturity Dates  Principal Amounts by Expected Maturity Dates 
 2009 2010 2011 2012 2013 Thereafter Total  2010 2011 2012 2013 2014 Thereafter Total 
 (Dollars in millions)    (Dollars in millions) 
Long-Term Fixed Rate Debt $100.0(1) $—  $200.0  $150.0  $250.0  $399.0  $1,099.0  $—  $200.0  $150.0  $250.0  $—  $649.0  $1,249.0 
Weighted Average Interest Rate Paid  6.0%  —   7.5%  6.7%  5.3%  6.7%  6.5%  —   7.5%  6.7%  5.3%  —   7.5%  7.0%
Fair Value of Long-Term Fixed Rate Debt = $1,027.1                            
Fair Value of Long-Term Fixed Rate Debt = $1,347.4                            
(1)These notes have been classified as Current Portion of Long-Term Debt on the Company’s Consolidated Balance Sheet.
 
RATE AND REGULATORY MATTERS
 
Utility Operation
 
Base rate adjustments 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 of the appropriate regulatory authorities.
 
New York Jurisdiction
 
On January 29, 2007,Customer delivery rates charged by Distribution Corporation commencedCorporation’s New York division were established in a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million. Following standard procedure, the NYPSC suspended the proposed tariff amendments to enable its staff and intervenors to conduct a routine investigation and hold hearings. Distribution Corporation explained in the filing that its request for rate relief was necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also included a proposal for an efficiency and conservation initiative with a revenue decoupling mechanism designed to render the Company indifferent to throughput reductions resulting from conservation. On September 20, 2007, the NYPSCorder issued an order approving, with modifications, Distribution Corporation’s conservation program for implementation on an accelerated basis. Associated ratemaking issues, however, were reserved for consideration in the rate.
On December 21, 2007 by the NYPSC issued aNYPSC. The rate order providing for an annual rateapproved a revenue increase of $1.8 million


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annually, together with a monthly bill surcharge that would collect up to $10.8 million to recover expenses for implementation of thean efficiency and conservation incentive program. The rate increase and bill surcharge became effective December 28, 2007. The rate order further provided for a return on equity of 9.1%. TheIn connection with the efficiency and conservation program, the rate order also adopted Distribution Corporation’s proposed revenue decoupling mechanism. The revenue decoupling mechanism, like others, “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. The Company surcharges or credits any difference from the average weather normalized usage per customer account. The surcharge or credit is calculated to recover total margin for the most recent twelve-month period ending December 31, and is applied to customer bills annually, beginning March 1st.
 
On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal contends that portions of the rate order should be invalidated because they fail to meet the applicable legal standard for agency decisions. Among the issues challenged by the Company are the reasonableness of the NYPSC’s disallowance of expense items including health care costs, and the


53

methodology used for calculating rate of return, which the appeal contends understated the Company’s cost of equity. Briefs were filed and oral argument was held on October 14, 2009. The Company cannot predict the outcome of the appeal at this time.
 
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the current rate ofone-third of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge equal, as applied, to an additional one percent of the utility’s gross operating revenue. As a result of this amendment, Distribution Corporation’s New York Division paid a total assessment of $26.2 million during fiscal 2009, of which $22.9 million was labeled as the temporary surcharge. The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills.
Pennsylvania Jurisdiction
 
On June 1, 2006, Distribution Corporation filed proposed tariff amendments with PaPUC to increase annual revenues by $25.9 million to cover increases in the cost of service to be effective July 30, 2006. The rate request was filed to address increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and suspending the proposed tariff amendments until March 2, 2007. On October 2, 2006, the parties, including Distribution Corporation, Staff of the PaPUC and intervenors, executed an agreement (Settlement) proposing to settle all issues in the rate proceeding. The Settlement included an increase in annual revenues of $14.3 million to non-gas revenues, an agreementcurrently does not to filehave a rate case until January 28, 2008 aton file with the earliest and an early implementation date. The SettlementPaPUC. Distribution Corporation’s current tariff in its Pennsylvania jurisdiction was last approved by the PaPUC at its meeting on November 30, 2006 and the new ratesas part of a settlement agreement that became effective January 1, 2007.
 
Pipeline and Storage
 
Supply Corporation currently does not have a rate case on file with the FERC. The rate settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general rate filing before then, with some exceptions specified in the settlement.
 
Empire currently does not have a rate case on file with the NYPSC. Among the issues resolved in connection with Empire’s FERC application to build thenew facilities (the Empire Connector are the rates and terms of service that will become applicable to all of Empire’s business, effective upon Empire constructing and placing its new facilitiesproject) were placed into service (currently expected foron December 2008). At10, 2008. As of that time,date, Empire will becomebecame an interstate pipeline subject to FERC regulation.regulation, performing services under a FERC-approved tariff and at FERC-approved rates. The December 21, 2006 FERC order described in the following paragraphissuing Empire its Certificate of Public Convenience and Necessity requires Empire to makefile a filingcost and revenue study at the FERC, within three years after the in-service date, justifyingin conjunction with which Empire will either justify Empire’s existing recourse rates or proposingpropose alternative rates.
On December 21, 2006, the FERC issued an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. The Empire Certificate contains various environmental and other conditions. Empire accepted that Certificate and received additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies. Empire also received, from all six upstate New York counties in which it will build the Empire Connector project, final approval of sales tax exemptions and temporary partial property tax abatements. In June 2007, Empire signed a firm transportation service agreement with KeySpan Gas East Corporation, under which Empire is obligated to provide transportation service that required construction of this project. Construction began in September 2007 and is anticipated to be ready to commence service in December 2008, on or before the in-service date of the Millennium Pipeline to which it will connect.
 
ENVIRONMENTAL MATTERS
 
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmentalclean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2008,2009, the Company has estimated its remainingclean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $19.4$18.7 million to $23.6$22.9 million. The


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minimum estimated liability of $19.4$18.7 million has been recorded on the Consolidated Balance Sheet at September 30, 2008.2009. The Company expects to recover its environmentalclean-up costs from a combination


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of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet. Other than discussed in Note HI (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
 
For further discussion refer to Item 8 at Note HI — Commitments and Contingencies under the heading “Environmental Matters.”
 
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussions. If enacted or adopted, legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Proposed measures could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
NEW AUTHORITATIVE ACCOUNTING PRONOUNCEMENTSAND FINANCIAL REPORTING GUIDANCE
 
In September 2006, the FASB issued SFAS 157. SFAS 157 providesauthoritative guidance for using fair value to measure assets and liabilities. The pronouncementThis guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157This guidance is to be applied whenever another standard requires or allows assets or liabilities are to be measured at fair value. In accordance with FASB Staff PositionFAS No. 157-2, SFAS 157 is effectiveOn October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The same FASB Staff Positionbasis. This guidance delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of the authoritative guidance for financial assets and financial liabilities, refer to Item 8 at Note F — Fair Value Measurements. The Company does not expectis currently evaluating the impact that SFAS 157the adoption of the authoritative guidance for nonfinancial assets and nonfinancial liabilities will have a significant impact on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of this guidance. The Company does not believe there are any nonfinancial liabilities that will be impacted by the adoption of this guidance.
 
In September 2006, the FASB also issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158authoritative guidance which requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncementThis guidance requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. This guidance also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158,this authoritative guidance, the Company has recognized the funded status of its benefit plans and implemented the related disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will bewas fully adopted by the Company by the endas of fiscalSeptember 30, 2009. Currently, theThe Company measureshas historically measured its plan assets and benefit obligations using a June 30th measurement date. AtAs a result of the change to a September 30, 2007, in order to recognize the funded status of its pension and post-retirement benefit plans in accordance with SFAS 158,30th measurement date, the Company recorded additional liabilities or reduced assetsfifteen months of pension and other post-retirement benefit costs during fiscal 2009. Such costs were calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to


58

$5.1 million and were recorded by the Company during the quarter ended December 31, 2008 as a cumulative amount of $78.7$3.8 million ($71.1 million net of deferred tax benefits recognized for the portion recorded as an increase to Accumulated Other Comprehensive Loss). Of the $71.1 million recognized, $61.9 million was recorded as an increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments $12.5and a $1.3 million (net of deferred tax benefits of $7.6 million) was recorded as an increase($0.8 million after tax) adjustment to Accumulated Other Comprehensive Loss, and $3.3 million was recorded as an increase to Other Regulatory Liabilitiesearnings reinvested in the Company’s Utility segment. The Company has recorded amounts to Other Regulatory Assets or Other Regulatory Liabilities in the Utility and Pipeline and Storage segments in accordance with the provisions of SFAS 71. The Company, in those segments, has certain regulatory commission authorizations, which allow the Company to defer as a regulatory asset or liability the difference between pension and post-retirement benefit costs as calculated in accordance with SFAS 87 and SFAS 106 and what is collected in rates.business. Refer to Item 8 at Note GH — Retirement Plan and Other Post-Retirement Benefits for further disclosures regarding the impact of SFAS 158this authoritative guidance on the Company’s consolidated financial statements.
 
In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to choose to measure many financial instruments at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 is effective as of the Company’s first quarter of fiscal 2009. The Company does not plan to elect the fair value measurement option for any of its financial instruments other than those that are already being measured at fair value.
In December 2007, the FASB issued SFAS 141R. SFAS 141R willrevised authoritative guidance that significantly changechanges the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies,


55

acquisition costs, in process research and development and restructuring costs. In addition, under SFAS 141R,this guidance, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. SFAS 141RThis guidance is effective as of the Company’s first quarter of fiscal 2010.
 
In December 2007, the FASB issued SFAS 160. SFAS 160 will changeauthoritative guidance that changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160This authoritative guidance is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
 
In March 2008, the FASB issued SFAS 161. SFAS 161authoritative guidance that requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133authoritative guidance for derivative instruments and its related interpretations,hedging activities, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161The Company adopted the disclosure provisions of this authoritative guidance during the Company’s second quarter of fiscal 2009. Refer to Item 8 at Note G — Financial Instruments for these disclosures.
In June 2008, the FASB issued authoritative guidance concerning whether certain instruments granted in share-based payment transactions are participating securities. This guidance specified that unvested share-based payment awards that contain nonforfeitable rights to dividends are participating securities and shall be included in the computation of earnings per share pursuant to the “two-class” method. The “two-class” method allocates undistributed earnings between common shares and participating securities. This authoritative guidance is effective as of the Company’s secondfirst quarter of fiscal 2009.2010. The Company does not believe this guidance will have a material impact on its earnings per share calculation.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements are effective for the Company’sForm 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that the adoption of SFAS 161these rules will have on its consolidated financial statements and MD&A disclosures.
In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements are required for the Company’sForm 10-K for the period ended


59

September 30, 2010. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
Effective with the June 30, 2009Form 10-Q, the Company adopted the FASB authoritative guidance for subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Refer to Item 8 at Note R — Subsequent Events for disclosures made as a result of the adoption of this guidance.
In June 2009, the FASB issued authoritative guidance that establishes the FASB Accounting Standards Codificationtm (the Codification) as the source of authoritative GAAP recognized by the FASB to be applied by all nongovernmental entities in the notespreparation of financial statements in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities law are also sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. The Codification was effective for interim and annual periods ending after September 15, 2009. Effective with this September 30, 2009Form 10-K, the Company has updated its disclosures to conform to the Codification. There has been no impact on the Company’s consolidated financial statements.statements as the Codification does not change or alter existing GAAP.
 
EFFECTS OF INFLATION
 
Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business.
 
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
 
The Company is including the following cautionary statement in thisForm 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to


56

other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
 
  1. Financial and economic conditions, including the availability of credit, and their effect on the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments;


60

  2. Occurrences affecting the Company’s ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
 
  3. Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
 
  4. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
 
  5. Economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters;
 
  6. Changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
 
  7. Changes in demographic patterns and weather conditions;
 
  8. Changes in the availabilityand/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves;
 
  9. Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
  10. Uncertainty of oil and gas reserve estimates;
 
  11. AbilityFactors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations;operations, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations;
 
  12. Significant changes from expectations indifferences between the Company’s projected and actual production levels for natural gas or oil;
 
  13. Changes in the availabilityand/or price of derivative financial instruments;
 
  14. Changes in the price differentials between various types of oil;oil having different qualityand/or different geographic locations, or changes in the price differentials between natural gas having different heating valuesand/or different geographic locations;
 
  15. Inability to obtain new customers or retain existing ones;
 
  16. Significant changes in competitive factors affecting the Company;
 
  17. Changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations;
 
  18. Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;
 
  19. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
 
  20. Significant changes from expectations indifferences between the Company’s projected and actual capital expenditures and operating expenses, and unanticipated project delays or changes in project costs or plans;


61

  21. The nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits;
 
  22. Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;


57

23. Changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company;
 
24.  23. Significant changes in tax rates or policies or in rates of inflation or interest;
 
25.  24. Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur;
 
26.  25. Changes in accounting principles or the application of such principles to the Company;
 
27.  26. The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
 
28.  27. Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or
 
29.  28. Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
 
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
 
Item 7A  Quantitative and Qualitative Disclosures About Market Risk
 
Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A.


5862

Item 8  Financial Statements and Supplementary Data
 
Index to Financial Statements
 
     
  Page
 
Financial Statements:
    
    
Report of Independent Registered Public Accounting Firm
  6064 
Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 20082009
  6165 
Consolidated Balance Sheets at September 30, 20082009 and 20072008
  6266 
Consolidated Statements of Cash Flows, three years ended September 30, 20082009
  6367 
Consolidated Statements of Comprehensive Income, three years ended September 30, 20082009
  6468 
Notes to Consolidated Financial Statements
  6569 
Financial Statement Schedules:    
For the three years ended September 30, 20082009    
Schedule II — Valuation and Qualifying Accounts
  115124 
 
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 MO — Quarterly Financial Data (unaudited) and Note OQ — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.


5963

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
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, 20082009 and 2007,2008, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 20082009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2008,2009, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
PricewaterhouseCoopers LLP
 
Buffalo, New York
November 26, 2008


60

NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands of dollars, except per common
 
  share amounts) 
 
INCOME
            
Operating Revenues
 $2,400,361  $2,039,566  $2,239,675 
             
Operating Expenses
            
Purchased Gas  1,235,157   1,018,081   1,267,562 
Operation and Maintenance  432,871   396,408   395,289 
Property, Franchise and Other Taxes  75,585   70,660   69,202 
Depreciation, Depletion and Amortization  170,623   157,919   151,999 
             
   1,914,236   1,643,068   1,884,052 
             
Operating Income
  486,125   396,498   355,623 
Other Income (Expense):
            
Income from Unconsolidated Subsidiaries  6,303   4,979   3,583 
Other Income  7,376   4,936   2,825 
Interest Income  10,815   1,550   9,409 
Interest Expense on Long-Term Debt  (70,099)  (68,446)  (72,629)
Other Interest Expense  (3,870)  (6,029)  (5,952)
             
Income from Continuing Operations Before Income Taxes
  436,650   333,488   292,859 
Income Tax Expense  167,922   131,813   108,245 
             
Income from Continuing Operations
  268,728   201,675   184,614 
Discontinued Operations:
            
Income (Loss) from Operations, Net of Tax  —   15,479   (46,523)
Gain on Disposal, Net of Tax  —   120,301   — 
             
Income (Loss) from Discontinued Operations, Net of Tax
  —   135,780   (46,523)
             
Net Income Available for Common Stock
  268,728   337,455   138,091 
             
EARNINGS REINVESTED IN THE BUSINESS
            
Balance at Beginning of Year  983,776   786,013   813,020 
             
   1,252,504   1,123,468   951,111 
Share Repurchases  (194,776)  (38,196)  (66,269)
Cumulative Effect of Adoption of FIN 48  (406)  —   — 
Dividends on Common Stock  (103,523)  (101,496)  (98,829)
             
Balance at End of Year
 $953,799  $983,776  $786,013 
             
Earnings Per Common Share:
            
Basic:            
Income from Continuing Operations $3.27  $2.43  $2.20 
Income (Loss) from Discontinued Operations  —   1.63   (0.56)
             
Net Income Available for Common Stock
 $3.27  $4.06  $1.64 
             
Diluted:            
Income from Continuing Operations $3.18  $2.37  $2.15 
Income (Loss) from Discontinued Operations  —   1.59   (0.54)
             
Net Income Available for Common Stock
 $3.18  $3.96  $1.61 
             
Weighted Average Common Shares Outstanding:
            
Used in Basic Calculation  82,304,335   83,141,640   84,030,118 
             
Used in Diluted Calculation  84,474,839   85,301,361   86,028,466 
             
See Notes to Consolidated Financial Statements


61

NATIONAL FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
         
  At September 30 
  2008  2007 
  (Thousands of dollars) 
 
ASSETS
Property, Plant and Equipment
 $4,873,969  $4,461,586 
Less — Accumulated Depreciation, Depletion and Amortization  1,719,869   1,583,181 
         
   3,154,100   2,878,405 
         
Current Assets
        
Cash and Temporary Cash Investments  68,239   124,806 
Cash Held in Escrow  —   61,964 
Hedging Collateral Deposits  1   4,066 
Receivables — Net of Allowance for Uncollectible Accounts of $33,117 and $28,654, Respectively  185,397   172,380 
Unbilled Utility Revenue  24,364   20,682 
Gas Stored Underground  87,294   66,195 
Materials and Supplies — at average cost  31,317   35,669 
Unrecovered Purchased Gas Costs  37,708   14,769 
Other Current Assets  65,158   45,057 
Deferred Income Taxes  —   8,550 
         
   499,478   554,138 
         
Other Assets
        
Recoverable Future Taxes  82,506   83,954 
Unamortized Debt Expense  13,978   12,070 
Other Regulatory Assets  189,587   137,577 
Deferred Charges  4,417   5,545 
Other Investments  80,640   85,902 
Investments in Unconsolidated Subsidiaries  16,279   18,256 
Goodwill  5,476   5,476 
Intangible Assets  26,174   28,836 
Prepaid Pension and Other Post-Retirement Benefit Costs  21,034   61,006 
Fair Value of Derivative Financial Instruments  28,786   9,188 
Other  7,732   8,059 
         
   476,609   455,869 
         
Total Assets
 $4,130,187  $3,888,412 
         
 
CAPITALIZATION AND LIABILITIES
Capitalization:
        
Comprehensive Shareholders’ Equity
        
Common Stock, $1 Par Value        
Authorized — 200,000,000 Shares; Issued and Outstanding — 79,120,544 Shares and 83,461,308 Shares, Respectively $79,121  $83,461 
Paid In Capital  567,716   569,085 
Earnings Reinvested in the Business  953,799   983,776 
         
Total Common Shareholders’ Equity Before Items Of Other Comprehensive Income (Loss)  1,600,636   1,636,322 
Accumulated Other Comprehensive Income (Loss)  2,963   (6,203)
         
Total Comprehensive Shareholders’ Equity
  1,603,599   1,630,119 
Long-Term Debt, Net of Current Portion
  999,000   799,000 
         
Total Capitalization
  2,602,599   2,429,119 
         
Current and Accrued Liabilities
        
Notes Payable to Banks and Commercial Paper  —   — 
Current Portion of Long-Term Debt  100,000   200,024 
Accounts Payable  142,520   109,757 
Amounts Payable to Customers  2,753   10,409 
Dividends Payable  25,714   25,873 
Interest Payable on Long-Term Debt  22,114   18,158 
Customer Advances  33,017   22,863 
Other Accruals and Current Liabilities  45,220   36,062 
Deferred Income Taxes  1,871   — 
Fair Value of Derivative Financial Instruments  1,362   16,200 
         
   374,571   439,346 
         
Deferred Credits
        
Deferred Income Taxes  634,372   575,356 
Taxes Refundable to Customers  18,449   14,026 
Unamortized Investment Tax Credit  4,691   5,392 
Cost of Removal Regulatory Liability  103,100   91,226 
Other Regulatory Liabilities  91,933   76,659 
Pension and Other Post-Retirement Liabilities  78,909   70,555 
Asset Retirement Obligations  93,247   75,939 
Other Deferred Credits  128,316   110,794 
         
   1,153,017   1,019,947 
         
Commitments and Contingencies
  —   — 
         
Total Capitalization and Liabilities
 $4,130,187  $3,888,412 
         
See Notes to Consolidated Financial Statements


62

NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands of dollars) 
 
Operating Activities
            
Net Income Available for Common Stock $268,728  $337,455  $138,091 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:            
Gain on Sale of Discontinued Operations  —   (159,873)  — 
Impairment of Oil and Gas Producing Properties  —   —   104,739 
Depreciation, Depletion and Amortization  170,623   170,803   179,615 
Deferred Income Taxes  72,496   52,847   (5,230)
Income from Unconsolidated Subsidiaries, Net of Cash Distributions  1,977   (3,366)  1,067 
Excess Tax Benefits Associated with Stock-Based Compensation Awards  (16,275)  (13,689)  (6,515)
Other  4,858   16,399   4,829 
Change in:            
Hedging Collateral Deposits  4,065   15,610   58,108 
Receivables and Unbilled Utility Revenue  (16,815)  5,669   (12,343)
Gas Stored Underground and Materials and Supplies  (22,116)  (5,714)  1,679 
Unrecovered Purchased Gas Costs  (22,939)  (1,799)  1,847 
Prepayments and Other Current Assets  (36,376)  18,800   (39,572)
Accounts Payable  32,763   (26,002)  (23,144)
Amounts Payable to Customers  (7,656)  (13,526)  22,777 
Customer Advances  10,154   (6,554)  4,946 
Other Accruals and Current Liabilities  (3,641)  8,950   (17,754)
Other Assets  (11,887)  4,109   (22,700)
Other Liabilities  54,817   (5,922)  80,960 
             
Net Cash Provided by Operating Activities
  482,776   394,197   471,400 
             
Investing Activities
            
Capital Expenditures  (397,734)  (276,728)  (294,159)
Investment in Partnership  —   (3,300)  — 
Net Proceeds from Sale of Foreign Subsidiaries  —   232,092   — 
Cash Held in Escrow  58,397   (58,248)  — 
Net Proceeds from Sale of Oil and Gas Producing Properties  5,969   5,137   13 
Other  4,376   (725)  (3,230)
             
Net Cash Used in Investing Activities
  (328,992)  (101,772)  (297,376)
             
Financing Activities
            
Excess Tax Benefits Associated with Stock-Based Compensation Awards  16,275   13,689   6,515 
Shares Repurchased under Repurchase Plan  (237,006)  (48,070)  (85,168)
Net Proceeds from Issuance of Long-Term Debt  296,655   —   — 
Reduction of Long-Term Debt  (200,024)  (119,576)  (9,805)
Net Proceeds from Issuance of Common Stock  17,432   17,498   23,339 
Dividends Paid on Common Stock  (103,683)  (100,632)  (98,266)
             
Net Cash Used in Financing Activities
  (210,351)  (237,091)  (163,385)
             
Effect of Exchange Rates on Cash
  —   (139)  1,365 
             
Net Increase (Decrease) in Cash and Temporary Cash Investments
  (56,567)  55,195   12,004 
Cash and Temporary Cash Investments At Beginning of Year
  124,806   69,611   57,607 
             
Cash and Temporary Cash Investments At End of Year
 $68,239  $124,806  $69,611 
             
Supplemental Disclosure of Cash Flow Information
            
Cash Paid For:
            
Interest $69,841  $75,987  $78,003 
             
Income Taxes $103,154  $97,961  $54,359 
             
See Notes to Consolidated Financial Statements


63

NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands of dollars) 
 
Net Income Available for Common Stock $268,728  $337,455  $138,091 
             
Other Comprehensive Income (Loss), Before Tax:            
Minimum Pension Liability Adjustment  —   —   165,914 
Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans  (13,584)  —   — 
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans  1,924   —   — 
Foreign Currency Translation Adjustment  12   7,874   7,408 
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income  —   (42,658)  (716)
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  (4,856)  4,747   2,573 
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  (31,490)  8,495   90,196 
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income  64,645   5,106   91,743 
             
Other Comprehensive Income (Loss), Before Tax  16,651   (16,436)  357,118 
             
Income Tax Expense Related to Minimum Pension Liability Adjustment  —   —   58,070 
Income Tax Benefit Related to the Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans  (5,127)  —   — 
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans  726   —   — 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  (1,434)  1,724   894 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  (13,228)  3,153   34,772 
Reclassification Adjustment for Income Tax Benefit on Realized Losses on Derivative Financial Instruments In Net Income  26,548   2,824   35,338 
             
Income Taxes — Net  7,485   7,701   129,074 
             
Other Comprehensive Income (Loss)  9,166   (24,137)  228,044 
             
Comprehensive Income $277,894  $313,318  $366,135 
             
See Notes to Consolidated Financial Statements25, 2009


64

NATIONAL FUEL GAS COMPANY
 
CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS
REINVESTED IN THE BUSINESS
             
  Year Ended September 30 
  2009  2008  2007 
  (Thousands of dollars, except per common 
     share amounts)    
 
INCOME
            
Operating Revenues
 $2,057,852  $2,400,361  $2,039,566 
             
Operating Expenses
            
Purchased Gas  1,001,782   1,235,157   1,018,081 
Operation and Maintenance  402,856   432,871   396,408 
Property, Franchise and Other Taxes  72,163   75,585   70,660 
Depreciation, Depletion and Amortization  173,410   170,623   157,919 
Impairment of Oil and Gas Producing Properties  182,811   —   — 
             
   1,833,022   1,914,236   1,643,068 
             
Operating Income
  224,830   486,125   396,498 
Other Income (Expense):
            
Income from Unconsolidated Subsidiaries  3,366   6,303   4,979 
Impairment of Investment in Partnership  (1,804)  —   — 
Other Income  6,576   7,376   4,936 
Interest Income  5,776   10,815   1,550 
Interest Expense on Long-Term Debt  (79,419)  (70,099)  (68,446)
Other Interest Expense  (7,497)  (3,870)  (6,029)
             
Income from Continuing Operations Before Income Taxes
  151,828   436,650   333,488 
Income Tax Expense  51,120   167,922   131,813 
             
Income from Continuing Operations
  100,708   268,728   201,675 
Discontinued Operations:
            
Income from Operations, Net of Tax  —   —   15,479 
Gain on Disposal, Net of Tax  —   —   120,301 
             
Income from Discontinued Operations, Net of Tax
  —   —   135,780 
             
Net Income Available for Common Stock
  100,708   268,728   337,455 
             
EARNINGS REINVESTED IN THE BUSINESS
            
Balance at Beginning of Year  953,799   983,776   786,013 
             
   1,054,507   1,252,504   1,123,468 
Share Repurchases  —   (194,776)  (38,196)
Cumulative Effect of Adoption of Authoritative Guidance for Income Taxes  —   (406)  — 
Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans  (804)  —   — 
Dividends on Common Stock  (105,410)  (103,523)  (101,496)
             
Balance at End of Year
 $948,293  $953,799  $983,776 
             
Earnings Per Common Share:
            
Basic:            
Income from Continuing Operations $1.26  $3.27  $2.43 
Income from Discontinued Operations  —   —   1.63 
             
Net Income Available for Common Stock
 $1.26  $3.27  $4.06 
             
Diluted:            
Income from Continuing Operations $1.25  $3.18  $2.37 
Income from Discontinued Operations  —   —   1.59 
             
Net Income Available for Common Stock
 $1.25  $3.18  $3.96 
             
Weighted Average Common Shares Outstanding:
            
Used in Basic Calculation  79,649,965   82,304,335   83,141,640 
             
Used in Diluted Calculation  80,628,685   84,474,839   85,301,361 
             
See Notes to Consolidated Financial Statements


65

NATIONAL FUEL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
         
  At September 30 
  2009  2008 
  (Thousands of dollars) 
 
ASSETS
Property, Plant and Equipment
 $5,183,527  $4,873,969 
Less — Accumulated Depreciation, Depletion and Amortization  2,051,482   1,719,869 
         
   3,132,045   3,154,100 
         
Current Assets
        
Cash and Temporary Cash Investments  408,053   68,239 
Cash Held in Escrow  2,000   — 
Hedging Collateral Deposits  848   1 
Receivables — Net of Allowance for Uncollectible Accounts of $38,334 and $33,117, Respectively  144,466   185,397 
Unbilled Utility Revenue  18,884   24,364 
Gas Stored Underground  55,862   87,294 
Materials and Supplies — at average cost  24,520   31,317 
Unrecovered Purchased Gas Costs  —   37,708 
Other Current Assets  68,474   65,158 
Deferred Income Taxes  53,863   — 
         
   776,970   499,478 
         
Other Assets
        
Recoverable Future Taxes  138,435   82,506 
Unamortized Debt Expense  14,815   13,978 
Other Regulatory Assets  530,913   189,587 
Deferred Charges  2,737   4,417 
Other Investments  78,503   80,640 
Investments in Unconsolidated Subsidiaries  16,257   16,279 
Goodwill  5,476   5,476 
Intangible Assets  21,536   26,174 
Prepaid Post-Retirement Benefit Costs  —   21,034 
Fair Value of Derivative Financial Instruments  44,817   28,786 
Other  6,625   7,732 
         
   860,114   476,609 
         
Total Assets
 $4,769,129  $4,130,187 
         
 
CAPITALIZATION AND LIABILITIES
Capitalization:
        
Comprehensive Shareholders’ Equity
        
Common Stock, $1 Par Value        
Authorized — 200,000,000 Shares; Issued and Outstanding — 80,499,915 Shares and 79,120,544 Shares, Respectively $80,500  $79,121 
Paid In Capital  602,839   567,716 
Earnings Reinvested in the Business  948,293   953,799 
         
Total Common Shareholders’ Equity Before Items Of Other Comprehensive Income (Loss)  1,631,632   1,600,636 
Accumulated Other Comprehensive Income (Loss)  (42,396)  2,963 
         
Total Comprehensive Shareholders’ Equity
  1,589,236   1,603,599 
Long-Term Debt, Net of Current Portion
  1,249,000   999,000 
         
Total Capitalization
  2,838,236   2,602,599 
         
Current and Accrued Liabilities
        
Notes Payable to Banks and Commercial Paper  —   — 
Current Portion of Long-Term Debt  —   100,000 
Accounts Payable  90,723   142,520 
Amounts Payable to Customers  105,778   2,753 
Dividends Payable  26,967   25,714 
Interest Payable on Long-Term Debt  32,031   22,114 
Customer Advances  24,555   33,017 
Customer Security Deposits  17,430   14,047 
Other Accruals and Current Liabilities  18,875   31,173 
Deferred Income Taxes  —   1,871 
Fair Value of Derivative Financial Instruments  2,148   1,362 
         
   318,507   374,571 
         
Deferred Credits
        
Deferred Income Taxes  663,876   634,372 
Taxes Refundable to Customers  67,046   18,449 
Unamortized Investment Tax Credit  3,989   4,691 
Cost of Removal Regulatory Liability  105,546   103,100 
Other Regulatory Liabilities  120,229   91,933 
Pension and Other Post-Retirement Liabilities  415,888   78,909 
Asset Retirement Obligations  91,373   93,247 
Other Deferred Credits  144,439   128,316 
         
   1,612,386   1,153,017 
         
Commitments and Contingencies
  —   — 
         
Total Capitalization and Liabilities
 $4,769,129  $4,130,187 
         
See Notes to Consolidated Financial Statements


66

NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
             
  Year Ended September 30 
  2009  2008  2007 
  (Thousands of dollars) 
 
Operating Activities
            
Net Income Available for Common Stock $100,708  $268,728  $337,455 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:            
Gain on Sale of Discontinued Operations  —   —   (159,873)
Impairment of Oil and Gas Producing Properties  182,811   —   — 
Depreciation, Depletion and Amortization  173,410   170,623   170,803 
Deferred Income Taxes  (2,521)  72,496   52,847 
Income from Unconsolidated Subsidiaries, Net of Cash Distributions  (466)  1,977   (3,366)
Impairment of Investment in Partnership  1,804   —   — 
Excess Tax Benefits Associated with Stock-Based Compensation Awards  (5,927)  (16,275)  (13,689)
Other  17,443   4,858   16,399 
Change in:            
Hedging Collateral Deposits  (847)  4,065   15,610 
Receivables and Unbilled Utility Revenue  47,658   (16,815)  5,669 
Gas Stored Underground and Materials and Supplies  43,598   (22,116)  (5,714)
Unrecovered Purchased Gas Costs  37,708   (22,939)  (1,799)
Prepayments and Other Current Assets  2,921   (36,376)  18,800 
Accounts Payable  (61,149)  32,763   (26,002)
Amounts Payable to Customers  103,025   (7,656)  (13,526)
Customer Advances  (8,462)  10,154   (6,554)
Customer Security Deposits  3,383   609   1,907 
Other Accruals and Current Liabilities  13,676   (4,250)  7,043 
Other Assets  (35,140)  (11,887)  4,109 
Other Liabilities  (4,201)  54,817   (5,922)
             
Net Cash Provided by Operating Activities
  609,432   482,776   394,197 
             
Investing Activities
            
Capital Expenditures  (309,930)  (397,734)  (276,728)
Investment in Subsidiary, Net of Cash Acquired  (34,933)  —   — 
Investment in Partnerships  (1,317)  —   (3,300)
Net Proceeds from Sale of Foreign Subsidiaries  —   —   232,092 
Cash Held in Escrow  (2,000)  58,397   (58,248)
Net Proceeds from Sale of Oil and Gas Producing Properties  3,643   5,969   5,137 
Other  (2,806)  4,376   (725)
             
Net Cash Used in Investing Activities
  (347,343)  (328,992)  (101,772)
             
Financing Activities
            
Excess Tax Benefits Associated with Stock-Based Compensation Awards  5,927   16,275   13,689 
Shares Repurchased under Repurchase Plan  —   (237,006)  (48,070)
Net Proceeds from Issuance of Long-Term Debt  247,780   296,655   — 
Reduction of Long-Term Debt  (100,000)  (200,024)  (119,576)
Net Proceeds from Issuance of Common Stock  28,176   17,432   17,498 
Dividends Paid on Common Stock  (104,158)  (103,683)  (100,632)
             
Net Cash Provided By (Used in) Financing Activities
  77,725   (210,351)  (237,091)
             
Effect of Exchange Rates on Cash
  —   —   (139)
             
Net Increase (Decrease) in Cash and Temporary Cash Investments
  339,814   (56,567)  55,195 
Cash and Temporary Cash Investments At Beginning of Year
  68,239   124,806   69,611 
             
Cash and Temporary Cash Investments At End of Year
 $408,053  $68,239  $124,806 
             
Supplemental Disclosure of Cash Flow Information
            
Cash Paid For:
            
Interest $75,640  $69,841  $75,987 
             
Income Taxes $40,638  $103,154  $97,961 
             
See Notes to Consolidated Financial Statements


67

NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
             
  Year Ended September 30 
  2009  2008  2007 
  (Thousands of dollars) 
 
Net Income Available for Common Stock $100,708  $268,728  $337,455 
             
Other Comprehensive Income (Loss), Before Tax:            
Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans  (71,771)  (13,584)  — 
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans  1,008   1,924   — 
Foreign Currency Translation Adjustment  (33)  12   7,874 
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income  —   —   (42,658)
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  (6,118)  (4,856)  4,747 
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  119,210   (31,490)  8,495 
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income  (114,380)  64,645   5,106 
             
Other Comprehensive Income (Loss), Before Tax  (72,084)  16,651   (16,436)
             
Income Tax Benefit Related to the Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans  (27,082)  (5,127)  — 
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans  380   726   — 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period  (2,311)  (1,434)  1,724 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period  48,293   (13,228)  3,153 
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses on Derivative Financial Instruments In Net Income  (46,005)  26,548   2,824 
             
Income Taxes — Net  (26,725)  7,485   7,701 
             
Other Comprehensive Income (Loss)  (45,359)  9,166   (24,137)
             
Comprehensive Income $55,349  $277,894  $313,318 
             
See Notes to Consolidated Financial Statements


68

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Note A — Summary of Significant Accounting Policies
 
Principles of Consolidation
 
The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
 
The preparation of the consolidated financial statements in conformity with GAAP 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.
 
Regulation
 
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
 
Revenue Recognition
 
The Company’s Utility segment records revenue 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.
 
The Company’s Energy Marketing segment records revenue as bills are rendered for service supplied on a calendar month basis.
 
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
 
The Company’s Timber segment records revenue on lumber and log sales as products are shipped, which is the point at which ownership and risk of loss transfers to the buyer of lumber products or logs.
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
 
Allowance for Uncollectible Accounts
 
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.


6569

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Regulatory Mechanisms
 
The Company’s rate schedules in the Utility segment 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. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
 
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note C — Regulatory Matters for further discussion.
 
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
 
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending December 31st, and applied to customer bills annually, beginning March 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation bills its customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, in fixed monthly reservation charges. The allowed rates that Empire bills its customers are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. To distinguish between the two rate designs, the modified fixed-variable rate design recovers return on equity and income taxes through variable charges whereas straight fixed-variable recovers all fixed costs, including return on equity and income taxes, through itsfixed monthly reservation charge.charges. Because of the difference inthis rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation’s revenues but mayCorporation.
Prior to December 10, 2008, the allowed rates that Empire billed its customers were based on a modified fixed-variable rate design, which recovered return on equity and income taxes through variable charges. Because of this rate design, changes in throughput due to weather variations could have had a significant impact on Empire’s revenues. On December 10, 2008, Empire became FERC regulated. As a result, Empire now bills its customers based on a straight fixed-variable rate design. Changes in throughput due to weather variations no longer have a significant impact on Empire’s revenues.revenue.
 
Property, Plant and Equipment
 
The principal assets of the Utility and Pipeline and Storage segments, 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.
 
In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the


70

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
 
Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
 
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net


66

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2009, 2008, 2007, and 2006,2007, estimated future net cash flows were increased by $143.3 million, $34.5 million $2.2 million and $4.7$2.2 million, respectively. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s Canadianoil and gas properties at June 30, 2006 and September 30, 2006.December 31, 2008. As such, the Company recognized a pre-tax impairmentsimpairment of $62.4$182.8 million at June 30, 2006 and $42.3December 31, 2008. Deferred income taxes of $74.6 million at September 30, 2006. These impairment charges are included in loss from discontinued operations for 2006 due to the sale of SECI during 2007.were recorded associated with this impairment.
 
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.
 
Depreciation, Depletion and Amortization
 
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. ForIn the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation, depletion and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
 
         
  As of September 30 
  2008  2007 
  (Thousands) 
 
Utility $1,580,366  $1,539,808 
Pipeline and Storage  996,743   976,316 
Exploration and Production  1,800,422   1,577,745 
Energy Marketing  1,232   1,199 
Timber  120,021   119,237 
All Other and Corporate  25,984   32,806 
         
  $4,524,768  $4,247,111 
         
Average depreciation, depletion and amortization rates are as follows:
        
             As of September 30 
 Year Ended September 30  2009 2008 
 2008 2007 2006  (Thousands) 
Utility  2.6%  2.8%  2.8% $1,616,908  $1,580,366 
Pipeline and Storage  3.2%  3.5%  4.0%  1,196,937   996,743 
Exploration and Production, per Mcfe(1) $2.26  $1.94  $2.00 
Exploration and Production  1,972,353   1,800,422 
Energy Marketing  3.5%  2.8%  4.8%  1,241   1,232 
Timber  4.1%  4.0%  5.6%
All Other and Corporate  5.0%  4.6%  4.1%  154,512   146,005 
     
 $4,941,951  $4,524,768 
     


6771

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Average depreciation, depletion and amortization rates are as follows:
             
  Year Ended September 30 
  2009  2008  2007 
 
Utility  2.6%  2.6%  2.8%
Pipeline and Storage  3.0%  3.2%  3.5%
Exploration and Production, per Mcfe(1) $2.14  $2.26  $1.94 
Energy Marketing  3.4%  3.5%  2.8%
All Other and Corporate  5.2%  4.3%  4.1%
 
 
(1)Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note OQ — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $2.10, $2.23 $1.92 and $1.98$1.92 per Mcfe of production in 2009, 2008 2007 and 2006,2007, respectively. Depletion of oil and gas producing properties in the United States amounted to $2.10, $2.23 $1.97 and $1.74$1.97 per Mcfe of production in 2009, 2008 2007 and 2006,2007, respectively. Depletion of oil and gas producing properties in Canada amounted to $1.67 and $2.95 per Mcfe of production in 2007 and 2006, respectively.2007.
 
Goodwill
 
The Company has recognized goodwill of $5.5 million as of September 30, 20082009 and 20072008 on its consolidated balance sheetConsolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with SFAS 142,the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 20082009 and 2007,2008, the fair value of Empire was greater than its book value. As such, the goodwill was considered not impaired.
 
Financial Instruments
 
Unrealized gains or losses from the Company’s investments in an equity mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note FG — Financial Instruments for further discussion.
 
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled fair value of derivative financial instruments. Reference is made to Note F — Fair Value Measurements for further discussion concerning the fair value represents the amount the Company would receive or pay to terminate theseof derivative financial instruments.
 
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues, purchased gas expense or interest expense on the Consolidated Statements of Income. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statements of Income. In December 2006, the Company repaid $22.8 million of Empire’s secured debt. The interest costs of this secured debt were hedged by an interest rate collar. Since the hedged transaction was settled and there will be no future cash flows associated with the secured debt, hedge accounting for the interest rate collar was discontinued and the unrealized gain of $1.9 million in accumulated other comprehensive income associated with the interest rate collar was reclassified to the Consolidated Statement of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 20082009 or 2006.2008.


72

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. The Company did not experience any material ineffectiveness with regard to its fair value hedges during 2009, 2008 2007 or 2006.


68

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)2007.
 
Accumulated Other Comprehensive Income (Loss)
 
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
 
                
 Year Ended September 30  Year Ended September 30 
 2008 2007  2009 2008 
 (Thousands)  (Thousands) 
Funded Status of the Pension and Other Post-Retirement Benefit Plans $(19,741) $(12,482)(1) $(63,802) $(19,741)
Cumulative Foreign Currency Translation Adjustment  (71)  (83)  (104)  (71)
Net Unrealized Gain (Loss) on Derivative Financial Instruments  15,949   (3,886)
Net Unrealized Gain on Derivative Financial Instruments  18,491   15,949 
Net Unrealized Gain on Securities Available for Sale  6,826   10,248   3,019   6,826 
          
Accumulated Other Comprehensive Income (Loss) $2,963  $(6,203) $(42,396) $2,963 
          
(1)In accordance with the transition recognition implementation provisions of SFAS 158, the adjustment to recognize the funded status of the pension and other post-retirement benefit plans are shown as an adjustment to the ending balance of accumulated other comprehensive income (loss). The adjustment is not shown as other comprehensive income (loss) in the Consolidated Statements of Comprehensive Income.
 
At September 30, 2008,2009, it is estimated that of the $15.9$18.5 million net unrealized gain on derivative financial instruments shown in the table above, $13.1$18.6 million of unrealized gains will be reclassified into the Consolidated Statement of Income during 2009.2010. The remaining unrealized gainloss on derivative financial instruments of $2.8$0.1 million will be reclassified into the Consolidated Statement of Income in subsequent years. As disclosed in Note F — Financial Instruments, theThe Company’s derivative financial instruments extend out to 2012.
 
The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of an unrecognized transition obligation, prior service costs and accumulated losses. The total unrecognized transition obligation was $0.1 million at September 30, 2007 (nothing at September 30, 2008). The total amount for prior service costs was $0.4$0.3 million and $1.0$0.4 million at September 30, 20082009 and September 30, 2007,2008, respectively. The total amount for accumulated losses was $19.3$63.5 million and $11.4$19.3 million at September 30, 20082009 and September 30, 2007,2008, respectively.
 
Gas Stored Underground — Current
 
In the Utility segment, gas stored underground — current in the amount of $34.1$30.4 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2008,2009, including transportation costs, the current cost of replacing this inventory of gas stored underground — current exceeded the amount stated on a LIFO basis by approximately $195.4$51.6 million at September 30, 2008.2009. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at lower of cost or market on an average cost method.


69

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Purchased Timber Rights
 
In the Timber segment, theThe Company purchases the right to harvest timber from land owned by other parties. These rights, which extend from several months to several years, are purchased to ensure an adequate supply of timber for the Company’s sawmill and kiln operations. The historical value of timber rights expected to be harvested during the following year are included in Materials and Supplies on the Consolidated Balance Sheets while the


73

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
historical value of timber rights expected to be harvested beyond one year are included in Other Assets on the Consolidated Balance Sheets. The components of the Company’s purchased timber rights are as follows:
 
                
 Year Ended September 30  Year Ended September 30 
 2008 2007  2009 2008 
 (Thousands)  (Thousands) 
Materials and Supplies $9,911  $8,925  $6,349  $9,911 
Other Assets  7,383   5,641   6,343   7,383 
          
 $17,294  $14,566  $12,692  $17,294 
          
 
Unamortized Debt Expense
 
Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related debt. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
 
Foreign Currency Translation
 
The functional currency for the Company’s foreign operations is the local currency of the country where the operations are located. Asset and liability accounts are translated at the rate of exchange on the balance sheet date. Revenues and expenses are translated at the average exchange rate during the period. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive income (loss). With the sale of SECI on August 31, 2007, the Company eliminated its major foreign operation. While the Company is in the process of winding up or selling certain power development projects in Europe, the investment in such projects is not significant and the Company does not expect to have any significant foreign currency translation adjustments in the future.
 
Income Taxes
 
The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
 
Consolidated Statements of Cash Flows
 
For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.
At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System at September 30, 2009. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represent non-cash investing activities at that date.
At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount has beenwas excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it representsrepresented a non-cash investing activity at that date.
Hedging Collateral Account
These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash held in margin accounts serves as collateralFlows for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.the year ended September 30, 2009.


7074

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Hedging Collateral Account
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for open hedging positions. At September 30, 2009, the Company had hedging collateral deposits of $0.8 million related to its exchange-traded futures contracts. It is the Company’s policy to not offset hedging collateral deposits paid or received against the derivative financial instruments liability or asset balances.
Cash Held in Escrow
On July 20, 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition includes $2 million held in escrow at September 30, 2009. Seneca placed this amount in escrow as part of the purchase price, and in accordance with the purchase agreement, this amount will remain in escrow for one year from the closing of the transaction provided there are no pending disputes or actions regarding obligations and liabilities required to be satisfied or discharged by Ivanhoe Energy.
 
On August 31, 2007, the Company received approximately $232.1 million of proceeds from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account was a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company held a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the year ended September 30, 2008, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the impact of the foreign currency hedge.
 
Other Current Assets
 
Other Current Assets consist of prepayments in the amounts of $10.6$12.2 million and $14.1$10.6 million at September 30, 20082009 and 2007,2008, respectively, prepaid property and other taxes of $11.2$12.0 million and $14.1$11.2 million at September 30, 20082009 and 2007,2008, respectively, federal income taxes receivable in the amounts of $27.5$23.3 million and $8.7$27.5 million at September 30, 20082009 and 2007,2008, respectively, state income taxes receivable in the amounts of $5.0$13.5 million and zero$5.0 million at September 30, 20082009 and 2007,2008, respectively, and fair values of firm commitments in the amounts of $10.9$7.5 million and $8.2$10.9 million at September 30, 2009 and 2008, respectively.
Customer Advances
The Company’s Utility and 2007,Energy Marketing segments have balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2009 and 2008, customers in the balanced billing programs had advanced excess funds of $24.6 million and $33.0 million, respectively.
Customer Security Deposits
The Company, in its Utility, Pipeline and Storage, and Energy Marketing segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2009 and 2008, the Company had received customer security deposits amounting to $17.4 million and $14.0 million, respectively.


75

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Earnings Per Common Share
 
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and stock-settled SARs. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these stock options and stock-settled SARs as determined using the Treasury Stock Method. Stock options and stock-settled SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2009, there were 365,000 stock-settled SARs and 765,000 stock options excluded as being antidilutive. For 2008, there were 7,344 stock-settled SARs excluded as being antidilutive, and there were no stock options excluded as being antidilutive. For 2007, no stock options or stock-settled SARs were excluded as being antidilutive. For 2006, 119,241 stock options were excluded as being antidilutive. There were no stock-settled SARs excluded as being antidilutive for 2006.
 
Share Repurchases
 
The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note E — Capitalization and Short-Term Borrowings for further discussion of the share repurchase program.
 
Stock-Based Compensation
 
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock-settled SARs, restricted stock, performance units or performance shares. Stock options and stock-settled SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or stock-settled SAR is exercisable less than one year or more than ten years


71

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
after the date of each grant. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
 
Prior to October 1, 2005, the Company accounted for its stock-based compensation under the recognition and measurement principles of APB 25 and related interpretations. Under that method, no compensation expense was recognized for options granted under the Company’s stock option and stock award plans. The Company did record, in accordance with APB 25, compensation expense for the market value of restricted stock on the date of the award over the periods during which the vesting restrictions existed.
Effective October 1, 2005, the Company adopted SFAS 123R,follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options and stock-settled SARs. The Company has chosen to use the modified version of prospective application, as allowed by SFAS 123R. Using the modified prospective application, the Company recorded compensation cost for the portion of awards granted prior to October 1, 2005 for which the requisite service had not been rendered and recognized such compensation cost as the requisite service was rendered on or after October 1, 2005. Such compensation expense is based on the grant-date fair value of the awards as calculated for the Company’s disclosure using a Binomial option-pricing model under SFAS 123. Any new awards, modifications to awards, repurchases of awards, or cancellations of awards subsequent to September 30, 2005 will follow the provisions of SFAS 123R, with compensation expense being calculated using the Black-Scholes-Merton closed form model. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with such share-based payments since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model.
The Company did not grant any stock options during the years ended September 30, 2009 and 2008. There were no448,000 stock options granted during the year ended September 30, 2008. There were 448,000 and 317,000 stock options granted during the years ended September 30, 2007 and 2006, respectively.2007. The Company granted 610,000 and 321,000 performance based stock-settled SARs during the year ended September 30, 2008. There were no2009 and 2008, respectively, but did not grant any performance based stock-settled SARs granted during the year ended September 30, 2007. The Company granted 50,000 non-performance based stock-settled SARs during the year ended September 30, 2007. There were no2007, but did not grant any non-performance based stock-settled SARs granted during the yearyears ended September 30, 2009 and 2008. There were no performance based or non-performance based stock-settled SARs granted during the year ended September 30, 2006. The accounting treatment for such performance based and non-performance based stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R.the current authoritative guidance for stock-based compensation. The performance based stock-settled SARs granted for the year ended


76

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
September 30, 2009 vest and become exercisable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The performance based stock-settled SARs granted for the year ended September 30, 2008 vest and become exercisable annually, in one-third increments, provided that a performance condition for diluted earnings per share is met for the prior fiscal year. The weighted average grant date fair value of the performance based stock-settled SARs granted during 2009 and 2008 was estimated on the date of grant using the same accounting treatment that is applied for stock options, under SFAS 123R, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed. During 2009, the Company reversed $0.5 million of previously recognized compensation expense associated with performance based stock-settled SARs. The Company also granted 25,000,63,000, 25,000, and 16,00025,000 restricted share awards (non-vested stock as defined by SFAS 123R)the current accounting literature) during the years ended September 30, 2009, 2008 and 2007, and 2006, respectively.
Stock-based compensation expense for the years ended September 30, 2009, 2008 2007 and 20062007 was approximately $2,332,000, $3,727,000,$2.1 million (net of the $0.5 million reversal of compensation expense discussed above), $2.3 million, and $1,705,000,$3.7 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statement of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2009, 2008 2007 and 20062007 was approximately $945,000, $1,488,000$0.8 million, $0.9 million and $653,000,$1.5 million, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 20082009 and 2007.


72

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)2008.
 
Stock Options
 
The total intrinsic value of stock options exercised during the years ended September 30, 2009, 2008 2007 and 20062007 totaled approximately $18.7 million, $24.6 million, $38.7 million, and $30.9$38.7 million, respectively. For 2009, 2008 2007 and 2006,2007, the amount of cash received by the Company from the exercise of such stock options was approximately $29.2 million, $18.5 million, $26.0 million, and $30.1$26.0 million, respectively.
 
The Company realizes tax benefits related to the exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2008, 2007, 2006, and 2005,2006, the Company realized a tax benefit of $1.6 million, $4.4 million, and $3.2 million, and $0.9respectively. For stock options exercised during the period of January 1, 2009 through September 30, 2009, the Company will realize a tax benefit of approximately $5.7 million respectively.in the quarter ended December 31, 2009. For stock options exercised during the period of January 1, 2008 through September 30, 2008, the Company will realizerealized a tax benefit of approximately $4.3 million in the quarter ended December 31, 2008. For stock options exercised during the period of January 1, 2007 through September 30, 2007, the Company realized a tax benefit of approximately $12.0 million in the quarter ended December 31, 2007. For stock options exercised during the period of January 1, 2006 through September 30, 2006, the Company realized a tax benefit of approximately $11.4 million in the quarter ended December 31, 2006. The weighted average grant date fair value of options granted in 2007 and 2006 is $7.27 per shareshare. As stated above, there were no stock options granted during the years ended September 30, 2009 and $6.68 per share, respectively.2008. For the years ended September 30, 2009, 2008 and 2007, 27,000, 358,000 and 2006, 358,000, 327,501 and 89,665 stock options became fully vested, respectively. The total fair value of thesethe stock options was approximately $2.6 million, $2.1 million and $0.4 million, respectively, forthat became vested during the years ended September 30, 2009, 2008 and 2007 was approximately $0.2 million, $2.6 million and 2006.$2.1 million, respectively. As of September 30, 2008,2009, unrecognized compensation expense related to stock options totaled approximately $0.3 million,$47,000, which will be recognized over a weighted average period of 8.63.0 months. For a summary of transactions during 20082009 involving option shares for all plans, refer to Note E — Capitalization and Short-Term Borrowings.


77

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The fair value of options at the date of grant was estimated using a Binomial option-pricing model for options granted prior to October 1, 2005 and the Black-Scholes-Merton closed form model for options granted after September 30, 2005.model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
Risk Free Interest Rate  N/A   4.46%  5.08%  N/A   N/A   4.46%
Expected Life (Years)  N/A   7.0   7.0   N/A   N/A   7.0 
Expected Volatility  N/A   17.73%  17.71%  N/A   N/A   17.73%
Expected Dividend Yield (Quarterly)  N/A   0.76%  0.83%  N/A   N/A   0.76%
 
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the option. The expected life and expected volatility are based on historical experience.
 
For grants during the yearsyear ended September 30, 2007, and 2006, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
 
Non-Performance Based Stock-settled SARs
 
There were noParticipants in the stock option and award plans did not exercise any non-performance based stock-settled SARs exercised during the years ended September 30, 2009, 2008 and 2007 and 2006 assince none of the non-performance based stock-settled SARs granted have vested. ThereAs stated above, there were 50,000 non-performance based stock-settled SARs granted during 2007. The weighted average grant date fair value of non-performance based stock-settled SARs granted in 2007 is $7.81 per share. There were noThe Company did not grant any non-performance based stock-settled SARs granted during 20082009 or 2006.2008. As of September 30, 2008,2009, unrecognized compensation expense related to non-performance based stock-settled SARs totaled approximately $0.2$0.1 million, which will be recognized over a weighted average period of 10.24.3 months. For a summary of transactions during


73

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2008 2009 involving non-performance based stock-settled SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
The fair value of non-performance based stock-settled SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
 
Year Ended
September 30,
2007
Risk Free Interest Rate4.53%
Expected Life (Years)7.0
Expected Volatility17.55%
Expected Dividend Yield (Quarterly)0.73%
             
  Year Ended September 30 
  2009  2008  2007 
 
Risk Free Interest Rate  N/A   N/A   4.53%
Expected Life (Years)  N/A   N/A   7.0 
Expected Volatility  N/A   N/A   17.55%
Expected Dividend Yield (Quarterly)  N/A   N/A   0.73%
 
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the non-performance based stock-settled SARs. The expected life and expected volatility are based on historical experience.
 
For grants during the year ended September 30, 2007, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
 
Performance Based Stock-settled SARs
 
There were noParticipants in the stock option and award plans did not exercise any performance based stock-settled SARs exercised during the years ended September 30, 2009, 2008 2007 and 2006 as none of the performance based stock-settled SARs granted have vested. There2007. As stated above, there were 610,000 and 321,000 performance based stock-settled SARs granted during 2008.the years ended September 30, 2009 and 2008,


78

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
respectively. The weighted average grant date fair value of performance based stock-settled SARs granted in 2009 and 2008 is $4.09 per share and $9.06 per share. There were noshare, respectively. The Company did not grant any performance based stock-settled SARs granted during 2007 or 2006.2007. For the yearsyear ended September 30, 2008, 2007 and 2006, there were no2009, 96,984 performance based stock-settled SARs became fully vested. Fiscal 2009 was the first year in which performance based stock-settled SARs became vested. The total fair value of the performance based stock-settled SARs that became fully vested.vested during the year ended September 30, 2009 was approximately $0.8 million. As of September 30, 2008,2009, unrecognized compensation expense related to performance based stock-settled SARs totaled approximately $1.9$1.3 million, which will be recognized over a weighted average period of 1.1 years.10.9 months. For a summary of transactions during 20082009 involving performance based stock-settled SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
 
The fair value of performance based stock-settled SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
 
Year Ended
September 30,
2008
Risk Free Interest Rate3.78%
Expected Life (Years)7.25
Expected Volatility17.69%
Expected Dividend Yield (Quarterly)0.64%
             
  Year Ended September 30 
  2009  2008  2007 
 
Risk Free Interest Rate  2.56%  3.78%  N/A 
Expected Life (Years)  7.50   7.25   N/A 
Expected Volatility  22.16%  17.69%  N/A 
Expected Dividend Yield (Quarterly)  1.09%  0.64%  N/A 
 
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the performance based stock-settled SARs. The expected life and expected volatility are based on historical experience.
 
For grants during the yearyears ended September 30, 2009 and 2008, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.


74

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Restricted Share Awards
 
The weighted average fair value of restricted share awards granted in 2009, 2008 and 2007 and 2006 is $47.46 per share, $48.41 per share $40.18 per share and $34.94$40.18 per share, respectively. As of September 30, 2008,2009, unrecognized compensation expense related to restricted share awards totaled approximately $1.6$3.9 million, which will be recognized over a weighted average period of 2.54.4 years. For a summary of transactions during 20082009 involving restricted share awards, refer to Note E — Capitalization and Short-Term Borrowings.
 
During 2006, a modification was made to a restricted share award involving one employee. The modification accelerated the vesting date of 4,000 shares from December 7, 2006 to July 1, 2006. The incremental compensation expense, totaling approximately $32,000, was included with the total stock-based compensation expense for the year ended September 30, 2006.
New Authoritative Accounting Pronouncementsand Financial Reporting Guidance
 
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 providesauthoritative guidance for using fair value to measure assets and liabilities. The pronouncementThis guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157This guidance is to be applied whenever another standard requires or allows assets or liabilities are to be measured at fair value. In accordance with FASB Staff PositionFAS No. 157-2, SFAS 157 is effectiveOn October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The same FASB Staff Positionbasis. This guidance delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of the authoritative guidance for financial assets and financial liabilities, refer to Note F — Fair Value Measurements. The Company does not expectis currently evaluating the impact that SFAS 157the adoption of the authoritative guidance for nonfinancial assets and nonfinancial liabilities will have a significant impact on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of this guidance. The Company does not believe there are any nonfinancial liabilities that will be impacted by the adoption of this guidance.


79

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158authoritative guidance which requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncementThis guidance requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. This guidance also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158,this authoritative guidance, the Company has recognized the funded status of its benefit plans and implemented the related disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will bewas fully adopted by the Company by the endas of fiscalSeptember 30, 2009. Currently, theThe Company measureshas historically measured its plan assets and benefit obligations using a June 30th measurement date. AtAs a result of the change to a September 30, 2007, in order to recognize the funded status of its pension and post-retirement benefit plans in accordance with SFAS 158,30th measurement date, the Company recorded additional liabilities or reduced assetsfifteen months of pension and other post-retirement benefit costs during fiscal 2009. Such costs were calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and were recorded by the Company during the quarter ended December 31, 2008 as a cumulative amount of $78.7$3.8 million ($71.1 million net of deferred tax benefits recognized for the portion recorded as an increase to Accumulated Other Comprehensive Loss). Of the $71.1 million recognized, $61.9 million was recorded as an increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments $12.5and a $1.3 million (net of deferred tax benefits of $7.6 million) was recorded as an increase($0.8 million after tax) adjustment to Accumulated Other Comprehensive Loss, and $3.3 million was recorded as an increase to Other Regulatory Liabilitiesearnings reinvested in the Company’s Utility segment. The Company has recorded amounts to Other Regulatory Assets or Other Regulatory Liabilities in the Utility and Pipeline and Storage segments in accordance with the provisions of SFAS 71. The Company, in those segments, has certain regulatory commission authorizations, which allow the Company to defer as a regulatory asset or liability the difference between pension and post-retirement benefit costs as calculated in accordance with SFAS 87 and SFAS 106 and what is collected in rates.business. Refer to Note GH — Retirement Plan and Other Post-Retirement Benefits for further disclosures regarding the impact of SFAS 158this authoritative guidance on the Company’s consolidated financial statements.


75

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115.” SFAS 159 permits entities to choose to measure many financial instruments at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 is effective as of the Company’s first quarter of fiscal 2009. The Company does not plan to elect the fair value measurement option for any of its financial instruments other than those that are already being measured at fair value.
 
In December 2007, the FASB issued SFAS 141R, “Business Combinations.” SFAS 141R willrevised authoritative guidance that significantly changechanges the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, in process research and development and restructuring costs. In addition, under SFAS 141R,this guidance, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. SFAS 141RThis guidance is effective as of the Company’s first quarter of fiscal 2010.
 
In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51.” SFAS 160 will changeauthoritative guidance that changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160This authoritative guidance is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
 
In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133.” SFAS 161authoritative guidance that requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133authoritative guidance for derivative instruments and its related interpretations,hedging activities, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161The Company adopted the disclosure provisions of this authoritative guidance during the Company’s second quarter of fiscal 2009. Refer to Note G — Financial Instruments for these disclosures.
In June 2008, the FASB issued authoritative guidance concerning whether certain instruments granted in share-based payment transactions are participating securities. This guidance specified that unvested share-based payment awards that contain nonforfeitable rights to dividends are participating securities and shall be included in the computation of earnings per share pursuant to the “two-class” method. The“two-class” method allocates undistributed earnings between common shares and participating securities. This authoritative


80

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
guidance is effective as of the Company’s secondfirst quarter of fiscal 2009.2010. The Company does not believe this guidance will have a material impact on its earnings per share calculation.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements are effective for the Company’sForm 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that the adoption of SFAS 161these rules will have on its consolidated financial statements and MD&A disclosures.
In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements are required for the Company’sForm 10-K for the period ended September 30, 2010. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
Effective with the June 30, 2009Form 10-Q, the Company adopted the FASB authoritative guidance for subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Refer to Note R — Subsequent Events for disclosures made as a result of the adoption of this guidance.
In June 2009, the FASB issued authoritative guidance that establishes the FASB Accounting Standards Codificationtm (the Codification) as the source of authoritative GAAP recognized by the FASB to be applied by all nongovernmental entities in the notespreparation of financial statements in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities law are also sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. The Codification was effective for interim and annual periods ending after September 15, 2009. Effective with this September 30, 2009Form 10-K, the Company has updated its disclosures to conform to the Codification. There has been no impact on the Company’s consolidated financial statements.statements as the Codification does not change or alter existing GAAP.
 
Note B —Asset Retirement Obligations
Note B — Asset Retirement Obligations
 
The Company accounts for asset retirement obligations in accordance with the provisions of SFAS 143. SFAS 143authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timingand/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.
 
As previously disclosed, the Company follows the full cost method of accounting for its exploration and production costs. UponIn accordance with the adoption of SFAS 143 on October 1, 2002,current authoritative guidance for asset retirement obligations, the Company has recorded an asset retirement obligation representing plugging and abandonment costs associated


81

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
with the Exploration and Production segment’s crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool). Prior toUnder the adoption of SFAS 143, plugging and abandonment costs were accountedcurrent authoritative guidance for solely through the Company’s units-of-production depletion calculation. An estimate of such costs was added to the depletion base, which also included capitalized costs in the full cost pool and estimated future expenditures to be incurred in developing proved reserves. With the adoption of SFAS 143,asset retirement obligations, since plugging and abandonment costs are already included in capitalized costs and the full cost pool, theunits-of-production depletion calculation has been modified to excludeexcludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
 
The full cost method of accounting provides a limit to the amount of costs that can be capitalized in the full cost pool. This limit is referred to as the full cost ceiling. Prior toIn accordance with current authoritative guidance, since the adoptionfull cost pool includes an amount associated with plugging and abandoning the wells, as discussed in the preceding paragraph, the calculation of SFAS 143, in calculating the full


76

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
cost ceiling the Company reducedno longer reduces the future net cash flows from proved oil and gas reserves by the estimated plugging and abandonment costs. Such future net cash flows would then be compared to capitalized costs in the full cost pool, with any excess capitalized costs being expensed. With the adoptionan estimate of SFAS 143, since the full cost pool now includes an amount associated with plugging and abandoning the wells, the calculation of the full cost ceiling has been changed so that future net cash flows from proved oil and gas reserves are no longer reduced by the estimated plugging and abandonment costs.
 
On September 30, 2006,In addition to the Company adopted FIN 47, an interpretation of SFAS 143. FIN 47 provides clarification of the term “conditional asset retirement obligation” as used in SFAS 143, defined as a legal obligation to perform an asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under this standard, if the fair value of a conditional asset retirement obligation can be reasonably estimated, a company must record a liabilityrecorded in the Exploration and a corresponding asset forProduction segment, the conditional asset retirement obligation representing the present value of that obligation at the date the obligation was incurred. FIN 47 also serves to clarify when a company would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation.
Upon the adoption of FIN 47, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company has also identifiedrecorded asset retirement obligations for certain costs connected with the retirement of distribution mains and services pipeline systems in the Utility segment and with the transmission mains and other components in the pipeline systems in the Pipeline and Storage segment. These retirement costs within the distribution and transmission systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for theclean-up of PCB contamination associated with the removal of certain pipe.
 
As a result of the implementation of FIN 47 as of September 30, 2006, the Company recorded additional asset retirement obligations of $23.2 million and corresponding long-lived plant assets, net of accumulated depreciation, of $3.5 million. These assets will be depreciated over their respective remaining depreciable life. The remaining $19.7 million represents the cumulative accretion and depreciation of the asset retirement obligations that would have been recognized if this interpretation had been in effect at the inception of the obligations. Of this amount, the Company recorded an increase to regulatory assets of $9.0 million and a reduction to cost of removal regulatory liability of $10.7 million. The cost of removal regulatory liability represents amounts collected from customers through depreciation expense in the Company’s Utility and Pipeline and Storage segments. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 requires that such costs of removal be reclassified from accumulated depreciation to other regulatory liabilities. At September 30, 2008 and 2007, the costs of removal reclassified to other regulatory liabilities amounted to $103.1 million and $91.2 million, respectively.
A reconciliation of the Company’s asset retirement obligation calculated in accordance with SFAS 143 is shown below:
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
   (Thousands)      (Thousands)   
Balance at Beginning of Year $75,939  $77,392  $41,411  $93,247  $75,939  $77,392 
Additions — Adoption of FIN 47  —   —   23,234 
Liabilities Incurred and Revisions of Estimates  18,739   (932)  11,244   4,492   18,739   (932)
Liabilities Settled  (6,871)  (6,108)  (1,303)  (13,155)  (6,871)  (6,108)
Accretion Expense  5,440   5,394   2,671   6,789   5,440   5,394 
Exchange Rate Impact  —   193   135   —   —   193 
              
Balance at End of Year $93,247  $75,939  $77,392  $91,373  $93,247  $75,939 
              


7782

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Note C —Regulatory Matters
Note C — Regulatory Matters
 
Regulatory Assets and Liabilities
 
The Company has recorded the following regulatory assets and liabilities:
 
                
 At September 30  At September 30 
 2008 2007  2009 2008 
 (Thousands)  (Thousands) 
Regulatory Assets(1):
                
Pension and Other Post-Retirement Benefit Costs(2) (Note G) $147,909  $98,787 
Pension and Other Post-Retirement Benefit Costs(2) (Note H) $461,352  $147,909 
Recoverable Future Taxes (Note D)  82,506   83,954   138,435   82,506 
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A)  37,708   14,769 
Environmental Site Remediation Costs(2) (Note H)  22,530   20,738 
NYPSC Assessment(2)  24,445   — 
Environmental Site Remediation Costs(2) (Note I)  21,456   22,530 
Asset Retirement Obligations(2) (Note B)  8,155   8,315   7,884   8,155 
Unamortized Debt Expense (Note A)  7,524   8,470   6,610   7,524 
Recoverable Worker Compensation Expense(2)  4,518   4,445 
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A)  —   37,708 
Other(2)  6,475   5,292   15,776   10,993 
          
Total Regulatory Assets  317,325   244,770   675,958   317,325 
          
Regulatory Liabilities:
                
Cost of Removal Regulatory Liability (Note B)  103,100   91,226 
Pension and Other Post-Retirement Benefit Costs(3) (Note G)  42,994   21,676 
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)  105,778   2,753 
Cost of Removal Regulatory Liability  105,546   103,100 
Taxes Refundable to Customers (Note D)  67,046   18,449 
Pension and Other Post-Retirement Benefit Costs(3) (Note H)  61,003   42,994 
Tax Benefit on Medicare Part D Subsidy(3)  23,502   19,147   28,817   23,502 
New York Rate Settlements(3)  19,012   27,964 
Taxes Refundable to Customers (Note D)  18,449   14,026 
Off-System Sales and Capacity Release Credits(3)  8,340   8,977 
Deferred Insurance Proceeds(3)  3,933   7,422   3,804   3,933 
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)  2,753   10,409 
Other(3)  2,492   450   18,265   12,527 
          
Total Regulatory Liabilities  216,235   192,320   398,599   216,235 
          
Net Regulatory Position $101,090  $52,450  $277,359  $101,090 
          
 
 
(1)The Company recovers the cost of its regulatory assets but with the exception of Unrecovered Purchased Gas Costs,generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
 
(2)Included in Other Regulatory Assets on the Consolidated Balance Sheets.
 
(3)Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
 
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheetConsolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.


7883

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
New York Rate SettlementsCost of Removal Regulatory Liability
 
With respect to utility services providedIn the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in New York,Note B — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has entered into rate settlements approved bycollected dollars from the NYPSC. The rate settlements have given rise to several significant liabilities, which are described as follows:
Gross Receipts Tax Over-Collections — In accordance with NYPSC policies, Distribution Corporation deferred the difference between the revenues it collects under a New York State gross receipts tax surcharge and its actual New York State income tax expense. Distribution Corporation’s cumulative gross receipts tax revenues exceeded its New York State income tax expense, resulting in a regulatory liability at September 30, 2008 and 2007 of $4.1 million and $6.7 million, respectively. Under the terms of its 2005 rate agreement, Distribution Corporation has been passing backcustomer that regulatory liability to rate payers since August 1, 2005. Further, the gross receipts tax surcharge that gave rise to the regulatory liability was eliminated from Distribution Corporation’s tariff (New York State income taxes are now recovered as a component of base rates).
Cost Mitigation Reserve (“CMR”) — The CMR is a regulatory liability that canwill be used to offset certain expense items specified in Distribution Corporation’s rate settlements. The source of the CMR was principally the accumulation of certain refunds from upstream pipeline companies. During 2005, under the terms of the 2005 rate agreement, Distribution Corporation transferred the remaining balance in a generic restructuring reserve (which had been established in a prior rate settlement) and the balances it had accumulated under various earnings sharing mechanisms to the CMR. The balance in the CMR at September 30, 2008 and 2007 amounted to $0.3 million and $7.4 million, respectively.
Other — The 2005 agreement also established a reservefuture to fund area development projects. The balance in the area development projects reserve at September 30, 2008 and 2007 amounted to $3.0 million and $3.6 million, respectively (Distribution Corporation established the reserve at September 30, 2005 by transferring $3.8 million from the CMR discussed above). Various other regulatory liabilities have also been created through the New York rate settlements and amounted to $11.6 million and $10.3 million at September 30, 2008 and 2007, respectively.asset retirement costs.
 
Tax Benefit on Medicare Part D Subsidy
 
The Company has established a regulatory liability for the tax benefit it will receive under the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act). The Act provides a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In the Company’s Utility and Pipeline and Storage segments, the ratepayercustomer funds the Company’s post-retirement benefit plans. As such, any tax benefit received under the Act must be flowed-through to the ratepayer.customer. Refer to Note GH — Retirement Plan and Other Post-Retirement Benefits for further discussion of the Act and its impact on the Company.
 
Deferred Insurance Proceeds
 
The Company, in its Utility and Pipeline and Storage segments,segment, has deferred environmental insurance settlement proceeds amounting to $3.9$3.8 million and $7.4$3.9 million at September 30, 20082009 and 2007,2008, respectively. Such proceeds have been deferred as a regulatory liability to be applied against any future environmental claims that may be incurred. The proceeds have been classified as a regulatory liability in recognition of the fact that ratepayerscustomers funded the premiums on the former insurance policies.
 
Recoverable Worker Compensation ExpenseNYPSC Assessment
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the current rate ofone-third of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge equal, as applied, to an additional one percent of the utility’s gross operating revenue. The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills in the Utility segment’s New York jurisdiction.
Off-System Sales and Capacity Release Credits
 
The Company, has established a liability in its Utility segment, in accordancehas entered into off-system sales and capacity release transactions. Most of the margins on such transactions are returned to the customer with only a small percentage being retained by the provisions of SFAS 112 for future worker compensation liabilities. Such amounts haveCompany. The amount owed to the customer has been deferred as a regulatory asset because the Company is allowed to recover worker compensation expense in rates.liability.


7984

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note D —Income Taxes
Note D — Income Taxes
 
The components of federal, state and foreign income taxes included in the Consolidated Statements of Income are as follows:
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
   (Thousands)      (Thousands)   
Current Income Taxes —                        
Federal $75,079  $99,608  $65,593  $43,300  $75,079  $99,608 
State  20,257   21,700   13,511   10,341   20,257   21,700 
Foreign  90   22   2,212   —   90   22 
Deferred Income Taxes —                        
Federal  56,668   39,340   19,111   (4,940)  56,668   39,340 
State  15,828   10,751   9,024   2,419   15,828   10,751 
Foreign  —   2,756   (33,365)  —   —   2,756 
              
  167,922   174,177   76,086   51,120   167,922   174,177 
Deferred Investment Tax Credit  (697)  (697)  (697)  (697)  (697)  (697)
              
Total Income Taxes $167,225  $173,480  $75,389  $50,423  $167,225  $173,480 
              
Presented as Follows:                        
Other Income $(697) $(697) $(697) $(697) $(697) $(697)
Income Tax Expense — Continuing Operations  167,922   131,813   108,245   51,120   167,922   131,813 
Discontinued Operations —                        
Income From Operations  —   2,792   (32,159)  —   —   2,792 
Gain on Disposal  —   39,572   —   —   —   39,572 
              
Total Income Taxes $167,225  $173,480  $75,389  $50,423  $167,225  $173,480 
              
 
The U.S. and foreign components of income (loss) before income taxes are as follows:
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
   (Thousands)    (Thousands) 
U.S.  $435,982  $496,074  $293,887  $151,160  $435,982  $496,074 
Foreign  (29)  14,861   (80,407)  (29)  (29)  14,861 
              
 $435,953  $510,935  $213,480  $151,131  $435,953  $510,935 
              


8085

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (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  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
   (Thousands)    (Thousands) 
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $152,584  $178,827  $74,718  $52,896  $152,584  $178,827 
Increase in Taxes Resulting from:            
Increase (Reduction) in Taxes Resulting from:            
State Income Taxes  23,455   21,093   14,648   8,294   23,455   21,093 
Foreign Tax Differential  69   (20,980)  (3,718)  10   69   (20,980)
Reversal of Capital Loss Valuation Allowance  —   —   (2,877)
Miscellaneous  (8,883)  (5,460)  (7,382)  (10,777)  (8,883)  (5,460)
              
Total Income Taxes $167,225  $173,480  $75,389  $50,423  $167,225  $173,480 
              
 
The foreign tax differential amount shown above for 2007 includes tax effects relating to the gain on disposition of a foreign subsidiary. Also, the foreign tax differential amount shown above for 2006 includes a $5.1 million deferred tax benefit relating to additional future tax deductions forecasted in Canada. The miscellaneous amount shown above for 2006 includes a net reversal of $3.2 million relating to a tax contingency reserve.
 
Significant components of the Company’s deferred tax liabilities and assets are as follows:
 
                
 At September 30  At September 30 
 2008 2007  2009 2008 
 (Thousands)  (Thousands) 
Deferred Tax Liabilities:                
Property, Plant and Equipment $673,313  $612,648  $733,581  $673,313 
Pension and Other Post-Retirement Benefit Costs — SFAS 158  43,340   21,892 
Pension and Other Post-Retirement Benefit Costs  164,120   43,340 
Other  55,391   39,724   69,297   55,391 
          
Total Deferred Tax Liabilities  772,044   674,264   966,998   772,044 
          
Deferred Tax Assets:                
Pension and Other Post-Retirement Benefit Costs — SFAS 158  (43,340)  (21,892)
Pension and Other Post-Retirement Benefit Costs  (202,627)  (55,309)
Other  (92,461)  (85,566)  (154,358)  (80,492)
          
Total Deferred Tax Assets  (135,801)  (107,458)  (356,985)  (135,801)
          
Total Net Deferred Income Taxes $636,243  $566,806  $610,013  $636,243 
          
Presented as Follows:                
Net Deferred Tax Liability/(Asset) — Current $1,871  $(8,550) $(53,863) $1,871 
Net Deferred Tax Liability — Non-Current  634,372   575,356   663,876   634,372 
          
Total Net Deferred Income Taxes $636,243  $566,806  $610,013  $636,243 
          
As of September 30, 2009, the Company recorded a deferred tax asset relating to a federal net operating loss carryover of $25.1 million. This carryover, which is available as a result of an acquisition, expires in varying amounts between 2023 and 2029. Although this loss carryover is subject to certain annual limitations, no valuation allowance was recorded because of management’s determination that the amount will be fully utilized during the carryforward period.
 
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $18.4$67.0 million and $14.0$18.4 million at September 30, 20082009 and 2007,2008, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $82.5 million and $84.0 million at September 30, 2008 and 2007, respectively.


8186

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
of prior ratemaking practices, amounted to $138.4 million and $82.5 million at September 30, 2009 and 2008, respectively.
During fiscal 2009, consent was received from the Internal Revenue Service (IRS) National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. Included in the regulatory liabilities and assets as of September 30, 2009 noted above are liabilities of $47.3 million and assets of $51.1 million associated with this tax accounting method change.
The Company adopted FIN 48the FASB authoritative guidance for income tax uncertainties on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million, all of which would impact the effective tax rate (net of federal benefit) if recognized.million.
 
A tabular reconciliation of the change in unrecognized tax benefits for the twelve monthsyear ended September 30, 2009 and 2008 is as follows:
 
     
  Amount 
  (thousands) 
 
Opening Balance of Unrecognized Tax Benefits — October 1, 2007 $1,700 
Gross Increase — Tax Positions in Prior Periods  — 
Gross Decrease — Tax Positions in Prior Periods  — 
Gross Increase — Tax Positions in Current Periods  — 
Gross Decrease — Tax Positions in Current Periods  — 
Decrease in Unrecognized Tax Benefits Related to Tax Settlements  — 
Reduction to Unrecognized Tax Benefits Due to Lapse of Statute of Limitations  — 
     
Ending Balance of Unrecognized Tax Benefits — September 30, 2008 $1,700 
     
         
  Year Ended September 30 
  2009  2008 
  (Thousands) 
 
Balance at Beginning of Year $1,700  $1,700 
Additions for Tax Positions Related to Current Year  8,721   — 
Additions for Tax Positions of Prior Years  —   — 
Reductions for Tax Positions of Prior Years  —   — 
Settlements with Taxing Authorities  (1,700)  — 
Lapse of Statute of Limitations  —   — 
         
Balance at End of Year $8,721  $1,700 
         
 
WithinThe balance of $8.7 million as of September 30, 2009 relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Due to the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not materially affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company anticipates that the unrecognized tax benefits will not significantly change within the next twelve months, the Company believes it is reasonably possible that the total amount of unrecognized tax benefits may be eliminated. This potential decrease in the amount of unrecognized tax benefits is associated with the anticipated completion of state income tax audits for various prior years.months.
 
The Company recognizes estimated interest payable relating to income taxes in Other Interest Expense and estimated penalties relating to income taxes in Other Income. The Company has accrueddid not recognize any interest expense related to income taxes during fiscal 2009. The Company recognized interest expense related to income taxes of $0.5 million through September 30, 2008 andduring fiscal 2008. The Company has not accrued any penalties.penalties during fiscal 2009 and 2008.
 
The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS)IRS is currently conducting an examination of the Company for fiscal 20082009 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 20052006 and later years, IRS examinations for fiscal 20072008 and prior years have been completed and the Company believes such years are effectively settled.
 
ForThe Company is also subject to various routine state income tax examinations. The Company’s operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the major states in whichdate of filing of the various subsidiary companies operate, the earliestincome tax year open for examination is as follows:
New YorkFiscal 2002
PennsylvaniaFiscal 2003
CaliforniaFiscal 2004
TexasFiscal 2004
return.


8287

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note E —Capitalization and Short-Term Borrowings
Note E — Capitalization and Short-Term Borrowings
 
Summary of Changes in Common Stock Equity
 
                                        
       Earnings
 Accumulated
        Earnings
 Accumulated
 
       Reinvested
 Other
        Reinvested
 Other
 
     Paid
 in
 Comprehensive
      Paid
 in
 Comprehensive
 
 Common Stock In
 the
 Income
  Common Stock In
 the
 Income
 
 Shares Amount Capital Business (Loss)  Shares Amount Capital Business (Loss) 
 (Thousands, except per share amounts)    (Thousands, except per share amounts)   
Balance at September 30, 2005  84,357  $84,357  $529,834  $813,020  $(197,628)
Net Income Available for Common Stock              138,091     
Dividends Declared on Common Stock ($1.18 Per Share)              (98,829)    
Other Comprehensive Income, Net of Tax                  228,044 
Share-Based Payment Expense(2)          1,705         
Common Stock Issued Under Stock and Benefit Plans(1)  1,572   1,572   28,564         
Share Repurchases  (2,526)  (2,526)  (16,373)  (66,269)    
           
Balance at September 30, 2006  83,403   83,403   543,730   786,013   30,416   83,403  $83,403  $543,730  $786,013  $30,416 
           
Net Income Available for Common Stock              337,455                   337,455     
Dividends Declared on Common Stock ($1.22 Per Share)              (101,496)                  (101,496)    
Other Comprehensive Loss, Net of Tax                  (24,137)                  (24,137)
Adjustment to Recognize the Funded Position of the Pension and Other Post-Retirement Benefit Plans                  (12,482)                  (12,482)
Share-Based Payment Expense(2)          3,727                   3,727         
Common Stock Issued Under Stock and Benefit Plans(1)  1,367   1,367   30,193           1,367   1,367   30,193         
Share Repurchases  (1,309)  (1,309)  (8,565)  (38,196)      (1,309)  (1,309)  (8,565)  (38,196)    
                      
Balance at September 30, 2007  83,461   83,461   569,085   983,776   (6,203)  83,461   83,461   569,085   983,776   (6,203)
                      
Net Income Available for Common Stock              268,728                   268,728     
Dividends Declared on Common Stock ($1.27 Per Share)              (103,523)                  (103,523)    
Cumulative Effect of the Adoption of FIN 48              (406)    
Other Comprehensive Loss, Net of Tax                  9,166 
Cumulative Effect of the Adoption of Authoritative Guidance for Income Taxes              (406)    
Other Comprehensive Income, Net of Tax                  9,166 
Share-Based Payment Expense(2)          2,332                   2,332         
Common Stock Issued Under Stock and Benefit Plans(1)  854   854   33,335           854   854   33,335         
Share Repurchases  (5,194)  (5,194)  (37,036)  (194,776)      (5,194)  (5,194)  (37,036)  (194,776)    
                      
Balance at September 30, 2008  79,121  $79,121  $567,716  $953,799(3) $2,963   79,121   79,121   567,716   953,799   2,963 
                      
Net Income Available for Common Stock              100,708     
Dividends Declared on Common Stock ($1.32 Per Share)              (105,410)    
Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans              (804)    
Other Comprehensive Loss, Net of Tax                  (45,359)
Share-Based Payment Expense(2)          2,055         
Common Stock Issued Under Stock and Benefit Plans(1)  1,379   1,379   33,068         
           
Balance at September 30, 2009  80,500  $80,500  $602,839  $948,293(3) $(42,396)
           


88

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
(1)Paid in Capital includes tax benefits of $5.9 million, $16.3 million $13.7 million and $6.5$13.7 million for September 30, 2009, 2008 2007 and 2006,2007, respectively, associated with the exercise of stock options.
 
(2)As of October 1, 2005, Paid in Capital includes compensation costs associated with stock option, stock-settled SARs and/or restricted stock awards, in accordance with SFAS 123R.awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.
 
(3)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, 2008, $808.82009, $804.1 million of accumulated earnings was free of such limitations.


83

 
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Common Stock
 
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.
 
During 2008,2009, the Company issued 890,9441,609,597 original issue shares of common stock as a result of stock option exercises and 25,00063,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R)existing guidance). Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise pricesand/or applicable withholding taxes. During 2008, 72,2052009, 303,091 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
 
The Company also has a director stock program under which it issues shares of Company common stock to the eight non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, as partial consideration for their services as directors.the directors’ services. Under this program, the Company issued 9,6009,865 original issue shares of common stock during 2008.2009.
 
In December 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, suchSuch repurchases may be made in the future if conditions improve. Allfuture. The share repurchases mentioned above were funded with cash provided by operating activitiesand/or through the use of the Company’s lines of credit.
 
Shareholder Rights Plan
 
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended fiveseveral times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective July 11, 2008, which is an Exhibit to this Annual Report and


89

Form 10-K.NATIONAL FUEL GAS COMPANY
 
TheNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Agreement effective December 4, 2008, a copy of which was included as an exhibit to theForm 8-K filed by the Company on December 4, 2008.
Pursuant to the Plan, the holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
 
The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors (an Acquiring Person).
 
The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and void. At any time following a


84

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Distribution Date, each holder of a Right may exercise its right to receive, a numberupon payment of shares ofan amount calculated under the Rights Agreement, common stock determined in accordance with a Plan formula that is based on the current market value of the Company’s common stock. UnderCompany (or, under certain circumstances, each holder of a Right may instead receive other propertysecurities or assets of the Company.Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
 
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.
 
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to exercise its Rights to receive, a numberupon exercise of shares ofthe right, common stock determined in accordance with a Plan formula based on the current market value of the Company’s common stock, or other property ofacquiring company having a value equal to two times the Company.amount paid to exercise the right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power are sold or transferred.
 
At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
 
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.
 
Stock Option and Stock Award Plans
 
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock-settled SARs, restricted stock, performance units or performance shares. Stock options and stock-settled SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option or stock-settled SAR is exercisable less than one year or more than ten years after the date of each grant.


8590

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
grant, and generally no option or stock-settled SAR is exercisable less than one year or more than ten years after the date of each grant.
Transactions involving option shares for all plans are summarized as follows:
 
                 
        Weighted
    
        Average
    
  Number of
     Remaining
  Aggregate
 
  Shares Subject
  Weighted Average
  Contractual
  Intrinsic
 
  to Option  Exercise Price  Life (Years)  Value 
           (In thousands) 
 
Outstanding at September 30, 2007  7,360,041  $25.89         
Granted in 2008  —  $—         
Exercised in 2008  (890,944) $23.78         
Forfeited in 2008  (4,400) $27.97         
                 
Outstanding at September 30, 2008  6,464,697  $26.17   3.11  $103,477 
                 
Option shares exercisable at September 30, 2008  6,337,697  $25.94   3.02  $102,909 
                 
Option shares available for future grant at September 30, 2008(1)  745,797             
                 
                 
        Weighted
    
        Average
    
  Number of
     Remaining
  Aggregate
 
  Shares Subject
  Weighted Average
  Contractual
  Intrinsic
 
  to Option  Exercise Price  Life (Years)  Value 
           (In thousands) 
 
Outstanding at September 30, 2008  6,464,697  $26.17         
Granted in 2009  —  $—         
Exercised in 2009  (1,609,597) $23.15         
Forfeited in 2009  —  $—         
                 
Outstanding at September 30, 2009  4,855,100  $27.18   2.80  $90,463 
                 
Option shares exercisable at September 30, 2009  4,755,100  $26.92   2.71  $89,832 
                 
Option shares available for future grant at September 30, 2009(1)  72,797             
                 
 
 
(1)Including shares available for stock-settled SARs and restricted stock grants.
 
Transactions involving non-performance based stock-settled SARs for all plans are summarized as follows:
 
                 
        Weighted
    
        Average
    
  Number of
     Remaining
  Aggregate
 
  Shares Subject
  Weighted Average
  Contractual
  Intrinsic
 
  To Option  Exercise Price  Life (Years)  Value 
           (In thousands) 
 
Outstanding at September 30, 2007  50,000  $41.20         
Granted in 2008  —  $—         
Exercised in 2008  —  $—         
Forfeited in 2008  —  $—         
                 
Outstanding at September 30, 2008  50,000  $41.20   8.45  $49 
                 
Stock-settled SARs exercisable at September 30, 2008  —   —   —  $— 
                 
                 
        Weighted
    
        Average
    
  Number of
     Remaining
  Aggregate
 
  Shares Subject
  Weighted Average
  Contractual
  Intrinsic
 
  To Option  Exercise Price  Life (Years)  Value 
           (In thousands) 
 
Outstanding at September 30, 2008  50,000  $41.20         
Granted in 2009  —  $—         
Exercised in 2009  —  $—         
Forfeited in 2009  —  $—         
                 
Outstanding at September 30, 2009  50,000  $41.20   7.45  $231 
                 
Stock-settled SARs exercisable at September 30, 2009  —   —   —  $— 
                 


8691

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Transactions involving performance based stock-settled SARs for all plans are summarized as follows:
 
                 
        Weighted
    
        Average
    
  Number of
     Remaining
  Aggregate
 
  Shares Subject
  Weighted Average
  Contractual
  Intrinsic
 
  To Option  Exercise Price  Life (Years)  Value 
           (In thousands) 
 
Outstanding at September 30, 2007  —  $—         
Granted in 2008  321,000  $48.46         
Exercised in 2008  —  $—         
Forfeited in 2008  (6,000) $58.99         
                 
Outstanding at September 30, 2008  315,000  $48.26   9.42  $(1,914)
                 
Stock-settled SARs exercisable at September 30, 2008  —   —   —  $— 
                 
                 
        Weighted
    
        Average
    
  Number of
     Remaining
  Aggregate
 
  Shares Subject
  Weighted Average
  Contractual
  Intrinsic
 
  To Option  Exercise Price  Life (Years)  Value 
           (In thousands) 
 
Outstanding at September 30, 2008  315,000  $48.26         
Granted in 2009  610,000  $29.88         
Exercised in 2009  —  $—         
Forfeited in 2009  —  $—         
                 
Outstanding at September 30, 2009  925,000  $36.14   8.96  $8,947 
                 
Stock-settled SARs exercisable at September 30, 2009  96,984  $47.37   8.40  $— 
                 
 
Restricted Share Awards
 
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
 
Transactions involving restricted shares for all plans are summarized as follows:
 
         
  Number of
  Weighted Average
 
  Restricted
  Fair Value per
 
  Share Awards  Award 
 
Restricted Share Awards Outstanding at September 30, 2007  36,328  $38.16 
Granted in 2008  25,000  $48.41 
Vested in 2008  (2,500) $34.94 
Forfeited in 2008  —  $— 
         
Restricted Share Awards Outstanding at September 30, 2008  58,828  $42.65 
         
         
  Number of
  Weighted Average
 
  Restricted
  Fair Value per
 
  Share Awards  Award 
 
Restricted Share Awards Outstanding at September 30, 2008  58,828  $42.65 
Granted in 2009  63,000  $47.46 
Vested in 2009  (3,828) $31.30 
Forfeited in 2009  —  $— 
         
Restricted Share Awards Outstanding at September 30, 2009  118,000  $46.59 
         
 
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 20082009 will lapse as follows: 2009 — 2,500 shares; 2010 — 28,82827,500 shares; 2011 — 2,500 shares; 2012 — 5,000 shares; 2013 — 5,000 shares; 2014 — 5,000 shares; 2015 — 5,00013,000 shares; and 2016 — 5,000 shares; 2018 — 35,000 shares; and 2021 — 20,000 shares.
 
Redeemable Preferred Stock
 
As of September 30, 2007,2009, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.


8792

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Long-Term Debt
 
The outstanding long-term debt is as follows:
 
                
 At September 30  At September 30 
 2008 2007  2009 2008 
 (Thousands)  (Thousands) 
Medium-Term Notes(1):                
6.0% to 7.50% due March 2009 to June 2025 $549,000  $749,000 
6.7% to 7.50% due November 2010 to June 2025 $449,000  $549,000 
Notes(1):                
5.25% to 6.5% due March 2013 to September 2022(2)  550,000   250,000 
     
  1,099,000   999,000 
     
Other Notes:        
Unsecured  —   24 
5.25% to 8.75% due March 2013 to May 2019  800,000   550,000 
          
Total Long-Term Debt  1,099,000   999,024   1,249,000   1,099,000 
Less Current Portion  100,000   200,024   —   100,000 
          
 $999,000  $799,000  $1,249,000  $999,000 
          
 
 
(1)The medium-term notesMedium-Term Notes and notesNotes are unsecured.
(2)In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private placement exempt from registration under the Securities Act of 1933. The notes have a term of 10 years, with a maturity date in April 2018. The holders of the notes may require the Company to repurchase their notes in the event of a change in control at a price equal to 101% of the principal amount. In addition, the Company is required to either offer to exchange the notes for substantially similar notes registered under the Securities Act of 1933 or, in certain circumstances, register the resale of the notes. The Company used $200.0 million of the proceeds from the sale of the notes to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008.
In April 2009, the Company issued $250.0 million of 8.75% notes due in May 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. These notes were registered under the Securities Act of 1933. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company’s 6.0% medium-term notes on March 1, 2009.
In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private placement exempt from registration under the Securities Act of 1933. In February 2009, the Company exchanged the notes for economically identical notes registered under the Securities Act of 1933. The notes have a term of 10 years, with a maturity date in April 2018. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The Company used $200.0 million of the proceeds of the issuance to refund $200.0 million of 6.303% medium-term notes that matured on May 27, 2008.
 
As of September 30, 2008,2009, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $100.0 million in 2009, zero in 2010, $200.0 million in 2011, $150.0 million in 2012, $250.0 million in 2013, zero in 2014, and $399.0$649.0 million thereafter.
 
Short-Term Borrowings
 
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These uncommitted credit lines, which aggregate to $420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million that extends through September 30, 2010.
 
At September 30, 20082009 and 2007,2008, the Company had no outstanding short-term notes payable to banks or commercial paper.


8893

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Debt Restrictions
 
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At September 30, 2008,2009, the Company’s debt to capitalization ratio (as calculated under the facility) was .41..44. The constraints specified in the committed credit facility would permit an additional $1.88$1.7 billion in short-termand/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.
 
Under the Company’s existing indenture covenants, at September 30, 2008,2009, the Company would have been permitted to issue up to a maximum of $1.3 billion$435.0 million in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. If the Company were to experience another impairment of oil and gas properties in the future, it is possible that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness. This would not preclude the Company from issuing new indebtedness to replace maturing debt.
 
The Company’s 1974 indenture pursuant to which $199.0$99.0 million (or 18%7.9%) of the Company’s long-term debt (as of September 30, 2008)2009) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest oron any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
 
The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2008,2009, the Company had no debt outstanding under the committed credit facility.
 
Note F —Financial Instruments
Note F — Fair Value Measurements
Beginning in fiscal 2009, the Company adopted the FASB authoritative guidance regarding fair value measurements which establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The adoption of this authoritative guidance regarding fair value measurements has not had a significant impact on the consolidated financial statements.


94

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
                 
  At fair Value as of September 30, 2009 
Recurring Fair Value Measures
 Level 1  Level 2  Level 3  Total 
  (Dollars in thousands) 
 
Assets:                
Cash Equivalents $390,462  $—  $—  $390,462 
Derivative Financial Instruments  5,312   12,536   26,969   44,817 
Other Investments  24,276   —   —   24,276 
Hedging Collateral Deposits  848   —   —   848 
                 
Total $420,898  $12,536  $26,969  $460,403 
                 
Liabilities:                
Derivative Financial Instruments $—  $2,148  $—  $2,148 
                 
Total $—  $2,148  $—  $2,148 
                 
Cash Equivalents
The cash equivalents reported in Level 1 consist of SEC registered money market mutual funds.
Derivative Financial Instruments
The derivative financial instruments reported in Level 1 consist of NYMEX futures contracts. The hedging collateral deposits associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in the Company’s Exploration and Production segment and natural gas swap agreements used in the Energy Marketing segment. The fair value of these natural gas swap agreements is based on an internal model that uses observable inputs. The fair market value of the price swap agreements reported in Level 2 as assets has been reduced by $0.2 million based on an assessment of counterparty credit risk. The derivative financial instruments reported in Level 3 consist of all of the Exploration and Production segment’s crude oil swap agreements. The fair value of the crude oil swap agreements is based on an internal model that uses both observable and unobservable inputs. The fair market value of the price swap agreements reported in Level 3 as assets has been reduced by $0.7 million based on an assessment of counterparty credit risk. The fair market value of the price swap agreements reported in Level 2 as liabilities has been reduced by less than $0.1 million based on an assessment of the Company’s credit risk. This credit reserve, as well as the credit reserve established for the Level 2 and Level 3 swap agreement assets, was determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.
Other Investments
The other investments reported in Level 1 consist of publicly traded equity securities and a publicly traded balanced equity mutual fund.
The table listed below provides a reconciliation of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3.


95

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Fair ValuesValue Measurements Using Unobservable Inputs (Level 3)
                     
     Total Gains/Losses—
       
     Realized and Unrealized       
        Included in Other
  Transfer
    
  October 1,
  Included in
  Comprehensive Income
  In/(Out) of
  September 30,
 
  2008  Earnings  (Loss)  Level 3  2009 
  (Dollars in thousands) 
 
Assets:
                    
Derivative Financial Instruments $7,110  $(47,076)(1) $75,077  $(8,142)(2) $26,969 
                     
Total $7,110  $(47,076) $75,077  $(8,142) $26,969 
                     
Liabilities:
                    
Derivative Financial Instruments $(777) $(12,104)(1) $12,070  $811(2) $— 
                     
Total $(777) $(12,104) $12,070  $811  $— 
                     
(1)Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2009.
(2)These transfers occurred because the Company was able to obtain and utilize forward-looking, observable basis differential information for its hedges on southern California natural gas production.
Note G — Financial Instruments
Long-Term Debt
 
TheAt September 30, 2009, the fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit risk in determining the yield, and subsequently, the fair market value of the debt. At September 30, 2008, the fair market value of the Company’s long-term debt is estimatedwas determined 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 
  2008 Carrying
  2008 Fair
  2007 Carrying
  2007 Fair
 
  Amount  Value  Amount  Value 
  (Thousands) 
 
Long-Term Debt $1,099,000  $1,027,098  $999,024  $1,024,417 
                 
                 
  At September 30 
  2009 Carrying
  2009 Fair
  2008 Carrying
  2008 Fair
 
  Amount  Value  Amount  Value 
  (Thousands) 
 
Long-Term Debt $1,249,000  $1,347,368  $1,099,000  $1,027,098 
                 
 
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value.
 
Temporary cash investments, notes payable to banks and commercial paper are stated at cost, which approximates their fair value due to the short-term maturities of those financial instruments.Other Investments in life


89

NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
 
Other Investments
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $53.6$54.2 million and $54.7$53.6 million at September 30, 20082009 and 2007,2008, respectively. The fair value of the equity mutual fund was $12.4$15.8 million and $14.7$12.4 million at September 30, 20082009 and 2007, 2008,


96

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
respectively. The gross unrealized loss on this equity mutual fund was $(1.0)$1.0 million at September 30, 2008. The equity mutual fund was in a gross unrealized gain position of $2.2 million at2009 and September 30, 2007.2008. Although this investment has been in an unrealized loss position for over twelve months, management has the intent and ability to hold the investment for a sufficient period of time for the asset to recover in value. As such, management does not consider this investment to be other than temporarily impaired. The fair value of the stock of an insurance company was $14.5$8.3 million and $16.3$14.5 million at September 30, 20082009 and 2007,2008, respectively. The gross unrealized gain on this stock was $12.1$5.9 million and $13.8$12.1 million at September 30, 20082009 and 2007,2008, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
 
Derivative Financial Instruments
 
The Company uses a variety ofis exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative financial instruments to manage a portion of the marketis commodity price risk associated with the fluctuations in the price of natural gasExploration and crude oil. These instruments include priceProduction and Energy Marketing segments. The Company enters into futures contracts andover-the-counter swap agreements no cost collars and futures contracts.
Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed price and a variable price as specified by the agreement. The variable price is either a crude oil or natural gas price quoted on the NYMEX or a quoted natural gas price in various national natural gas publications. The majority of these derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price for the anticipated sale of natural gas and crude oil productionto manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, and withdrawal of gas from storage to meet customer demand. The duration of the Company’s hedges do not typically exceed 3 years and the majority of the positions settle within one year.
The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheet at September 30, 2009 as shown in the table below.
             
  Fair Values of Derivative Instruments
  (Dollar Amounts in Thousands)
  Asset Derivatives
 Liability Derivatives
Derivatives
 September 30, 2009 September 30, 2009
Designated as
 Consolidated
   Consolidated
  
Hedging
 Balance Sheet
   Balance Sheet
  
Instruments
 Location Fair Value Location Fair Value
 
Commodity
Contracts		 Fair Value of
Derivative
Financial
Instruments		 $44,817  Fair Value of
Derivative
Financial
Instruments		 $2,148 
The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheet at September 30, 2009.
     
Derivatives
 Fair Values of Derivative Instruments
Designated as
 (Dollar Amounts in Thousands)
Hedging
 Gross Asset Derivatives
 Gross Liability Derivatives
Instruments
 September 30, 2009 September 30, 2009
 
  Fair Value Fair Value
Commodity
Contracts		 $63,601 $20,932
Cash Flow Hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
As of September 30, 2009, the Company’s Exploration and Production segment andhad the All Other category. The Energy Marketing segment accounts for thesefollowing commodity derivative financial instruments as fair value hedges and uses themcontracts (swaps) outstanding to hedge against falling prices, a risk to which they are exposed on their fixed price gas purchase commitments. The Energy Marketing segment also uses these derivative financial instruments to hedge against rising prices, a risk to which they are exposed on their fixed priceforecasted sales commitments. At September 30, 2008,(where the Company had natural gas price swap agreements covering a notional amount of 15.1 Bcf extending through 2011 at a weighted average fixed rate of $9.69 per Mcf. Of this amount, 0.9 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $9.64 per Mcf. The remaining 14.2 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $9.69 per Mcf. At September 30, 2008, the Company would have received a net $20.3 million to terminate the price swap agreements. The Company also had crude oil price swap agreements covering a notional amount of 1,920,000 bbls extending through 2011 at a weighted average fixed rate of $90.50 per bbl. At September 30, 2008, the Company would have had to pay a net $0.8 million to terminate the price swap agreements. The Energy Marketing segment also used natural gas swaps to hedge basis risk on their fixed price purchase commitments. At September 30, 2008, the Company had natural gas swap agreements covering 1.4 Bcf at a weighted average fixed rate of $0.47 per Mcf. These are treated as fair value hedges and the Company would have had to pay $0.2 million at September 30, 2008 to terminate the agreements.
At September 30, 2008, the Company had long (purchased) futures contracts covering 9.1 Bcf of gas extending through 2012 at a weighted average contract price of $9.24 per Mcf. They are accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with residential, commercial and industrial customers. The Company would have had to pay $9.9 million to terminate these futures contracts at September 30, 2008.uses short


9097

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Atpositions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):
Commodity
Units
Natural Gas36.9 Bcf (all short positions)
Crude Oil2,688,000 Bbls (all short positions)
As of September 30, 2008,2009, the Company’s Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):
Commodity
Units
Natural Gas6.4 Bcf (6.2 Bcf short positions (forecasted storage withdrawals) and 0.2 Bcf long positions (forecasted storage injections))
As of September 30, 2009, the Company’s Exploration and Production segment had short (sold) futures contracts covering 6.7 Bcf$36.2 million ($21.3 million after tax) of gas extending through 2010 at a weighted average contractgains included in the accumulated other comprehensive income balance. It is expected that $36.4 million ($21.4 million after tax) of these gains will be reclassified into income within the next 12 months as the sales of the underlying commodities are expected to occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note A includes both the Exploration and Production and Energy Marketing segments).
As of September 30, 2009, the Company’s Energy Marketing segment had $4.7 million ($2.8 million after tax) of losses included in the accumulated other comprehensive income (loss) balance. It is expected that $4.7 million ($2.8 million after tax) of these losses will be reclassified into income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note A includes both the Exploration and Production and Energy Marketing segments).


98

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                 
  The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
  Year Ended September 30, 2009 (Dollar Amounts in Thousands)
  Amount of
   Amount of
    
  Derivative Gain or
   Derivative Gain or
    
  (Loss) Recognized
 Location of
 (Loss) Reclassified
    
  in Other
 Derivative Gain or
 from Accumulated
   Derivative Gain or
  Comprehensive
 (Loss) Reclassified
 Other Comprehensive
 Location of
 (Loss) Recognized
  Income (Loss) on
 from Accumulated
 Income (Loss) on
 Derivative Gain or
 in the Consolidated
  the Consolidated
 Other Comprehensive
 the Consolidated
 (Loss) Recognized
 Statement of Income
  Statement of
 Income (Loss) on
 Balance Sheet into
 in the Consolidated
 (Ineffective
  Comprehensive
 the Consolidated
 the Consolidated
 Statement of Income
 Portion and Amount
  Income (Effective
 Balance Sheet into
 Statement of Income
 (Ineffective
 Excluded from
Derivatives in Cash
 Portion) for the
 the Consolidated
 (Effective Portion)
 Portion and Amount
 Effectiveness Testing)
Flow Hedging
 Year Ended
 Statement of Income
 for the Year Ended
 Excluded from
 for the Year Ended
Relationships
 September 30, 2009 (Effective Portion) September 30, 2009 Effectiveness Testing) September 30, 2009
 
Commodity Contracts — Exploration & Production segment $110,883  Operating Revenue $91,808  Operating Revenue $          — 
Commodity Contracts — Energy Marketing segment $7,492  Purchased Gas $21,301  Operating Revenue $          — 
Commodity Contracts — Pipeline & Storage segment(1) $652  Operating Revenue $1,952  Operating Revenue $          — 
Commodity Contracts — All Other(1) $183  Purchased Gas $(681) Purchased Gas $          — 
                 
Total $119,210    $114,380    $          — 
                 
(1)There were no open hedging positions at September 30, 2009. As such there is no mention of these positions in the preceding sections of this footnote.
Fair value hedges
The Company’s Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price of $11.02 per Mcf. Of this amount, 3.5 Bcf is accounted for as cash flow hedges as these contracts relatesales commitments, fixed price purchase commitments, and commitments related to the anticipated saleinjection and withdrawal of storage gas. In order to hedge fixed price sales commitments, the Company enters into long positions to mitigate the risk that after the Company enters into fixed price sales agreements with its customers, the price of natural gas byincreases (thereby passing up the opportunity for higher operating revenue). With fixed price purchase commitments, the Company enters into short positions to mitigate the risk that after the Company locks into fixed price purchase deals with its suppliers, the price of natural gas decreases (thereby passing up the opportunity for lower purchased gas expense). Fair value hedges related to the injection and withdrawal of storage gas impact purchased gas expense. As of September 30, 2009, the Company’s Energy Marketing segment. The remaining 3.2 Bcf is accounted for assegment had fair value hedges used to hedge against falling prices on theircovering approximately 13.0 Bcf (11.7 Bcf of fixed price sales commitments (all long positions), 0.9 Bcf of fixed price purchase commitments (all short positions), and 0.4 Bcf of commitments related to the withdrawal of storage gas purchasing commitments(all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, against decreasesthe gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in natural gas prices associated with the eventual sale of gas in storage. The Company would have received $18.6 million to terminate these futures contracts at September 30, 2008.current earnings, as shown below.
         
Consolidated Statement of Income
 Gain/(Loss) on Derivative Gain/(Loss) on Commitment
 
Operating Revenues $5,242,000  $(5,242,000)
Purchased Gas $(8,252,000) $8,252,000 

99

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
         
    Amount of
    Derivative Gain or
  Location of
 (Loss) Recognized
  Derivative Gain or
 in the Consolidated
  (Loss) Recognized
 Statement of Income
  in the Consolidated
 for the Year Ended
Derivatives in Fair Value Hedging Relationships
 Statement of Income September 30, 2009
    (In thousands)
 
Commodity Contracts — Energy Marketing segment(1)  Operating Revenues  $5,242 
Commodity Contracts — Energy Marketing segment(2)  Purchased Gas  $11 
Commodity Contracts — Energy Marketing segment(3)  Purchased Gas  $(8,263)
         
      $(3,010)
         
(1)Represents hedging of fixed price sales commitments of natural gas.
(2)Represents hedging of fixed price purchase commitments of natural gas.
(3)Represents hedging of storage withdrawal commitments of natural gas.
 
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on an ongoinga quarterly basis monitors counterparty credit exposure. Management has obtained guarantees from manyThe majority of the parent companies of the respectiveCompany’s counterparties to its derivativeare financial instruments.institutions and energy traders. The Company hasover-the-counter swap positions with ten counterparties. At September 30, 2008,2009, the Company had eleven counterparties for its over the counter derivative financial instruments and no individual counterparty represented greater than 42% of total credit risk (measured as volumes hedged by an individual counterparty as a percentagethat were in gain positions with eight of the Company’s total over the counter volumes hedged).counterparties. The Company recorded a $0.6had derivative financial instruments that were in loss positions with the other two counterparties. The Company had $26.6 million reduction to the fair market value of its derivative contractscredit exposure with one counterparty (which is rated A1 (Moody’s Investor Service), A (S&P), and A+ (Fitch Ratings Service) as of September 30, 2009). On average for those financial instruments that arewere in a gain position, basedthe Company had $1.8 million of credit exposure per counterparty with the other seven counterparties that were in a gain position. The Company had not received any collateral from the counterparties at September 30, 2009 since the Company’s gain position on its assessmentsuch derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
As of counterparty credit risk. This credit reserve was determined by applying default probabilitiesSeptember 30, 2009, eight of the ten counterparties to the anticipated cash flows thatCompany’s outstanding derivative instrument contracts (specifically theover-the-counter swaps) had a common credit-risk-related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (the lower of the S&P or Moody’s Debt Rating), the available credit extended to the Company is expecting fromwould either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position and the Company’s credit rating declined, then additional hedging collateral deposits would be required. At September 30, 2009, these credit-risk related contingency features were not triggered since the Company had assets of $37.9 million related to derivative financial instruments with the eight counterparties.
 
Note G —Retirement Plan and Other Post-Retirement Benefits
For its exchange traded futures contracts, which are in an asset position, the Company had paid $0.8 million in hedging collateral as of September 30, 2009. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions (i.e. those positions that have been settled for cash) and margin requirements. (This is discussed in Note A under Hedging Collateral Deposits.)

100

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note H — Retirement Plan and Other Post-Retirement Benefits
 
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers approximately 65%a majority of the full-time employees of the Company. The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Employees hired after June 30, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account benefit have been $0.6 million through September 30, 2008 (with $0.2were $0.4 million, $0.2 million and $0.1$0.2 million of costs occurring infor the years ended September 30, 2009, 2008 and 2007, and 2006, respectively).respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans were $4.0$4.1 million, $4.1$4.0 million, and $4.1 million for the years ended September 30, 2009, 2008 2007 and 2006,2007, respectively.
 
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
 
The Company’s policy is to fund the Retirement Plan with 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. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations. Retirement Plan, VEBA trust and 401(h) account assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.


91

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The expected return on plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is equal to market value as of the measurement date.
 
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30, 2009, June 30, 2008 and June 30, 2007, for fiscal year 2009, 2008 and 2006,2007, respectively.
 
                         
  Retirement Plan  Other Post-Retirement Benefits 
  Year Ended September 30  Year Ended September 30 
  2008  2007  2006  2008  2007  2006 
  (Thousands) 
 
Change in Benefit Obligation
                        
Benefit Obligation at Beginning of Period $742,519  $732,207  $825,204  $444,545  $445,931  $546,273 
Service Cost  12,597   12,898   16,416   5,104   5,614   8,029 
Interest Cost  44,949   44,350   40,196   27,081   27,198   26,804 
Plan Participants’ Contributions  —   —   —   1,990   1,566   1,559 
Retiree Drug Subsidy Receipts  —   —   —   1,532   1,325   — 
Amendments(1)  —   —   —   (31,874)  —   — 
Actuarial (Gain) Loss  (34,189)  (2,986)  (108,112)  (14,390)  (14,450)  (115,052)
Benefits Paid  (46,817)  (43,950)  (41,497)  (22,443)  (22,639)  (21,682)
                         
Benefit Obligation at End of Period
 $719,059  $742,519  $732,207  $411,545  $444,545  $445,931 
                         
Change in Plan Assets
                        
Fair Value of Assets at Beginning of Period $765,144  $664,521  $616,462  $412,371  $325,624  $271,636 
Actual Return on Plan Assets  (39,206)  119,662   68,649   (43,478)  65,552   34,785 
Employer Contributions  3,817   16,488   20,907   29,200   42,268   39,326 
Employer Contributions During Period from Measurement Date to Fiscal Year End  12,151   8,423   —   —   —   — 
Plan Participants’ Contributions  —   —   —   1,990   1,566   1,559 
Benefits Paid  (46,817)  (43,950)  (41,497)  (22,443)  (22,639)  (21,682)
                         
Fair Value of Assets at End of Period
 $695,089  $765,144  $664,521  $377,640  $412,371  $325,624 
                         
Reconciliation of Funded Status
                        
Funded Status $(23,970) $22,625  $(67,686) $(33,905) $(32,174) $(120,307)
Unrecognized Net Actuarial Loss  —   —   107,626   —   —   54,487 
Unrecognized Transition Obligation  —   —   —   —   —   49,890 
Unrecognized Prior Service Cost  —   —   7,185   —   —   12 
                         
Net Amount Recognized at End of Period $(23,970) $22,625  $47,125  $(33,905) $(32,174) $(15,918)
                         


92101

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
  Retirement Plan  Other Post-Retirement Benefits 
  Year Ended September 30  Year Ended September 30 
  2008  2007  2006  2008  2007  2006 
  (Thousands) 
 
Amounts Recognized in the Balance Sheets Consist of:
                        
Accrued Benefit Liability $(23,970) $—  $—  $(54,939) $(70,555) $(32,918)
Prepaid Benefit Cost  —   22,625   47,125   21,034   38,381   17,000 
Intangible Assets  —   —   —   —   —   — 
Accumulated Other Comprehensive Loss from Additional Minimum Pension Liability Adjustment (Pre-Tax)  —   —   —   —   —   — 
                         
Net Amount Recognized at End of Period $(23,970) $22,625  $47,125  $(33,905) $(32,174) $(15,918)
                         
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
                        
Discount Rate  6.75%  6.25%  6.25%  6.75%  6.25%  6.25%
Expected Return on Plan Assets  8.25%  8.25%  8.25%  8.25%  8.25%  8.25%
Rate of Compensation Increase  5.00%  5.00%  5.00%  5.00%  5.00%  5.00%
Components of Net Periodic Benefit Cost
                        
Service Cost $12,598  $12,898  $16,416  $5,104  $5,614  $8,029 
Interest Cost  44,949   44,350   40,196   27,081   27,198   26,804 
Expected Return on Plan Assets  (55,000)  (51,235)  (49,943)  (33,715)  (26,960)  (22,302)
Amortization of Prior Service Cost  808   882   957   4   4   4 
Amortization of Transition Amount  —   —   —   7,127   7,127   7,127 
Recognition of Actuarial Loss(2)  11,063   13,528   23,108   2,927   8,214   23,402 
Net Amortization and Deferral for Regulatory Purposes  6,008   1,211   (6,409)  22,264   16,220   (11,084)
                         
Net Periodic Benefit Cost $20,426  $21,634  $24,325  $30,792  $37,417  $31,980 
                         
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change In Additional Minimum Liability Recognition $—  $—  $(165,914) $—  $—  $— 
                         
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to Adoption of SFAS 158  NA  $11,256   NA   NA  $778   NA 
                         
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
                        
Discount Rate  6.25%  6.25%  5.00%  6.25%  6.25%  5.00%
Expected Return on Plan Assets  8.25%  8.25%  8.25%  8.25%  8.25%  8.25%
Rate of Compensation Increase  5.00%  5.00%  5.00%  5.00%  5.00%  5.00%
                         
  Retirement Plan  Other Post-Retirement Benefits 
  Year Ended September 30  Year Ended September 30 
  2009  2008  2007  2009  2008  2007 
  (Thousands) 
 
Change in Benefit Obligation
                        
Benefit Obligation at Beginning of Period $719,059  $742,519  $732,207  $411,545  $444,545  $445,931 
Service Cost  10,913   12,597   12,898   3,801   5,104   5,614 
Interest Cost  46,836   44,949   44,350   27,499   27,081   27,198 
Plan Participants’ Contributions  —   —   —   2,185   1,990   1,566 
Retiree Drug Subsidy Receipts  —   —   —   1,427   1,532   1,325 
Amendments(1)  —   —   —   (10,765)  (31,874)  — 
Actuarial (Gain) Loss  102,430   (34,189)  (2,986)  55,776   (14,390)  (14,450)
Adjustment for Change in Measurement Date  14,438   —   —   7,825   —   — 
Benefits Paid  (62,180)  (46,817)  (43,950)  (31,998)  (22,443)  (22,639)
                         
Benefit Obligation at End of Period
 $831,496  $719,059  $742,519  $467,295  $411,545  $444,545 
                         
Change in Plan Assets
                        
Fair Value of Assets at Beginning of Period $695,089  $765,144  $664,521  $377,640  $412,371  $325,624 
Actual Return on Plan Assets  (99,511)  (39,206)  119,662   (62,368)  (43,478)  65,552 
Employer Contributions  15,993   3,817   16,488   25,659   29,200   42,268 
Employer Contributions During Period from Measurement Date to Fiscal Year End  N/A   12,151   8,423   N/A   —   — 
Plan Participants’ Contributions  —   —   —   2,185   1,990   1,566 
Adjustment for Change in Measurement Date  14,490   —   —   7,904   —   — 
Benefits Paid  (62,180)  (46,817)  (43,950)  (31,998)  (22,443)  (22,639)
                         
Fair Value of Assets at End of Period
 $563,881  $695,089  $765,144  $319,022  $377,640  $412,371 
                         
Net Amount Recognized at End of Period (Funded Status)
 $(267,615) $(23,970) $22,625  $(148,273) $(33,905) $(32,174)
                         
Amounts Recognized in the Balance Sheets Consist of:
                        
Accrued Benefit Liability $(267,615) $(23,970) $—  $(148,273) $(54,939) $(70,555)
Prepaid Benefit Cost  —   —   22,625   —   21,034   38,381 
                         
Net Amount Recognized at End of Period $(267,615) $(23,970) $22,625  $(148,273) $(33,905) $(32,174)
                         
Accumulated Benefit Obligation
 $758,658  $659,004  $672,340   N/A   N/A   N/A 
                         

93102

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
  Retirement Plan  Other Post-Retirement Benefits 
  Year Ended September 30  Year Ended September 30 
  2009  2008  2007  2009  2008  2007 
  (Thousands) 
 
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
                        
Discount Rate  5.50%  6.75%  6.25%  5.50%  6.75%  6.25%
Expected Return on Plan Assets  8.25%  8.25%  8.25%  8.25%  8.25%  8.25%
Rate of Compensation Increase  5.00%  5.00%  5.00%  5.00%  5.00%  5.00%
Components of Net Periodic Benefit Cost
                        
Service Cost $10,913  $12,597  $12,898  $3,801  $5,104  $5,614 
Interest Cost  46,836   44,949   44,350   27,499   27,081   27,198 
Expected Return on Plan Assets  (57,958)  (55,000)  (51,235)  (31,615)  (33,715)  (26,960)
Amortization of Prior Service Cost  732   808   882   (1,074)  4   4 
Amortization of Transition Amount  —   —   —   2,265   7,127   7,127 
Recognition of Actuarial Loss(2)  5,676   11,064   13,528   9,271   2,927   8,214 
Net Amortization and Deferral for Regulatory Purposes  12,817   6,008   1,211   18,037   22,264   16,220 
                         
Net Periodic Benefit Cost $19,016  $20,426  $21,634  $28,184  $30,792  $37,417 
                         
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to Recognition of Funded Status of Benefit Plans  N/A   N/A  $11,256   N/A   N/A  $778 
                         
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
                        
Discount Rate  6.75%  6.25%  6.25%  6.75%  6.25%  6.25%
Expected Return on Plan Assets  8.25%  8.25%  8.25%  8.25%  8.25%  8.25%
Rate of Compensation Increase  5.00%  5.00%  5.00%  5.00%  5.00%  5.00%
 
(1)In Fiscalfiscal 2008 and 2009, the Company passed an amendment,amendments, for most of the subsidiaries, which increased the participant contributions for active employees at the time of the amendment. This decreased the benefit obligation.
 
(2)Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
 
The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under SFAS 87 and SFAS 106the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets)assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
In September 2006, the FASB issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of Company’s fiscal year, with limited exceptions. Under SFAS 158, certain previously unrecognized actuarial gains and losses, previously unrecognized prior service costs, and a previously unrecognized transition obligation are required to be recognized. These amounts were not required to be recorded on the Company’s Consolidated Balance Sheet before the adoption of SFAS 158, but were instead amortized over a period of time. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 as of September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date. The incremental effects of adopting the provisions of SFAS 158 on the Company’s Consolidated Balance Sheet at September 30, 2007 are presented in the table below:
             
  Before
  Consolidated
  After
 
  Application of
  SFAS 158
  Application of
 
  SFAS 158(1)  Impact  SFAS 158 
  (Thousands) 
 
Qualified Retirement Plan
            
Reduction in Prepaid Pension and Other Post-Retirement Benefit Costs $51,612  $(28,987) $22,625 
Increase in Other Regulatory Assets Related to SFAS 158 $—  $17,731  $17,731 
Reduction in Accumulated Other Comprehensive Income $—  $7,008  $7,008 
Reduction in Deferred Income Taxes (under Deferred Credits) $—  $4,248  $4,248 


94

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
             
  Before
  Consolidated
  After
 
  Application of
  SFAS 158
  Application of
 
  SFAS 158(1)  Impact  SFAS 158 
  (Thousands) 
 
Other Post-Retirement Benefits
            
Increase in Prepaid Pension and OtherPost-Retirement Benefit Costs
 $26,067  $12,314  $38,381 
Increase in Other Regulatory Assets Related to SFAS 158 $—  $38,472  $38,472 
Increase in Other Regulatory Liabilities Related to SFAS 158 $—  $(3,247) $(3,247)
Reduction in Accumulated Other Comprehensive Income $—  $484  $484 
Reduction in Deferred Income Taxes (under Deferred Credits) $—  $294  $294 
Increase in Other Post-Retirement Liabilities $(22,238) $(48,317) $(70,555)
Non-Qualified Benefit Plan
            
Increase in Other Regulatory Assets Related to SFAS 158 $—  $5,704  $5,704 
Reduction in Accumulated Other Comprehensive Income $—  $4,990  $4,990 
Reduction in Deferred Income Taxes (under Deferred Credits) $—  $3,027  $3,027 
Increase in Other Deferred Credits $(30,115) $(13,721) $(43,836)
Total Consolidated
            
Reduction in Prepaid Pension and OtherPost-Retirement Benefit Costs
 $77,679  $(16,673) $61,006 
Increase in Other Regulatory Assets Related to SFAS 158 $—  $61,907  $61,907 
Increase in Other Regulatory Liabilities Related to SFAS 158 $—  $(3,247) $(3,247)
Reduction in Accumulated Other Comprehensive Income $—  $12,482  $12,482 
Reduction in Deferred Income Taxes (under Deferred Credits) $—  $7,569  $7,569 
Increase in Other Post-Retirement Liabilities $(22,238) $(48,317) $(70,555)
Increase in Other Deferred Credits $(30,115) $(13,721) $(43,836)
(1)Amounts represent balances before applying the effects of the adoption of SFAS 158, but after giving effect to any necessary adjustments as a result of recognizing an additional minimum pension liability. At September 30, 2007, there was no additional minimum pension liability adjustment since the fair value of the plan assets exceeded the accumulated benefit obligation.
In order to adjust the funded status of its pension and otherpost-retirement benefit plans at September 30, 2008, the Company recorded a $57.2 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $7.3 million (net of deferred tax benefits of $4.4 million) increase to Accumulated Other Comprehensive Loss.

95103

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
As note above, through 2008, the Company used June 30th as the measurement date for financial reporting purposes. In 2009, in accordance with the current authoritative guidance for defined benefit pension and other postretirement plans, the Company began measuring the Plan’s assets and liabilities for its pension and other post-retirement benefit plans as of September 30th, its fiscal year end. In making this change and as permitted by the current authoritative guidance, the Company recorded fifteen months of pension and post-retirement benefits expense (for the period from July 1, 2008 through September 30, 2009) during the fiscal year ended September 30, 2009. The pension and other post-retirement benefit costs for the period of July 1, 2008 to September 30, 2008 amounted to $3.8 million and were recorded by the Company during the year ended September 30, 2009 as a $3.4 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to earnings reinvested in the business. In addition, for the Company’s non-qualified benefit plan, benefit costs of $1.3 million were recorded by the Company during the year ended September 30, 2009 as a $0.4 million increase to Other Regulatory Assets in the Company’s Utility segment and a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business.
 
The cumulative amounts recognized in accumulated other comprehensive loss,income (loss), regulatory assets, and regulatory liabilities through fiscal 2009, the changes in fiscal 2008,such amounts during 2009, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 20092010 are presented in the table below:
 
                        
   Other
      Other
   
 Retirement
 Post-Retirement
 Non-Qualified
  Retirement
 Post-Retirement
 Non-Qualified
 
 Plan Benefits Benefit Plan  Plan Benefits Benefit Plan 
 (Thousands)  (Thousands) 
Amounts Recognized In Accumulated Other Comprehensive Loss, Regulatory Assets and Regulatory Liabilities(1)
            
Net Actuarial Gain/(Loss) $(71,637) $(53,108) $(13,530)
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1)
            
Net Actuarial Loss $(324,615) $(191,360) $(24,690)
Transition Obligation  —   (11,326)  —   —   (2,027)  — 
Prior Service (Cost) Credit  (5,495)  7,561   (11)  (4,581)  10,517   — 
              
Net Amount Recognized $(77,132) $(56,873) $(13,541) $(329,196) $(182,870) $(24,690)
              
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2009(1)
            
Increase in Net Actuarial Loss $(252,978) $(138,252) $(11,160)
Reduction in Transition Obligation  —   9,299   — 
Prior Service (Cost) Credit  914   2,956   11 
       
Net Change $(252,064) $(125,997) $(11,149)
       
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1)
                        
Net Actuarial Gain/(Loss) $(5,676) $(9,271) $(1,322)
Net Actuarial Loss $(21,641) $(25,882) $(2,623)
Transition Obligation  —   (2,265)  —   —   (541)  — 
Prior Service (Cost) Credit  (731)  1,074   —   (655)  1,710   — 
              
Net Amount Expected to be Recognized $(6,407) $(10,462) $(1,322) $(22,296) $(24,713) $(2,623)
              
 
 
(1)Amounts presented are shown before recognizing deferred taxes.
 
In accordance withorder to adjust the provisionsfunded status of SFAS 87,its pension and other post-retirement benefit plans at September 30, 2009, the Company recorded an additional minimum pension liability at September 30, 2005 representinga $318.4 million increase to Other Regulatory Assets in the excessCompany’s Utility and


104

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Pipeline and Storage segments and a $70.8 million (pre-tax) increase to Accumulated Other Comprehensive Loss.
The effect of the accumulated benefit obligation over the fair value of plan assets plus accrued amounts previously recorded. An intangible asset offset the additional liability to the extent of previously Unrecognized Prior Service Cost. The amount in excess of Unrecognized Prior Service Cost was recorded net of the related tax benefit as accumulated other comprehensive loss. At September 30, 2006, the Company reversed the additional minimum pension liability, intangible asset and accumulated other comprehensive loss recorded in prior years since the fair value of the plan assets exceeded the accumulated benefit obligation at September 30, 2006. The pre-tax amounts of thediscount rate change in accumulated other comprehensive (income) loss related to the additional minimum pension liability adjustment at September 30, 2006 are shown in the table above. At September 30, 2007, prior to recognizing the impact of adopting SFAS 158, there was no additional minimum pension liability adjustment recorded since the fair value of the plan assets exceeded the accumulated benefit obligation. The projected benefit obligation, accumulated benefit obligation and fair value of assets for the Retirement Plan were as follows:
             
  2008  2007  2006 
  (Thousands) 
 
Projected Benefit Obligation $719,059  $742,519  $732,207 
Accumulated Benefit Obligation $659,004  $672,340  $660,026 
Fair Value of Plan Assets $695,089  $765,144  $664,520 
in 2009 was to increase the projected benefit obligation of the Retirement Plan by $102.6 million. The effect of the discount rate change for the Retirement Plan in 2008 was to decrease the projected benefit obligation of the Retirement Plan by $38.6 million. In 2008, other actuarial experience increased the projected benefit obligation for the Retirement Plan by $4.4 million. There2007, there was no change to the discount rate used to estimate the projected benefit obligation for the Retirement Plan during 2007. The effect of the discount rate change for the Retirement Plan in 2006 was to decrease the projected benefit obligation of the Retirement Plan by $113.1 million.


96

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Plan.
 
The Company made cash contributions totaling $16.0 million to the Retirement Plan during the year ended September 30, 2008.2009. The Company expects that the annual contribution to the Retirement Plan in 20092010 will be in the range of $15.0$20.0 million to $20.0$30.0 million. As a result of the recent downturn in the stock markets and general economic conditions, itIt is likely that the Company will have to fund larger amounts to the Retirement Plan subsequent to 20092010 in order to be in compliance with the Pension Protection Act of 2006.
The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter: $50.5 million in 2009; $51.0$51.8 million in 2010; $51.4$52.2 million in 2011; $51.9$52.6 million in 2012; $52.9$53.3 million in 2013; $54.4 million in 2014; and $286.7$294.3 million in the five years thereafter.
 
In addition to the Retirement Plan discussed above, the Company also has a Non QualifiedNon-Qualified benefit plan that covers a group of management employees designated by the Chief Executive Officer of the Company. This plan provides for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit cost associated with this plan was $5.2 million, $5.0 million and $5.5 million in 2009, 2008 and $5.4 million in 2008, 2007, and 2006, respectively. At September 30, 2008,2007, an $8.0 million (pre-tax) loss was includedrecognized in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet. This was first recognized in 2007Sheet upon adoption of SFAS 158. There were no amounts recognized inthe FASB revised authoritative guidance for defined benefit pension and other comprehensive income (loss) attributable to the recognition of an additional minimum liability for 2006.postretirement plans. The accumulated benefit obligation for this plan was $31.8$35.8 million and $28.8$31.8 million at September 30, 20082009 and 2007,2008, respectively. The projected benefit obligation for the plan was $47.5$60.3 million and $43.8$47.5 million at September 30, 20082009 and 2007,2008, respectively. The actuarial valuations for this plan were determined based on a discount rate of 6.75%5.25%, 6.25%6.75% and 6.25% as of September 30, 2009, 2008 2007 and 2006,2007, respectively; a rate of compensation increase of 10.0% as of September 30, 2009, 2008 2007 and 2006;2007; and an expected long-term rate of return on plan assets of 8.25% at September 30, 2009, 2008 2007 and 2006.2007.
The effect of the discount rate change in 2009 was to increase the other post-retirement benefit obligation by $60.9 million. Effective October 1, 2009, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $27.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2009 by $32.1 million.
 
The effect of the discount rate change in 2008 was to decrease the other post-retirement benefit obligation by $26.3 million. Effective July 1, 2008, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $20.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2008 by $8.1 million.
 
There was no change to the discount rate used to estimate the other post-retirement benefit obligation during 2007. Effective July 1, 2007, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $8.6 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2007 by $23.0 million.
 
The effect of the discount rate change in 2006 was to decrease the other post-retirement benefit obligation by $77.5 million. Effective July 1, 2006, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to decrease the other post-retirement benefit obligation by $1.7 million. A change in the disability assumption decreased the other post-retirement benefit obligation by $1.4 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2006 by $34.4 million.
On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least


105

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
actuarially equivalent to Medicare Part D. In accordance with FASB Staff PositionFAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, sinceSince the Company is assumed to continue to provide a prescription drug benefit to retirees in the point of service and indemnity plans that is at least actuarially equivalent to Medicare Part D, the impact of the Act was reflected as of December 8, 2003.


97

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows:
 
                
 Benefit Payments Subsidy Receipts  Benefit Payments Subsidy Receipts
2009 $26,210,000  $(1,714,000)
2010 $28,248,000  $(1,942,000) $26,827,000  $(1,933,000)
2011 $30,122,000  $(2,167,000) $28,592,000  $(2,156,000)
2012 $31,484,000  $(2,437,000) $29,970,000  $(2,444,000)
2013 $32,687,000  $(2,719,000) $31,299,000  $(2,758,000)
2014 through 2018 $181,354,000  $(17,304,000)
2014 $32,743,000  $(3,066,000)
2015 through 2019 $185,348,000  $(20,026,000)
 
                     
 2008 2007 2006  2009 2008 2007
Rate of Increase for Pre Age 65 Participants  9.0%(1)  8.0%(2)  9.0%(2)  8.0%(1)  9.0%(2)  8.0%(3)
Rate of Increase for Post Age 65 Participants  7.0%(1)  6.67%(2)  7.0%(2)  7.0%(1)  7.0%(2)  6.67%(3)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits  10.0%(1)  10.0%(2)  11.0%(2)  9.0%(1)  10.0%(2)  10.0%(3)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement  7.0%(1)  7.0%(3)  5.25%(4)  7.0%(1)  7.0%(2)  7.0%(4)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy  7.9%(1)  10.0%(2)  10.0%(3)
 
 
(1)It was assumed that this rate would gradually decline to 5.0%4.5% by 2018.2028.
 
(2)It was assumed that this rate would gradually decline to 5.0% by 2014.2018.
 
(3)It was assumed that this rate would gradually decline to 5.0% by 2016.2014.
 
(4)It was assumed that this rate would gradually decline to 5.0% by 2017.2016.
 
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 other post-retirement benefit obligation as of October 1, 20082009 would increase by $45.1$54.5 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 20082009 by $4.7$3.9 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 20082009 would decrease by $38.4$46.2 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 20072009 by $3.9$3.3 million.
 
The Company made cash contributions totaling $29.1$25.5 million to the VEBA trusts and 401(h) accounts during the year ended September 30, 2008.2009. In addition, the Company made direct payments of $0.1$0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2008.2009. The Company expects that the annual contribution to the VEBA trusts and 401(h) accounts in 20092010 will be in the range of $25.0 million to $30.0 million.
The Company’s Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2008, 2007 and 2006 by asset category are as follows:
                 
     Percentage of Plan
 
  Target Allocation
  Assets at September 30 
Asset Category
 2009  2008  2007  2006 
 
Equity Securities  60-75%  67%  70%  67%
Fixed Income Securities  20-35%  29%  24%  26%
Other  0-15%  4%  6%  7%
                 
Total      100%  100%  100%
                 


98106

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Company’s Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2009, 2008 and 2007 by asset category are as follows:
                 
     Percentage of Plan
 
  Target Allocation
  Assets at September 30 
Asset Category
 2010  2009  2008  2007 
 
Equity Securities  60-75%  66%  67%  70%
Fixed Income Securities  20-35%  21%  23%  18%
Other  0-15%  13%  10%  12%
                 
Total      100%  100%  100%
                 
The Company’s weighted average asset allocations for its VEBA trusts and 401(h) accounts at September 30, 2009, 2008 2007 and 20062007 by asset category are as follows:
 
                                
   Percentage of Plan
    Percentage of Plan
 
 Target Allocation
 Assets at September 30  Target Allocation
 Assets at September 30 
Asset Category
 2009 2008 2007 2006  2010 2009 2008 2007 
Equity Securities  85-100%  93%  95%  95%  85-100%  93%  93%  95%
Fixed Income Securities  0-15%  2%  1%  1%  0-15%  2%  1%  1%
Other  0-15%  5%  4%  4%  0-15%  5%  6%  4%
              
Total      100%  100%  100%      100%  100%  100%
              
 
The Company’s assumption regarding the expected long-term rate of return on plan assets is 8.25%. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
 
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition.
 
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
 
The discount rate which is used to present value the future benefit payment obligations of the Retirement Plan the Non-Qualified benefit plan, and the Company’s other post-retirement benefits is 6.75%5.50% as of September 30, 2008.2009. The discount rate which is used to present value the future benefit payment obligations of the Non-Qualified benefit plan is 5.25% as of September 30, 2009. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments.
 
Note H —Commitments and Contingencies
Note I — Commitments and Contingencies
 
Environmental Matters
 
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.


107

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
It is the Company’s policy to accrue estimated environmentalclean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2008,2009, the Company has estimated its remainingclean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $19.4$18.7 million to $23.6$22.9 million. The minimum estimated liability of $19.4$18.7 million has been recorded on the Consolidated Balance Sheet at September 30, 2008.2009. The Company expects to recover its environmentalclean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet (refer to Note C — Regulatory Matters for further discussion of the insurance proceeds). Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.


99

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
(i) Former Manufactured Gas Plant Sites
 
The Company has incurred investigationand/orclean-up costs at several former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing monitoring and long-term maintenance at two sites.
 
With respectThe Company has agreed with the NYDEC to remediate another former manufactured gas plant site the Company received, in 1998 and again in October 1999, notice that the NYDEC believes the Company is responsible for contamination discovered at the site located in New York for which the Company had not been named as a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimatedclean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commented to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company filed a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and, without admitting liability or fault, agreed to the terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site consistent with the remedy selected in the NYDEC’s Record of Decision. The Company reimbursed the NYDEC in the amount of approximately $1.5 million for costs incurred in connection with the site from 1998 through May 30, 2007. The Company acknowledged that additional charges related to the site will be billed to the Company at a later date, including costs incurred by the NYDEC after May 30, 2007 and any costs incurred by the New York Department of Health.York. The Company has not received and does not expect to receive any estimatesapproval from the NYDEC of such additional costs. The Company has submitted a Remedial Design/Remedial ActionDesign work plan to the NYDEC in accordance with the Order on Consentfor this site and has increased its recorded an estimated minimum liability for remediation of this site to $16.5of $15.7 million.
 
(ii) Other
 
In June 2007, the NYDEC notified the Company, as well as a number of other companies, of their potential liability with respect to a remedial action at a waste disposal site in New York. The notification identified the Company as one of approximately 500 other companies considered to be PRPs related to this site and requested that the remedy the NYDEC proposed in a Record of Decision issued in March 2006 be performed. The estimatedclean-up costs under the remedy selected by the NYDEC are estimated to be approximately $13.0 million if implemented. The Company participates in an organized group with other PRPs who are addressing this site.
 
Other
 
The Company, in its Utility segment, Energy Marketing segment, and All Other category, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Substantially all of these contracts expire within the next five years. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $793.2 million in 2009, $168.0$520.2 million in 2010, $55.6$101.8 million in 2011, $47.0$66.6 million in 2012, $21.6$40.2 million in 2013, $39.8 million in 2014, and $100.7$76.3 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
 
The Company has entered into leases for the use of buildings, vehicles, construction tools, meters, computer equipment and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $6.0 million in 2009, $4.6$5.4 million in 2010, $3.6$3.9 million in 2011, $3.2$3.3 million in 2012, $2.5$2.4 million in 2013, $2.3 million in 2014, and $12.4$10.5 million thereafter.


100

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company has entered into several contractual commitments associated with the construction of the Empire Connector project, including the pipeline construction itself and construction of a compressor station, as well as other contractual commitments for engineering and consulting services. The Empire Connector is scheduled to go in service by December 2008. As of September 30, 2008, the future contractual commitments related to the construction of the Empire Connector during 2009 is $13.5 million.
 
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C — Regulatory Matters, the Company is involved in other regulatory


108

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
 
Note I —Discontinued Operations
Note J — Discontinued Operations
 
On August 31, 2007, the Company, in its Exploration and Production segment, completed the sale of SECI, Seneca’s wholly owned subsidiary that operated in Canada. The Company received approximately $232.1 million of proceeds from the sale, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. The sale resulted in the recognition of a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. SECI is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The decision to sell was based on lower than expected returns from the Canadian oil and gas properties combined with difficulty in finding significant new reserves. Seneca will continue its exploration and development activities in Appalachia, the Gulf of Mexico,United States, primarily in Appalachia and California. As a result of the decision to sell SECI, the Company began presenting all SECI operations as discontinued operations during the fourth quarter of 2007.
 
The following is selected financial information of the discontinued operations for SECI:
 
         
  Year Ended September 30 
  2007  2006 
  (Thousands) 
 
Operating Revenues $50,495  $71,984 
Operating Expenses  33,306   151,532 
         
Operating Income (Loss)  17,189   (79,548)
Interest Income  1,082   866 
         
Income (Loss) before Income Taxes  18,271   (78,682)
Income Tax Expense (Benefit)  2,792   (32,159)
         
Income (Loss) from Discontinued Operations  15,479   (46,523)
Gain on Disposal, Net of Taxes of $39,572  120,301   — 
         
Income (Loss) from Discontinued Operations $135,780  $(46,523)
         
     
  Year Ended
 
  September 30,
 
  2007 
  (Thousands) 
 
Operating Revenues $50,495 
Operating Expenses  33,306 
     
Operating Income  17,189 
Interest Income  1,082 
     
Income before Income Taxes  18,271 
Income Tax Expense  2,792 
     
Income from Discontinued Operations  15,479 
Gain on Disposal, Net of Taxes of $39,572  120,301 
     
Income from Discontinued Operations $135,780 
     


101

NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNote K — (Continued)Business Segment Information
Note J —Business Segment Information
 
The Company reports financial results for five businesshas four reportable segments: Utility, Pipeline and Storage, Exploration and Production, and Energy Marketing, and Timber.Marketing. The breakdowndivision of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
 
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.


109

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The Pipeline and Storage segment operations are regulated. Theregulated by the FERC regulates the operations offor both Supply Corporation and the NYPSC regulates the operations of Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR) and pipeline companies in the northeastern United States markets. Empire transports natural gas from the United States/Canadian border near Buffalo, New York into Central New York just north of Syracuse, New York. Empire is constructing theEmpire’s new facilities (the Empire Connector project,project), which consists of a compressor station and a pipeline extension from near Rochester, New York to an interconnection near Corning, New York with the unaffiliated Millennium Pipeline. The Empire Connector is anticipated to be ready to commencePipeline, were placed into service in earlyon December 2008, on or before the in-service date of the Millennium Pipeline.10, 2008. Empire transports gas to major industrial companies, utilities (including Distribution Corporation) and power producers.
 
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the Gulf Coast region of Texas Louisiana and Alabama.Louisiana. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. As disclosed in Note IJ — Discontinued Operations, on August 31, 2007, Seneca completed the sale of SECI, its wholly owned subsidiary operating in Canada, for a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. As a result of the sale, SECI’s operations have been reported as discontinued operations. As disclosed in Note M — Acquisition, on July 20, 2009, Seneca acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million (including cash acquired). Ivanhoe Energy’s United States oil and gas operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009.
 
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
The Timber segment’s operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings (primarily high quality hardwoods) in the northeastern United States and sawmills and kilns in Pennsylvania.
 
The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income.
 


102110

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                                                    
 Year Ended September 30, 2008  Year Ended September 30, 2009
               Corporate
                Corporate
  
   Pipeline
 Exploration
     Total
   and
      Pipeline
 Exploration
   Total
   and
  
   and
 and
 Energy
   Reported
 All
 Intersegment
 Total
    and
 and
 Energy
 Reportable
 All
 Intersegment
 Total
 Utility Storage Production Marketing Timber Segments Other Eliminations Consolidated  Utility Storage Production Marketing Segments Other Eliminations Consolidated
 (Thousands)  (Thousands)
Revenue from External Customers $1,194,657  $135,052  $466,760  $549,932  $49,516  $2,395,917  $3,749  $695  $2,400,361  $1,097,550  $137,478  $382,758  $397,763  $2,015,549  $41,409  $894  $2,057,852 
Intersegment Revenues $15,612  $81,504  $—  $1,300  $—  $98,416  $14,115  $(112,531) $—  $15,474  $81,795  $—  $558  $97,827  $3,890  $(101,717) $— 
Interest Income $1,836  $843  $10,921  $323  $1,053  $14,976  $179  $(4,340) $10,815  $2,486  $995  $2,430  $79  $5,990  $583  $(797) $5,776 
Interest Expense $27,683  $13,783  $41,645  $175  $3,142  $86,428  $640  $(13,099) $73,969  $32,417  $21,580  $33,368  $215  $87,580  $2,471  $(3,135) $86,916 
Depreciation, Depletion and Amortization $39,113  $32,871  $92,221  $42  $4,904  $169,151  $783  $689  $170,623  $39,675  $35,115  $90,816  $42  $165,648  $7,066  $696  $173,410 
Income Tax Expense $36,303  $34,008  $92,686  $3,180  $(378) $165,799  $2,564  $(441) $167,922 
Income Tax Expense (Benefit) $37,097  $30,579  $(14,616) $4,470  $57,530  $(5,221) $(1,189) $51,120 
Income from Unconsolidated Subsidiaries $—  $—  $—  $—  $—  $—  $6,303  $—  $6,303  $—  $—  $—  $—  $—  $3,366  $—  $3,366 
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $—  $—  $182,811  $—  $182,811  $—  $—  $182,811 
Significant Non-Cash Item: Impairment of Investment in Partnership $—  $—  $—  $—  $—  $1,804(1) $—  $1,804 
Significant Non-Cash Item: Impairment of Landfill Gas Assets $—  $—  $—  $—  $—  $4,568(2) $—  $4,568 
Segment Profit: Net Income (Loss) $61,472  $54,148  $146,612  $5,889  $107  $268,228  $5,672  $(5,172) $268,728  $58,664  $47,358  $(10,238) $7,166  $102,950  $(2,071) $(171) $100,708 
Expenditures for Additions to Long-Lived Assets $57,457  $165,520  $192,187  $39  $1,354  $416,557  $131  $(2,186) $414,502  $56,178  $50,118  $223,223(3) $25  $329,544  $9,723(4) $(47) $339,220 
 
                        
 At September 30, 2009
 (Thousands)
Segment Assets $2,132,610  $1,046,372  $1,265,678  $52,469  $4,497,129  $210,809  $61,191  $4,769,129 
 
                                     
  At September 30, 2008 
  (Thousands) 
 
                                     
Segment Assets $1,643,665  $948,984  $1,416,120  $89,527  $149,896  $4,248,192  $67,978  $(185,983) $4,130,187 
 
                                     
  Year Ended September 30, 2007 
                       Corporate
    
     Pipeline
  Exploration
        Total
     and
    
     and
  and
  Energy
     Reported
  All
  Intersegment
  Total
 
  Utility  Storage  Production  Marketing  Timber  Segments  Other  Eliminations  Consolidated 
  (Thousands) 
 
Revenue from External Customers $1,106,453  $130,410  $324,037  $413,612  $58,897  $2,033,409  $5,385  $772  $2,039,566 
Intersegment Revenues $14,271  $81,556  $—  $—  $—  $95,827  $8,726  $(104,553) $— 
Interest Income $(2,345) $357  $9,905  $682  $1,249  $9,848  $16  $(8,314) $1,550 
Interest Expense $28,190  $9,623  $51,743  $263  $3,265  $93,084  $2,687  $(21,296) $74,475 
Depreciation, Depletion and Amortization $40,541  $32,985  $78,174  $33  $4,709  $156,442  $785  $692  $157,919 
Income Tax Expense $31,642  $35,740  $52,421  $5,654  $2,818  $128,275  $1,647  $1,891  $131,813 
Income from Unconsolidated Subsidiaries $—  $—  $—  $—  $—  $—  $4,979  $—  $4,979 
Segment Profit: Income from Continuing Operations $50,886  $56,386  $74,889  $7,663  $3,728  $193,552  $2,564  $5,559  $201,675 
Expenditures for Additions to Long-Lived Assets from Continuing Operations $54,185  $43,226  $146,687  $76  $3,657  $247,831  $87  $(319) $247,599 
(1)Amount represents the impairment in the value of the Company’s 50% investment in ESNE, a partnership that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania.
(2)Amount represents the impairment in the value of certain long-lived landfill gas site assets due to the loss of a primary customer at the site and the anticipated shut-down of the site. The impairment includes a $2.6 million reduction in intangible assets related to long-term gas purchase contracts and a $2.0 million reduction in property, plant and equipment.
(3)Amount includes the acquisition of Ivanhoe Energy’s United States oil and gas operation for $34.9 million, net of cash acquired, and is discussed in Note M — Acquisition.
(4)Amount includes a $1.3 million capital contribution made by NFG Midstream Processing, LLC in the Whitetail Processing Plant.
 
                                     
  At September 30, 2007 
  (Thousands) 
 
                                     
Segment Assets $1,565,593  $810,957  $1,326,073  $59,802  $165,224  $3,927,649  $66,531  $(105,768) $3,888,412 
                                     
  Year Ended September 30, 2006 
                       Corporate
    
     Pipeline
  Exploration
        Total
     and
    
     and
  and
  Energy
     Reported
  All
  Intersegment
  Total
 
  Utility  Storage  Production  Marketing  Timber  Segments  Other  Eliminations  Consolidated 
  (Thousands) 
 
Revenue from External Customers $1,265,695  $132,921  $274,896  $497,069  $65,024  $2,235,605  $3,304  $766  $2,239,675 
Intersegment Revenues $15,068  $81,431  $—  $—  $5  $96,504  $9,444  $(105,948) $— 
Interest Income $4,889  $454  $7,816  $445  $747  $14,351  $22  $(4,964) $9,409 
Interest Expense $26,174  $6,620  $50,457  $227  $3,095  $86,573  $2,555  $(10,547) $78,581 
Depreciation, Depletion and Amortization $40,172  $36,876  $67,122  $53  $6,495  $150,718  $789  $492  $151,999 
Income Tax Expense $35,699  $33,896  $29,351  $3,748  $3,277  $105,971  $969  $1,305  $108,245 
Income from Unconsolidated Subsidiaries $—  $—  $—  $—  $—  $—  $3,583  $—  $3,583 
Segment Profit: Income (Loss) from Continuing Operations $49,815  $55,633  $67,494  $5,798  $5,704  $184,444  $359  $(189) $184,614 
Expenditures for Additions to Long-Lived Assets from Continuing Operations $54,414  $26,023  $166,535  $16  $2,323  $249,311  $85  $2,995  $252,391 
                                     
  At September 30, 2006 
  (Thousands) 
 
                                     
Segment Assets $1,498,442  $767,889  $1,209,969(1) $81,374  $159,421  $3,717,095  $64,287  $(17,634) $3,763,748 

103111

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                                 
  Year Ended September 30, 2008
              Corporate
  
    Pipeline
 Exploration
   Total
   and
  
    and
 and
 Energy
 Reportable
 All
 Intersegment
 Total
  Utility Storage Production Marketing Segments Other Eliminations Consolidated
  (Thousands)
 
Revenue from External Customers $1,194,657  $135,052  $466,760  $549,932  $2,346,401  $53,265  $695  $2,400,361 
Intersegment Revenues $15,612  $81,504  $—  $1,300  $98,416  $14,115  $(112,531) $— 
Interest Income $1,836  $843  $10,921  $323  $13,923  $1,232  $(4,340) $10,815 
Interest Expense $27,683  $13,783  $41,645  $175  $83,286  $3,782  $(13,099) $73,969 
Depreciation, Depletion and Amortization $39,113  $32,871  $92,221  $42  $164,247  $5,687  $689  $170,623 
Income Tax Expense (Benefit) $36,303  $34,008  $92,686  $3,180  $166,177  $2,186  $(441) $167,922 
Income from Unconsolidated Subsidiaries $—  $—  $—  $—  $—  $6,303  $—  $6,303 
Segment Profit: Net Income (Loss) $61,472  $54,148  $146,612  $5,889  $268,121  $5,779  $(5,172) $268,728 
Expenditures for Additions to Long-Lived Assets $57,457  $165,520  $192,187  $39  $415,203  $1,485  $(2,186) $414,502 
                                 
                                 
  At September 30, 2008
  (Thousands)
 
Segment Assets $1,643,665  $948,984  $1,416,120  $89,527  $4,098,296  $217,874  $(185,983) $4,130,187 
                                 
  Year Ended September 30, 2007
              Corporate
  
    Pipeline
 Exploration
   Total
   and
  
    and
 and
 Energy
 Reportable
 All
 Intersegment
 Total
  Utility Storage Production Marketing Segments Other Eliminations Consolidated
  (Thousands)
 
Revenue from External Customers $1,106,453  $130,410  $324,037  $413,612  $1,974,512  $64,282  $772  $2,039,566 
Intersegment Revenues $14,271  $81,556  $—  $—  $95,827  $8,726  $(104,553) $— 
Interest Income $(2,345) $357  $9,905  $682  $8,599  $1,265  $(8,314) $1,550 
Interest Expense $28,190  $9,623  $51,743  $263  $89,819  $5,952  $(21,296) $74,475 
Depreciation, Depletion and Amortization $40,541  $32,985  $78,174  $33  $151,733  $5,494  $692  $157,919 
Income Tax Expense $31,642  $35,740  $52,421  $5,654  $125,457  $4,465  $1,891  $131,813 
Income from Unconsolidated Subsidiaries $—  $—  $—  $—  $—  $4,979  $—  $4,979 
Segment Profit: Income from Continuing Operations $50,886  $56,386  $74,889  $7,663  $189,824  $6,292  $5,559  $201,675 
Expenditures for Additions to Long-Lived Assets from Continuing Operations $54,185  $43,226  $146,687  $76  $244,174  $7,044(1) $(319) $250,899 
                                 
                                 
  At September 30, 2007
  (Thousands)
 
Segment Assets $1,565,593  $810,957  $1,326,073  $59,802  $3,762,425  $231,755  $(105,768) $3,888,412 
 
(1)Amount includes $134,930 of assets of SECI, which has been classified as discontinued operations as of September 30, 2007. (See Note I — Discontinued Operations).a $3.3 million capital contribution to Seneca Energy by Horizon Power.
 
                        
 For The Year Ended September 30  For The Year Ended September 30 
Geographic Information
 2008 2007 2006  2009 2008 2007 
 (Thousands)  (Thousands) 
Revenues from External Customers(1):
                        
United States $2,400,361  $2,039,566  $2,239,675  $2,057,852  $2,400,361  $2,039,566 
              
 
             
  At September 30 
  2008  2007  2006 
  (Thousands) 
 
Long-Lived Assets:
            
United States $3,630,709  $3,334,274  $3,181,769 
Assets of Discontinued Operations  —   —   97,234 
             
  $3,630,709  $3,334,274  $3,279,003 
             

112

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
             
  At September 30 
  2009  2008  2007 
  (Thousands) 
 
Long-Lived Assets:
            
United States $3,992,159  $3,630,709  $3,334,274 
             
 
 
(1)Revenue is based upon the country in which the sale originates. This table excludes revenues from Canadian discontinued operations of $50,495 and $71,984 for September 30, 2007 and 2006, respectively.2007.
 
Note K —Investments in Unconsolidated Subsidiaries
Note L — Investments in Unconsolidated Subsidiaries
 
The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy, Model City, ESNE and ESNE.Whitetail Processing Plant. The Company has 50% interests in each of these entities.the first three entities and a 35% ownership interest in the Whitetail Processing Plant. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. ESNE sells its electricity into the New York power grid. Whitetail Processing Plant is currently under construction with completion expected in the fall of 2009. Once completed, the plant will extract natural gas liquids from local production in Pennsylvania.
During the quarter ended December 31, 2008, the Company recorded a pre-tax impairment of $1.8 million ($1.1 million on an after-tax basis) of its equity investment in ESNE due to a decline in the fair market value of ESNE. The impairment was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power.
 
A summary of the Company’s investments in unconsolidated subsidiaries at September 30, 20082009 and 20072008 is as follows:
 
                
 At September 30  At September 30 
 2008 2007  2009 2008 
 (Thousands)  (Thousands) 
ESNE $3,958  $4,652 
Seneca Energy  10,589   12,033  $10,924  $10,589 
Model City  1,732   1,571   2,136   1,732 
ESNE  1,880   3,958 
Whitetail Processing Plant  1,317   — 
          
 $16,279  $18,256  $16,257  $16,279 
          
Note M — Acquisition
On July 20, 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired all of the shares of Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired), of which $2.0 million was held in escrow at September 30, 2009. In accordance with the purchase agreement, this amount will remain in escrow for one year from the closing of the transaction provided there are no pending disputes or actions regarding obligations and liabilities required to be satisfied or discharged by Ivanhoe Energy. Ivanhoe Energy’s United States oil and gas operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009. As of the acquisition date, these assets produced approximately 645 (595 net) barrels per day of oil in California and Texas. The purchase also included certain exploration acreage in California. This acquisition adds to the Company’s existing oil producing assets in the Midway Sunset Field in California. The acquisition consisted of approximately $37.1 million in property, plant and equipment,


104113

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note L —Intangible Assets
$6.2 million of current assets (including $2.0 million of cash held in escrow), $0.3 million of current liabilities and $3.8 million of deferred credits. Details of the acquisition are as follows (all figures in thousands):
     
Assets Acquired $43,282 
Liabilities Assumed  (4,082)
Cash Acquired at Acquisition  (4,267)
     
Cash Paid, Net of Cash Acquired $34,933 
     
Note N — Intangible Assets
 
As a result of the Empire and Toro acquisitions in 2003, the Company acquired certain intangible assets during 2003.assets. In the case of the Empire acquisition, the intangible assets represent the fair value of various long-term transportation contracts with Empire’s customers. In the case of the Toro acquisition, the intangible assets represent the fair value of various long-term gas purchase contracts with the various landfills. These intangible assets are being amortized over the lives of the transportation and gas purchase contracts with no residual value at the end of the amortization period. The weighted-average amortization period for the gross carrying amount of the transportation contracts is 8 years. The weighted-average amortization period for the gross carrying amount of the gas purchase contracts is 20 years. Details of these intangible assets are as follows (in thousands):
 
                                
       At September 30,
    At September 30,
 
 At September 30, 2008 2007  At September 30, 2009 2008 
 Gross Carrying
 Accumulated
 Net Carrying
 Net Carrying
  Gross Carrying
 Accumulated
 Net Carrying
 Net Carrying
 
 Amount Amortization Amount Amount  Amount Amortization Amount Amount 
Intangible Assets Subject to Amortization:                                
Long-Term Transportation Contracts $8,580  $(6,058) $2,522  $3,591  $4,701  $(2,630) $2,071  $2,522 
Long-Term Gas Purchase Contracts  31,864   (8,212)  23,652   25,245   31,864   (12,399)  19,465   23,652 
                  
 $40,444  $(14,270) $26,174  $28,836  $36,565  $(15,029) $21,536  $26,174 
                  
Aggregate Amortization Expense:                                
For the Year Ended September 30, 2009 $4,638             
For the Year Ended September 30, 2008 $2,662              $2,662             
For the Year Ended September 30, 2007 $2,662              $2,662             
For the Year Ended September 30, 2006 $2,662             
 
In September 2009, the Company recorded a pre-tax impairment of $4.6 million in the value of certain long-lived assets in the All Other category due to the loss of the primary customer at one of Toro’s landfill gas sites and the anticipated shut-down of the site. The impairment was comprised of a $2.6 million reduction in intangible assets related to long-term gas purchase contracts and a $2.0 million reduction in property, plant and equipment. The $2.6 million intangible assets impairment was recorded to Purchased Gas expense and the $2.0 million property, plant and equipment impairment was recorded to Depreciation, Depletion and Amortization expense on the Consolidated Statement of Income. The $2.6 million impairment of the intangible asset is included in amortization expense for the year ended September 30, 2009 in the table shown above.
In October 2008, the Company completed the amortization of intangible assets related to two long-term transportation contracts. As such, the gross carrying amount of intangible assets subject to amortization was reduced from $8.6 million at September 30, 2008 remained unchanged fromto $4.7 million at September 30, 2007. The2009. Accumulated amortization was reduced by the same amount. Aside from this change, the only activity with regard to intangible assets subject to amortization was amortization expense as shown onin the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.5 million in 2009, and $0.4 million inannually for 2010, 2011,


114

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2012, 2013 and 2013.2014. Amortization expense for the long-term gas purchase contracts is estimated to be $1.6$1.4 million annually for 2009, 2010, 2011, 2012, 2013 and 2013.2014.
 
Note M —Quarterly Financial Data (unaudited)
Note O — 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. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are 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.


105

NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
                                    
         Net
         
         Income
                             
     Income
 Income
 Available
 Earnings from
          Net
    
     from
 from
 for
 Continuing Operations per
          Income
 Earnings per
Quarter
 Operating
 Operating
 Continuing
 Discontinued
 Common
 Common Share Earnings per Common Share  Operating
 Operating
 (Loss) Available for
 Common Share
Ended
 Revenues Income Operations Operations Stock Basic Diluted Basic Diluted  Revenues Income (Loss) Common Stock Basic Diluted
 (Thousands, except per common share amounts)  (Thousands, except per common share amounts)
2009
               
9/30/2009 $278,933  $64,922  $26,998(1) $0.34  $0.33 
6/30/2009 $367,111  $88,086  $42,904  $0.54  $0.53 
3/31/2009 $804,645  $138,642  $73,484  $0.92  $0.92 
12/31/2008 $607,163  $(66,820) $(42,678)(2) $(0.54) $(0.53)
2008
                                                   
9/30/2008 $397,858  $79,149  $43,266  $—  $43,266  $0.54  $0.52  $0.54  $0.52  $397,858  $79,149  $43,266  $0.54  $0.52 
6/30/2008 $548,382  $110,947  $59,855  $—  $59,855  $0.74  $0.72  $0.74  $0.72  $548,382  $110,947  $59,855  $0.74  $0.72 
3/31/2008 $885,853  $170,020  $95,003(1) $—  $95,003(1) $1.14  $1.11  $1.14  $1.11  $885,853  $170,020  $95,003(3) $1.14  $1.11 
12/31/2007 $568,268  $126,009  $70,604  $—  $70,604  $0.84  $0.82  $0.84  $0.82  $568,268  $126,009  $70,604  $0.84  $0.82 
2007
                                    
9/30/2007 $302,030  $73,504  $34,295  $123,395(2) $157,690(2) $0.41  $0.40  $1.89  $1.84 
6/30/2007 $448,779  $83,933  $41,212(3) $5,586  $46,798(3) $0.49  $0.48  $0.56  $0.55 
3/31/2007 $798,100  $142,404  $75,480(4) $2,967  $78,447(4) $0.91  $0.89  $0.95  $0.92 
12/31/2006 $490,657  $96,657  $50,688(5) $3,832  $54,520(5) $0.61  $0.60  $0.66  $0.64 
 
 
(1)Includes a $0.6non-cash $4.6 million gain on sale of turbine.impairment charge ($2.8 million after tax) associated with landfill gas assets in the All Other category.
 
(2)Includes a $120.3non-cash $182.8 million impairment charge ($108.2 million after tax) associated with the Exploration and Production segment’s oil and gas producing properties; a non-cash $1.8 million impairment charge ($1.1 million after tax) associated with an equity investment in the All Other category and a $2.3 million gain realized on life insurance policies in the sale of SECI.Corporate category.
 
(3)Includes $4.8a $0.6 million of income associated withgain on the reversal of reserve for preliminary project costs associated with the Empire Connector project.
(4)Includes $2.3 million of income associated with the reversalsale of a purchased gas expense accrual related to the resolution of a contingency.
(5)Includes a $1.9 million positive earnings impact associated with the discontinuance of hedge accounting on an interest rate collar.turbine.
 
Note N —Market for Common Stock and Related Shareholder Matters (unaudited)
Note P — Market for Common Stock and Related Shareholder Matters (unaudited)
 
At September 30, 2008,2009, there were 16,54416,098 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note E — Capitalization and Short-Term Borrowings. The quarterly price ranges (based onintra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2008 and 2007, are shown below:
             
  Price Range    
Quarter Ended
 High  Low  Dividends Declared 
 
2008
            
9/30/2008 $60.36  $39.16  $.325 
6/30/2008 $63.71  $47.00  $.325 
3/31/2008 $48.78  $38.04  $.31 
12/31/2007 $50.29  $45.20  $.31 
2007
            
9/30/2007 $47.00  $40.95  $.31 
6/30/2007 $47.87  $42.75  $.31 
3/31/2007 $43.79  $36.94  $.30 
12/31/2006 $40.21  $35.02  $.30 

106
115

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Note O —Supplementary Information for Oil and Gas Producing Activities (unaudited)
ranges (based onintra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2009 and 2008, are shown below:
             
  Price Range  
Quarter Ended
 High Low Dividends Declared
 
2009
            
9/30/2009 $48.30  $33.77  $.335 
6/30/2009 $37.61  $29.83  $.335 
3/31/2009 $34.34  $26.67  $.325 
12/31/2008 $41.99  $26.83  $.325 
2008
            
9/30/2008 $60.36  $39.16  $.325 
6/30/2008 $63.71  $47.00  $.325 
3/31/2008 $48.78  $38.04  $.31 
12/31/2007 $50.29  $45.20  $.31 
Note Q — Supplementary Information for Oil and Gas Producing Activities (unaudited)
 
The following supplementary information is presented in accordance with SFAS 69, “Disclosuresthe authoritative guidance regarding disclosures about Oiloil and Gas Producing Activities,”gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
 
Capitalized Costs Relating to Oil and Gas Producing Activities
 
                
 At September 30  At September 30 
 2008 2007  2009 2008 
 (Thousands)  (Thousands) 
Proved Properties(1) $1,783,276  $1,583,956  $1,953,720  $1,783,276 
Unproved Properties  23,285   20,005   70,061   23,285 
          
  1,806,561   1,603,961   2,023,781   1,806,561 
Less — Accumulated Depreciation, Depletion and Amortization  718,166   627,073   990,284   718,166 
          
 $1,088,395  $976,888  $1,033,497  $1,088,395 
          
 
 
(1)Includes asset retirement costs of $60.9$65.9 million and $40.9$60.9 million at September 30, 20082009 and 2007,2008, respectively.
 
Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Following is a summary of costs excluded from amortization at September 30, 2008:
                     
  Total
             
  as of
             
  September 30,
  Year Costs Incurred 
  2008  2008  2007  2006  Prior 
  (Thousands) 
 
Acquisition Costs $23,285  $7,914  $2,433  $11,918  $1,020 


107116

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
capitalized costs being amortized. Following is a summary of costs excluded from amortization at September 30, 2009:
                     
  Total
             
  as of
             
  September 30,
  Year Costs Incurred 
  2009  2009  2008  2007  Prior 
  (Thousands) 
 
Acquisition Costs $63,708  $44,728  $6,342  $2,361  $10,277 
Development Costs  6,353   6,353   —   —   — 
                     
  $70,061(1) $51,081  $6,342  $2,361  $10,277 
                     
(1)Costs related to unproved properties excluded from amortization includes $52.3 million related to onshore properties and $17.8 million related to offshore properties at September 30, 2009.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands)  (Thousands) 
United States
                        
Property Acquisition Costs:                        
Proved $16,474  $2,621  $5,339  $35,803  $16,474  $2,621 
Unproved  8,449   3,210   8,844   44,528   8,449   3,210 
Exploration Costs  56,274   26,891   64,087   11,724   56,274   26,891 
Development Costs  106,975   113,206   87,738   125,109   106,975   113,206 
Asset Retirement Costs  20,048   2,139   10,965   2,877   20,048   2,139 
              
  208,220   148,067   176,973   220,041   208,220   148,067 
              
Canada — Discontinued Operations
                        
Property Acquisition Costs:                        
Proved  —   (1,404)  (427)  —   —   (1,404)
Unproved  —   (1,142)  6,492   —   —   (1,142)
Exploration Costs  —   20,134   20,778   —   —   20,134 
Development Costs  —   11,414   14,385   —   —   11,414 
Asset Retirement Costs  —   167   279   —   —   167 
              
  —   29,169   41,507   —   —   29,169 
              
Total
                        
Property Acquisition Costs:                        
Proved  16,474   1,217   4,912   35,803   16,474   1,217 
Unproved  8,449   2,068   15,336   44,528   8,449   2,068 
Exploration Costs  56,274   47,025   84,865   11,724   56,274   47,025 
Development Costs  106,975   124,620   102,123   125,109   106,975   124,620 
Asset Retirement Costs  20,048   2,306   11,244   2,877   20,048   2,306 
              
 $208,220  $177,236  $218,480  $220,041  $208,220  $177,236 
              
For the years ended September 30, 2008, 2007 and 2006, the Company spent $25.4 million, $30.3 million and $55.6 million, respectively, developing proved undeveloped reserves.


108117

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
For the years ended September 30, 2009, 2008 and 2007, the Company spent $24.2 million, $25.4 million and $30.3 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands, except per Mcfe amounts)  (Thousands, except per Mcfe amounts) 
United States
                        
Operating Revenues:                        
Natural Gas (includes revenues from sales to affiliates of $443, $325 and $106, respectively) $216,623  $135,399  $152,451 
Natural Gas (includes revenues from sales to affiliates of $239, $443 and $325, respectively) $106,815  $216,623  $135,399 
Oil, Condensate and Other Liquids  305,887   189,539   195,050   174,356   305,887   189,539 
              
Total Operating Revenues(1)  522,510   324,938   347,501   281,171   522,510   324,938 
Production/Lifting Costs  66,685   48,410   41,354   62,614   66,685   48,410 
Accretion Expense  4,056   3,704   2,412   5,437   4,056   3,704 
Depreciation, Depletion and Amortization ($2.23, $1.97 and $1.74 per Mcfe of production)  91,093   77,452   66,488 
Income Tax Expense  144,922   78,928   88,104 
Depreciation, Depletion and Amortization ($2.10, $2.23 and $1.97 per Mcfe of production)  89,307   91,093   77,452 
Impairment of Oil and Gas Producing Properties(2)  182,811   —   — 
Income Tax Expense (Benefit)  (27,055)  144,922   78,928 
              
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)  215,754   116,444   149,143   (31,943)  215,754   116,444 
              
Canada — Discontinued Operations
                        
Operating Revenues:                        
Natural Gas  —   39,114   54,819   —   —   39,114 
Oil, Condensate and Other Liquids  —   10,313   13,985   —   —   10,313 
              
Total Operating Revenues(1)  —   49,427   68,804   —   —   49,427 
Production/Lifting Costs  —   14,846   14,628   —   —   14,846 
Accretion Expense  —   249   258   —   —   249 
Depreciation, Depletion and Amortization ($0, $1.67 and $2.95 per Mcfe of production)  —   12,787   27,439 
Impairment of Oil and Gas Producing Properties(2)  —   —   104,739 
Income Tax Expense (Benefit)  —   3,703   (31,987)
Depreciation, Depletion and Amortization ($1.67 per Mcfe of production for 2007)  —   —   12,787 
Income Tax Expense  —   —   3,703 
              
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)  —   17,842   (46,273)  —   —   17,842 
              


109118

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                        
 Year Ended September 30  Year Ended September 30 
 2008 2007 2006  2009 2008 2007 
 (Thousands, except per Mcfe amounts)  (Thousands, except per Mcfe amounts) 
Total
                        
Operating Revenues:                        
Natural Gas (includes revenues from sales to affiliates of $443, $325 and $106, respectively)  216,623   174,513   207,270 
Natural Gas (includes revenues from sales to affiliates of $239, $443 and $325, respectively)  106,815   216,623   174,513 
Oil, Condensate and Other Liquids  305,887   199,852   209,035   174,356   305,887   199,852 
              
Total Operating Revenues(1)  522,510   374,365   416,305   281,171   522,510   374,365 
Production/Lifting Costs  66,685   63,256   55,982   62,614   66,685   63,256 
Accretion Expense  4,056   3,953   2,670   5,437   4,056   3,953 
Depreciation, Depletion and Amortization ($2.23, $1.92 and $1.98 per Mcfe of production)  91,093   90,239   93,927 
Depreciation, Depletion and Amortization ($2.10, $2.23 and $1.92 per Mcfe of production)  89,307   91,093   90,239 
Impairment of Oil and Gas Producing Properties(2)  —   —   104,739   182,811   —   — 
Income Tax Expense  144,922   82,631   56,117   (27,055)  144,922   82,631 
              
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $215,754  $134,286  $102,870  $(31,943) $215,754  $134,286 
              
 
 
(1)Exclusive of hedging gains and losses. See further discussion in Note FG — Financial Instruments.
 
(2)See discussion of impairment in Note A — Summary of Significant Accounting Policies.

110119

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
Reserve Quantity Information
 
The Company’s proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by qualified Company geologists and engineers and are audited by independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
 
                                                
 Gas MMcf  Gas MMcf 
 U. S.      U. S.     
 Gulf
 West
     Canada
    Gulf
 West
     Canada
   
 Coast
 Coast
 Appalachian
 Total
 (Discontinued
 Total
  Coast
 Coast
 Appalachian
 Total
 (Discontinued
 Total
 
 Region Region Region U.S. Operations) Company  Region Region Region U.S. Operations) Company 
Proved Developed and Undeveloped Reserves:                                                
September 30, 2005  38,470   70,459   83,125   192,054   46,086   238,140 
Extensions and Discoveries  11,763   1,815   11,132   24,710   6,229   30,939 
Revisions of Previous Estimates  679   5,757   (7,776)  (1,340)  (11,096)  (12,436)
Production  (9,110)  (3,880)  (5,108)  (18,098)  (7,673)  (25,771)
Purchases of Minerals in Place  —   1,715   —   1,715   —   1,715 
Sales of Minerals in Place  —   —   —   —   (12)  (12)
             
September 30, 2006  41,802   75,866   81,373   199,041   33,534   232,575   41,802   75,866   81,373   199,041   33,534   232,575 
Extensions and Discoveries  3,577   —   29,676   33,253   1,333   34,586   3,577   —   29,676   33,253   1,333   34,586 
Revisions of Previous Estimates  (9,851)  1,238   1,618   (6,995)  11,634   4,639   (9,851)  1,238   1,618   (6,995)  11,634   4,639 
Production  (10,356)  (3,929)  (5,555)  (19,840)  (6,426)  (26,266)  (10,356)  (3,929)  (5,555)  (19,840)  (6,426)  (26,266)
Sales of Minerals in Place  (36)  —   (34)  (70)  (40,075)  (40,145)  (36)  —   (34)  (70)  (40,075)  (40,145)
                          
September 30, 2007  25,136   73,175   107,078   205,389   —   205,389   25,136   73,175   107,078   205,389   —   205,389 
Extensions and Discoveries  8,759   —   31,322   40,081   —   40,081   8,759   —   31,322   40,081   —   40,081 
Revisions of Previous Estimates  2,156   566   (3,460)  (738)  —   (738)  2,156   566   (3,460)  (738)  —   (738)
Production  (11,033)  (4,039)  (7,269)  (22,341)  —   (22,341)  (11,033)  (4,039)  (7,269)  (22,341)  —   (22,341)
Purchases of Minerals in Place  —   4,539   727   5,266   —   5,266   —   4,539   727   5,266   —   5,266 
Sales of Minerals in Place  (377)  (1,381)  —   (1,758)  —   (1,758)  (377)  (1,381)  —   (1,758)  —   (1,758)
                          
September 30, 2008  24,641   72,860   128,398   225,899   —   225,899   24,641   72,860   128,398   225,899   —   225,899 
Extensions and Discoveries  6,698   3,282   49,249   59,229   —   59,229 
Revisions of Previous Estimates  9,407   488   (19,484)  (9,589)  —   (9,589)(1)
Production  (9,886)  (4,063)  (8,335)  (22,284)  —   (22,284)
Purchases of Minerals in Place  —   392   —   392   —   392 
Sales of Minerals in Place  (4,693)  —   —   (4,693)  —   (4,693)
             
September 30, 2009  26,167   72,959   149,828   248,954   —   248,954 
                          
Proved Developed Reserves:                                                
September 30, 2005  23,108   58,692   83,125   164,925   43,980   208,905 
September 30, 2006  32,345   64,196   81,373   177,914   33,534   211,448   32,345   64,196   81,373   177,914   33,534   211,448 
September 30, 2007  25,136   66,017   96,674   187,827   —   187,827   25,136   66,017   96,674   187,827   —   187,827 
September 30, 2008  18,242   68,453   115,824   202,519   —   202,519   18,242   68,453   115,824   202,519   —   202,519 
September 30, 2009  18,051   67,603   120,579   206,233   —   206,233 
 
(1)During 2009, the Company made a downward revision of its proved developed and undeveloped reserves amounting to 9,589 MMcf. This was primarily attributable to a 19,484 MMcf reduction in the Appalachian


111120

 
NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
                         
  Oil Mbbl 
  U. S.       
  Gulf
  West
        Canada
    
  Coast
  Coast
  Appalachian
  Total
  (Discontinued
  Total
 
  Region  Region  Region  U.S.  Operations)  Company 
 
Proved Developed and Undeveloped Reserves:                        
September 30, 2005  1,295   57,085   177   58,557   1,700   60,257 
Extensions and Discoveries  39   172   108   319   128   447 
Revisions of Previous Estimates  595   (80)  57   572   101   673 
Production  (685)  (2,582)  (69)  (3,336)  (272)  (3,608)
Purchases of Minerals in Place  —   274   —   274   —   274 
Sales of Minerals in Place  —   —   —   —   (25)  (25)
                         
September 30, 2006  1,244   54,869   273   56,386   1,632   58,018 
Extensions and Discoveries  63   —   281   344   108   452 
Revisions of Previous Estimates  851   (6,822)  84   (5,887)  (76)  (5,963)
Production  (717)  (2,403)  (124)  (3,244)  (206)  (3,450)
Sales of Minerals in Place  (6)  —   (7)  (13)  (1,458)  (1,471)
                         
September 30, 2007  1,435   45,644   507   47,586   —   47,586 
Extensions and Discoveries  298   471   58   827   —   827 
Revisions of Previous Estimates  203   (34)  (64)  105   —   105 
Production  (505)  (2,460)  (105)  (3,070)  —   (3,070)
Purchases of Minerals in Place  —   2,084   —   2,084   —   2,084 
Sales of Minerals in Place  (73)  (1,261)  —   (1,334)  —   (1,334)
                         
September 30, 2008  1,358   44,444   396   46,198   —   46,198 
                         
Proved Developed Reserves:                        
September 30, 2005  1,229   41,701   177   43,107   1,700   44,807 
September 30, 2006  1,217   42,522   273   44,012   1,632   45,644 
September 30, 2007  1,435   36,509   483   38,427   —   38,427 
September 30, 2008  1,313   37,224   357   38,894   —   38,894 
region offset by a 9,407 MMcf increase in the Gulf Coast region. The reduction in the Appalachian region was mainly due to declining natural gas prices, which made certain reserves uneconomical. The improvement in the Gulf Coast region was due to improved performance of Gulf Coast properties.
                         
  Oil Mbbl 
  U. S.       
  Gulf
  West
        Canada
    
  Coast
  Coast
  Appalachian
  Total
  (Discontinued
  Total
 
  Region  Region  Region  U.S.  Operations)  Company 
 
Proved Developed and Undeveloped Reserves:                        
September 30, 2006  1,244   54,869   273   56,386   1,632   58,018 
Extensions and Discoveries  63   —   281   344   108   452 
Revisions of Previous Estimates  851   (6,822)  84   (5,887)  (76)  (5,963)
Production  (717)  (2,403)  (124)  (3,244)  (206)  (3,450)
Sales of Minerals in Place  (6)  —   (7)  (13)  (1,458)  (1,471)
                         
September 30, 2007  1,435   45,644   507   47,586   —   47,586 
Extensions and Discoveries  298   471   58   827   —   827 
Revisions of Previous Estimates  203   (34)  (64)  105   —   105 
Production  (505)  (2,460)  (105)  (3,070)  —   (3,070)
Purchases of Minerals in Place  —   2,084   —   2,084   —   2,084 
Sales of Minerals in Place  (73)  (1,261)  —   (1,334)  —   (1,334)
                         
September 30, 2008  1,358   44,444   396   46,198   —   46,198 
Extensions and Discoveries  302   896   15   1,213   —   1,213 
Revisions of Previous Estimates  447   43   (41)  449   —   449 
Production  (640)  (2,674)  (59)  (3,373)  —   (3,373)
Purchases of Minerals in Place  —   2,115   —   2,115   —   2,115 
Sales of Minerals in Place  (15)  —   —   (15)  —   (15)
                         
September 30, 2009  1,452   44,824   311   46,587   —   46,587 
                         
Proved Developed Reserves:                        
September 30, 2006  1,217   42,522   273   44,012   1,632   45,644 
September 30, 2007  1,435   36,509   483   38,427   —   38,427 
September 30, 2008  1,313   37,224   357   38,894   —   38,894 
September 30, 2009  1,194   37,711   285   39,190   —   39,190 
 
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
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 widely fluctuating political and economic conditions.


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NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The standardized measure is intended instead to provide a 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 
  2009  2008  2007 
  (Thousands) 
 
United States
            
Future Cash Inflows $3,972,026  $5,845,214  $4,879,496 
Less:            
Future Production Costs  1,010,851   1,231,705   872,536 
Future Development Costs  312,717   265,515   229,987 
Future Income Tax Expense at Applicable Statutory Rate  916,466   1,645,351   1,423,707 
             
Future Net Cash Flows  1,731,992   2,702,643   2,353,266 
Less:            
10% Annual Discount for Estimated Timing of Cash Flows  856,015   1,434,799   1,292,804 
             
Standardized Measure of Discounted Future Net Cash Flows $875,977  $1,267,844  $1,060,462 
             
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
             
  Year Ended September 30 
  2009  2008  2007 
  (Thousands) 
 
United States
            
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year		 $1,267,844  $1,060,462  $861,659 
Sales, Net of Production Costs  (218,557)  (455,825)  (276,529)
Net Changes in Prices, Net of Production Costs  (699,217)  509,705   539,895 
Purchases of Minerals in Place  38,902   67,768   — 
Sales of Minerals in Place  (20,141)  (31,642)  484 
Extensions and Discoveries  66,002   143,394   98,751 
Changes in Estimated Future Development Costs  (22,392)  (100,684)  (83,199)
Previously Estimated Development Costs Incurred  53,285   65,156   58,710 
Net Change in Income Taxes at Applicable Statutory Rate  331,251   (119,585)  (174,920)
Revisions of Previous Quantity Estimates  (27,864)  (3,936)  (140,203)
Accretion of Discount and Other  106,864   133,031   175,814 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year  875,977   1,267,844   1,060,462 
             

112
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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands) 
 
United States
            
Future Cash Inflows $5,845,214  $4,879,496  $3,911,059 
Less:            
Future Production Costs  1,231,705   872,536   758,258 
Future Development Costs  265,515   229,987   205,497 
Future Income Tax Expense at Applicable Statutory Rate  1,645,351   1,423,707   1,019,307 
             
Future Net Cash Flows  2,702,643   2,353,266   1,927,997 
Less:            
10% Annual Discount for Estimated Timing of Cash Flows  1,434,799   1,292,804   1,066,338 
             
Standardized Measure of Discounted Future Net Cash Flows  1,267,844   1,060,462   861,659 
             
Canada — Discontinued Operations
            
Future Cash Inflows  —   —   197,227 
Less:            
Future Production Costs  —   —   92,234 
Future Development Costs  —   —   11,520 
Future Income Tax Expense at Applicable Statutory Rate  —   —   (151)
             
Future Net Cash Flows  —   —   93,624 
Less:            
10% Annual Discount for Estimated Timing of Cash Flows  —   —   19,375 
             
Standardized Measure of Discounted Future Net Cash Flows  —  ��—   74,249 
             
Total
            
Future Cash Inflows  5,845,214   4,879,496   4,108,286 
Less:            
Future Production Costs  1,231,705   872,536   850,492 
Future Development Costs  265,515   229,987   217,017 
Future Income Tax Expense at Applicable Statutory Rate  1,645,351   1,423,707   1,019,156 
             
Future Net Cash Flows  2,702,643   2,353,266   2,021,621 
Less:            
10% Annual Discount for Estimated Timing of Cash Flows  1,434,799   1,292,804   1,085,713 
             
Standardized Measure of Discounted Future Net Cash Flows $1,267,844  $1,060,462  $935,908 
             
             
  Year Ended September 30 
  2009  2008  2007 
  (Thousands) 
 
Canada — Discontinued Operations
            
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year  —   —   74,249 
Sales, Net of Production Costs  —   —   (34,581)
Net Changes in Prices, Net of Production Costs  —   —   35,628 
Sales of Minerals in Place  —   —   (151,236)
Extensions and Discoveries  —   —   6,908 
Changes in Estimated Future Development Costs  —   —   5,722 
Previously Estimated Development Costs Incurred  —   —   5,798 
Net Change in Income Taxes at Applicable Statutory Rate  —   —   (10,075)
Revisions of Previous Quantity Estimates  —   —   34,998 
Accretion of Discount and Other  —   —   32,589 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year  —   —   — 
             
Total
            
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year  1,267,844   1,060,462   935,908 
Sales, Net of Production Costs  (218,557)  (455,825)  (311,110)
Net Changes in Prices, Net of Production Costs  (699,217)  509,705   575,523 
Purchases of Minerals in Place  38,902   67,768   — 
Sales of Minerals in Place  (20,141)  (31,642)  (150,752)
Extensions and Discoveries  66,002   143,394   105,659 
Changes in Estimated Future Development Costs  (22,392)  (100,684)  (77,477)
Previously Estimated Development Costs Incurred  53,285   65,156   64,508 
Net Change in Income Taxes at Applicable Statutory Rate  331,251   (119,585)  (184,995)
Revisions of Previous Quantity Estimates  (27,864)  (3,936)  (105,205)
Accretion of Discount and Other  106,864   133,031   208,403 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year $875,977  $1,267,844  $1,060,462 
             
Note R — Subsequent Events
In accordance with the authoritative guidance for subsequent events, the Company has evaluated subsequent events through November 25, 2009, which represents the filing date of thisForm 10-K with the SEC, in order to ensure that thisForm 10-K includes appropriate disclosure of events both recognized in the financial statements as of September 30, 2009, and events which occurred subsequent to September 30, 2009 but were

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NATIONAL FUEL GAS COMPANY
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The principal sources of changenot recognized in the standardized measurefinancial statements. As of discounted future net cash flowsNovember 25, 2009, there were as follows:
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands) 
 
United States
            
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year		 $1,060,462  $861,659  $1,491,532 
Sales, Net of Production Costs  (455,825)  (276,529)  (306,147)
Net Changes in Prices, Net of Production Costs  509,705   539,895   (941,545)
Purchases of Minerals in Place  67,768   —   7,607 
Sales of Minerals in Place  (31,642)  484   — 
Extensions and Discoveries  143,394   98,751   66,975 
Changes in Estimated Future Development Costs  (100,684)  (83,199)  (83,750)
Previously Estimated Development Costs Incurred  65,156   58,710   67,048 
Net Change in Income Taxes at Applicable Statutory Rate  (119,585)  (174,920)  404,176 
Revisions of Previous Quantity Estimates  (3,936)  (140,203)  4,850 
Accretion of Discount and Other  133,031   175,814   150,913 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year  1,267,844   1,060,462   861,659 
             
Canada — Discontinued Operations
            
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year		  —   74,249   206,643 
Sales, Net of Production Costs  —   (34,581)  (54,176)
Net Changes in Prices, Net of Production Costs  —   35,628   (180,216)
Sales of Minerals in Place  —   (151,236)  (238)
Extensions and Discoveries  —   6,908   10,369 
Changes in Estimated Future Development Costs  —   5,722   (3,282)
Previously Estimated Development Costs Incurred  —   5,798   4,450 
Net Change in Income Taxes at Applicable Statutory Rate  —   (10,075)  82,966 
Revisions of Previous Quantity Estimates  —   34,998   (15,478)
Accretion of Discount and Other  —   32,589   23,211 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year  —   —   74,249 
             


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NATIONAL FUEL GAS COMPANY
no subsequent events which required recognition or disclosure.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
             
  Year Ended September 30 
  2008  2007  2006 
  (Thousands) 
 
Total
            
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year		  1,060,462   935,908   1,698,175 
Sales, Net of Production Costs  (455,825)  (311,110)  (360,323)
Net Changes in Prices, Net of Production Costs  509,705   575,523   (1,121,761)
Purchases of Minerals in Place  67,768   —   7,607 
Sales of Minerals in Place  (31,642)  (150,752)  (238)
Extensions and Discoveries  143,394   105,659   77,344 
Changes in Estimated Future Development Costs  (100,684)  (77,477)  (87,032)
Previously Estimated Development Costs Incurred  65,156   64,508   71,498 
Net Change in Income Taxes at Applicable Statutory Rate  (119,585)  (184,995)  487,142 
Revisions of Previous Quantity Estimates  (3,936)  (105,205)  (10,628)
Accretion of Discount and Other  133,031   208,403   174,124 
             
Standardized Measure of Discounted Future Net Cash Flows at End of Year $1,267,844  $1,060,462  $935,908 
             
Schedule II — Valuation and Qualifying Accounts
 
                                        
   Additions
          Additions
       
 Balance
 Charged
 Additions
   Balance
  Balance
 Charged
 Additions
   Balance
 
 at
 to
 Charged
   at
  at
 to
 Charged
   at
 
 Beginning
 Costs
 to
   End
  Beginning
 Costs
 to
   End
 
 of
 and
 Other
   of
  of
 and
 Other
   of
 
Description
 Period Expenses Accounts(1) Deductions(2) Period  Period Expenses Accounts(1) Deductions(2) Period 
 (Thousands)  (Thousands) 
Year Ended September 30, 2009
                    
Allowance for Uncollectible Accounts $33,117  $31,464  $2,751  $28,998  $38,334 
           
Year Ended September 30, 2008
                                        
Allowance for Uncollectible Accounts $28,654  $27,274  $2,734  $25,545  $33,117  $28,654  $27,274  $2,734  $25,545  $33,117 
                      
Year Ended September 30, 2007
                                        
Allowance for Uncollectible Accounts $31,427  $27,652  $1,414  $31,839  $28,654  $31,427  $27,652  $1,414  $31,839  $28,654 
                      
Year Ended September 30, 2006
                    
Allowance for Uncollectible Accounts $26,940  $29,088  $907  $25,508  $31,427 
Deferred Tax Valuation Allowance $2,877  $(2,877) $—  $—  $— 
           
 
 
(1)Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement.
 
(2)Amounts represent net accounts receivable written-off.

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124

Item 9  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
None
 
Item 9A  Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
The term “disclosure controls and procedures” is defined inRules 13a-15(e) and15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2008.2009.
 
Management’s Annual Report on Internal Control over Financial Reporting
 
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined inRules 13a-15(f) and15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
 
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008.2009. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2008.2009.
 
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report onForm 10-K, has issued aan attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008.2009. The report appears in Part II, Item 8 of this Annual Report onForm 10-K.
 
Changes in Internal Control over Financial Reporting
 
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 20082009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
Item 9B  Other Information
 
None
 
PART III
 
Item 10  Directors, Executive Officers and Corporate Governance
 
The information required by this item concerning the directors of the Company and corporate governance is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010


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Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning directors iswill be set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2013,” “Directors Whose Terms Expire in 2012,” “Directors Whose Terms Expire in 2011,” “Directors Whose Terms Expire in 2010,” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The information concerning corporate governance is set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.
 
The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the Company’s Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
 
The Company intends to satisfy the disclosure requirement under Item 5.05 ofForm 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’sRegulation S-K, by posting such information on its website, www.nationalfuelgas.com.
 
Item 11  Executive Compensation
 
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning executive compensation iswill be set forth in the definitive Proxy Statement under the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee,” is incorporated herein by reference.
 
Item 12  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
Equity Compensation Plan Information
 
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The equity compensation plan information iswill be set forth in the definitive Proxy Statement under the heading “Equity Compensation Plan Information” and is incorporated herein by reference.
 
Security Ownership and Changes in Control
 
(a)  Security Ownership of Certain Beneficial Owners
 
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning security ownership of certain beneficial owners iswill be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
 
(b)  Security Ownership of Management
 
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning security ownership of


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management iswill be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
 
(c)  Changes in Control
 
None
 
Item 13  Certain Relationships and Related Transactions, and Director Independence
 
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information regarding certain relationships and related transactions iswill be set forth in the definitive Proxy Statement under the headings “Compensation Committee Interlocks and Insider Participation” and “Related Person Transactions” and is incorporated herein by reference. The information regarding director independence is set forth in the definitive Proxy Statement under the heading “Director Independence” and is incorporated herein by reference.
 
Item 14  Principal Accountant Fees and Services
 
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning principal accountant fees and services iswill be set forth in the definitive Proxy Statement under the heading “Audit Fees” and is incorporated herein by reference.
 
PART IV
 
Item 15  Exhibits and Financial Statement Schedules
 
(a)1.  Financial Statements
 
Financial statements filed as part of this report are listed in the index included in Item 8 of thisForm 10-K, and reference is made thereto.
 
(a)2.  Financial Statement Schedules
 
Financial statement schedules filed as part of this report are listed in the index included in Item 8 of thisForm 10-K, and reference is made thereto.
 
(a)3.  Exhibits
 
     
Exhibit
 Description of
Number
 
Exhibits
 
 3(i)  Articles of Incorporation:
 •  Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880)
 •  Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 3(ii),Form 8-K dated March 14, 2005 in FileNo. 1-3880)
 3(ii)  By-Laws:
 •  National Fuel Gas Company By-Laws as amended June 11, 2008 (Exhibit 3.1,Form 8-K dated June 16, 2008 in FileNo. 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 FileNo. 2-51796)


118

     
Exhibit
 Description of
Number
 
Exhibits
 
 •  Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in FileNo. 33-49401)
 •  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 FileNo. 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 FileNo. 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 FileNo. 33-49401)
 •  Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in FileNo. 1-3880)
 •  Fifteenth Supplemental Indenture, dated as of September 1, 1996, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880)
 •  Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
 •  Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
 •  Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4,Form 10-Q for the quarterly period ended March 31, 2003 in FileNo. 1-3880)
 •  Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008 (Exhibit 4.1,Form 10-Q for the quarterly period ended June 30, 2008 in FileNo. 1-3880)
 •  Amended and Restated Rights Agreement, dated as of July 11, 2008, between the Company and The Bank of New York, as rights agent (Exhibit 4.1,Form 8-K dated July 15, 2008 in FileNo. 1-3880)
 10  Material Contracts:
 •  Credit Agreement, dated as of August 19, 2005, among the Company, the Lenders Party Thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880)
 •  Form of Indemnification Agreement, dated September 2006, between the Company and each Director (Exhibit 10.1,Form 8-K dated September 18, 2006 in FileNo. 1-3880)
 •  Settlement Agreement dated January 24, 2008 among the Company, New Mountain Vantage GP, L.L.C. (“Vantage”) and certain of Vantage’s affiliates (Exhibit 10.1,Form 8-K dated January 24, 2008 in FileNo. 1-3880)
 •  Director Services Agreement, dated as of June 1, 2008, between the Company and Philip C. Ackerman (Exhibit 99,Form 8-K dated June 16, 2008 in FileNo. 1-3880)
 •  Resolutions adopted by the National Fuel Gas Company Board of Directors on February 21, 2008 regarding director stock ownership guidelines (Exhibit 10.5,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
 10.1 Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and each of Karen M. Camiolo, Carl M. Carlotti, Anna Marie Cellino, Paula M. Ciprich, Donna L. DeCarolis, John R. Pustulka, James D. Ramsdell, David F. Smith and Ronald J. Tanski
 10.2 Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, Seneca Resources Corporation and Matthew D. Cabell
 •  Letter Agreement between the Company and Matthew D. Cabell, dated November 17, 2006 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)

119

     
Exhibit
 Description of
Number
 
Exhibits
 
 •  National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1993 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 1996 in FileNo. 1-3880)
 •  National Fuel Gas Company 1993 Award and Option Plan, amended through June 14, 2001 (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2001 in FileNo. 1-3880)
 •  National Fuel Gas Company 1993 Award and Option Plan, amended through September 8, 2005 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880)
 •  Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880)
 •  National Fuel Gas Company 1997 Award and Option Plan, as amended and restated as of July 23, 2007 (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
 •  Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated March 28, 2005 in FileNo. 1-3880)
 •  Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated May 16, 2006 in FileNo. 1-3880)
 •  Form of Restricted Stock Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
 •  Form of Stock Option Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
 •  Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2008 inFile No. 1-3880)
 •  Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880)
 10.3 Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program
 •  Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.8,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
 •  Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2007 in FileNo. 1-3880)
 10.4 National Fuel Gas Company Executive Annual Cash Incentive Program
 •  Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective February 20, 2008 (Exhibit 10.3,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
 •  National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 1994 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880)

120127

     
Exhibit
 Description of
Number
 
Exhibits
 
•Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in FileNo. 33-49401)
•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 FileNo. 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 FileNo. 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 FileNo. 33-49401)
•Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in FileNo. 1-3880)
•Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
•Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
•Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4,Form 10-Q for the quarterly period ended March 31, 2003 in FileNo. 1-3880)
•Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008 (Exhibit 4.1,Form 10-Q for the quarterly period ended June 30, 2008 in FileNo. 1-3880)
•Officer’s Certificate establishing 8.75% Notes due 2019, dated April 6, 2009 (Exhibit 4.4,Form 8-K dated April 6, 2009 in FileNo. 1-3880)
•Amended and Restated Rights Agreement, dated as of December 4, 2008, between the Company and The Bank of New York, as rights agent (Exhibit 4.1,Form 8-K dated December 4, 2008 in FileNo. 1-3880)
10Material Contracts:
•Credit Agreement, dated as of August 19, 2005, among the Company, the Lenders Party Thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880)
•Form of Indemnification Agreement, dated September 2006, between the Company and each Director (Exhibit 10.1,Form 8-K dated September 18, 2006 in FileNo. 1-3880)
•Settlement Agreement dated January 24, 2008 among the Company, New Mountain Vantage GP, L.L.C. (“Vantage”) and certain of Vantage’s affiliates (Exhibit 10.1,Form 8-K dated January 24, 2008 in FileNo. 1-3880)
•Director Services Agreement, dated as of June 1, 2008, between the Company and Philip C. Ackerman (Exhibit 99,Form 8-K dated June 16, 2008 in FileNo. 1-3880)
•Agreement to Extend Duration of Director Services Agreement, dated June 1, 2009, between the Company and Philip C. Ackerman (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2009 in FileNo. 1-3880)
•Resolutions adopted by the National Fuel Gas Company Board of Directors on February 21, 2008 regarding director stock ownership guidelines (Exhibit 10.5,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
Management Contracts and Compensatory Plans and Arrangements:

128

     
Exhibit
 Description of
Number
 
Exhibits
 
 •  Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and each of Karen M. Camiolo, Carl M. Carlotti, Anna Marie Cellino, Paula M. Ciprich, Donna L. DeCarolis, John R. Pustulka, James D. Ramsdell, David F. Smith and Ronald J. Tanski (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880)
 •  Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, Seneca Resources Corporation and Matthew D. Cabell (Exhibit 10.2,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880)
 •  Letter Agreement between the Company and Matthew D. Cabell, dated November 17, 2006 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
 10.1 Description of September 17, 2009 restricted stock award
 10.2 Description of post-employment medical and prescription drug benefits
 •  National Fuel Gas Company 1997 Award and Option Plan, as amended and restated as of July 23, 2007 (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
 •  Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated March 28, 2005 in FileNo. 1-3880)
 •  Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated May 16, 2006 in FileNo. 1-3880)
 •  Form of Restricted Stock Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
 •  Form of Stock Option Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
 •  Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
 •  Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880)
 •  Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880)
 •  Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program (Exhibit 10.3,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880)
 •  Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2007 in FileNo. 1-3880)
 •  Description of performance goals for certain executive officers under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880)
 •  National Fuel Gas Company Executive Annual Cash Incentive Program (Exhibit 10.4,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880)
 •  Description of performance goals for an executive officer under the Company’s Executive Annual Cash Incentive Program (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880)
 •  Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective February 20, 2008 (Exhibit 10.3,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
 •  National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 1994 in FileNo. 1-3880)

129

Exhibit
Description of
Number
Exhibits
•Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880)
•Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880)
 •  National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880)
 •  Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880)
 •  Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1999 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 2001 in FileNo. 1-3880)
 •  Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21, 2005 (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880)
 •  Form of Letter Regarding Deferred Compensation Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.6,Form 10-K for fiscal year ended September 30, 2005 in FileFile No. 1-3880)
 •  National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10,Form 10-Q for the quarterly period ended June 30, 1997 in FileNo. 1-3880)
 •  Amendment No. 1 to National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880)
 •  Amendment No. 2 to National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 1998 in FileNo. 1-3880)
 •  Form of Letter Regarding Tophat Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880)
 •  National Fuel Gas Company Tophat Plan, Amended and Restated December 7, 2005 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2005 in FileNo. 1-3880)
 •  National Fuel Gas Company Tophat Plan, as amended September 20, 2007 (Exhibit 10.3,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880)
 •  Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and Philip C. Ackerman (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880)
 •  Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
 •  Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
 •  Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
 •  Life Insurance Premium Agreement, dated September 17, 2009, between the Company and David F. Smith (Exhibit 10.1,Form 8-K dated September 23, 2009 in FileNo. 1-3880)
•National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880)
 •  National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880)

130

Exhibit
Description of
Number
Exhibits
 •  Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880)
 •  Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 1998 in FileNo. 1-3880)
•Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
•Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4,Form 10-K/A for fiscal year ended September 30, 2001, in FileNo. 1-3880)
•National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of January 1, 2007 (Exhibit 10.5,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
•National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 20, 2007 (Exhibit 10.4,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880)
•National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008 (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880)
•National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880)
•National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement(I), dated September 1, 2003 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880)
•National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in FileNo. 1-3880)
•Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880)
•National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2009 in FileNo. 1-3880)
•Amended and Restated Retirement Benefit Agreement for David F. Smith, dated September 20, 2007, among the Company, National Fuel Gas Supply Corporation and David F. Smith (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880)
•Description of assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880)
•Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
•Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880)
•Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880)
•Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2006 in FileNo. 1-3880)

121131

     
Exhibit
 Description of
Number
 
Exhibits
 
 •  Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880)
 •  Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4,Form 10-K/A for fiscal year ended September 30, 2001, in FileNo. 1-3880)
 •  National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of January 1, 2007 (Exhibit 10.5,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880)
 •  National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 20, 2007 (Exhibit 10.4,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880)
 10.5 National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008
 •  National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880)
 •  National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880)
 •  National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in FileNo. 1-3880)
 •  Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880)
 •  Amended and Restated Retirement Benefit Agreement for David F. Smith, dated September 20, 2007, among the Company, National Fuel Gas Supply Corporation and David F. Smith (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880)
 •  Description of assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880)
 •  Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.7,Form 10-Q for the quarterly period ended December 31, 2006 inFile No. 1-3880)
 •  Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880)
 •  Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880)
 •  Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2006 in FileNo. 1-3880)
 12  Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2004 through 2008
 21  Subsidiaries of the Registrant
 23  Consents of Experts:
 23.1 Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation
 23.2 Consent of Independent Registered Public Accounting Firm
 31  Rule 13a-14(a)/15d-14(a) Certifications:
 31.1 Written statements of Chief Executive Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act

122

        
Exhibit
Exhibit
 Description of
Exhibit
 Description of
Number
Number
 
Exhibits
Number
 
Exhibits
31.2 Written statements of Principal Financial Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act12  Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2005 through 2009
32  Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 200221  Subsidiaries of the Registrant
99  Additional Exhibits:23  Consents of Experts:
99.1 Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation23.1 Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation
99.2 Company Maps23.2 Consent of Independent Registered Public Accounting Firm
•  Incorporated herein by reference as indicated.31  Rule 13a-14(a)/15d-14(a) Certifications:
   All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report onForm 10-K31.1 Written statements of Chief Executive Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act
••  In accordance with Item 601(b)(32)(ii) ofRegulation S-K and SEC Release Nos.33-8238 and34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference31.2 Written statements of Principal Financial Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act
32  Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99  Additional Exhibits:
99.1 Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation
99.2 Company Maps
•  Incorporated herein by reference as indicated.
   All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report onForm 10-K
••  In accordance with Item 601(b)(32)(ii) ofRegulation S-K and SEC Release Nos.33-8238 and34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference

123132

 
Signatures
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
National Fuel Gas Company
(Registrant)
 
 By /s/  D. F. Smith
D. F. Smith
President and Chief Executive Officer
 
Date: November 26, 200825, 2009
 
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/  P. C. Ackerman

P. C. Ackerman		 Chairman of the Board and Director Date: November 26, 200825, 2009
     
/s/  R. T. Brady

R. T. Brady		 Director Date:                 November 26, 2008
     
/s/  R. D. Cash

R. D. Cash		 Director Date: November 26, 200825, 2009
     
/s/  S. E. Ewing

S. E. Ewing		 Director Date: November 26, 200825, 2009
     
/s/  R. E. Kidder

R. E. Kidder		 Director Date: November 26, 200825, 2009
     
/s/  C. G. Matthews

C. G. Matthews		 Director Date: November 26, 200825, 2009
     
/s/  G. L. Mazanec

G. L. Mazanec		 Director Date: November 26, 200825, 2009
     
/s/  R. G. Reiten

R. G. Reiten		 Director Date: November 26, 200825, 2009
     
/s/  F. V. Salerno

F. V. Salerno		 Director Date: November 26, 200825, 2009
     
/s/  D. F. Smith

D. F. Smith		 President, Chief Executive
Officer and Director		 Date: November 26, 200825, 2009


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Signature
 
Title
  
 
     
/s/  R. J. Tanski

R. J. Tanski		 Treasurer and Principal
Financial Officer		 Date: November 26, 200825, 2009
     
/s/  K. M. Camiolo

K. M. Camiolo		 Controller and Principal
Accounting Officer		 Date: November 26, 200825, 2009


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