UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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| | þ | ANNUAL REPORT PURSUANT TO SECTION 13 orOR 15(d) |
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 20062008
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| | 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)
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| New Jersey | | 13-1086010 |
(State or other jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification No.) |
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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:
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| | | Name of
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| | | Each Exchange
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Title of Each Class | | Registered |
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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 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a non-accelerated filer.smaller reporting company. See definitionthe definitions of “large accelerated filer,” “accelerated filerfiler” and large accelerated filer”“smaller reporting company” in RuleRule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer þ Accelerated Filer o Non-Accelerated Filer | | | |
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller 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 $2,715,600,700$3,768,755,000 as of March 31, 2006.2008.
Common Stock, $1 Par Value, outstanding as of November 30, 2006: 82,385,144October 31, 2008: 79,124,644 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for theits 2009 Annual Meeting of Shareholders to be held February 15, 2007Stockholders are incorporated by reference into Part III of this report.
Glossary of Terms
Frequently used abbreviations, acronyms, or terms used in this report:
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| | 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
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.
MidstreamNational 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.
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
NTSBNational Transportation Safety Board
APB 18Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock
APB 20Accounting Principles Board Opinion No. 20, Accounting Changes
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 Fuel 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.
Cashout revenuesA cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper.
CTACumulative Foreign Currency Translation Adjustment
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 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.
Energy Policy ActEnergy Policy Act of 2005
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.
FINFASB Interpretation Number
FIN 47FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations — an interpretationInterpretation of SFAS 143.
FIN 48FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretationInterpretation 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.
GAAPAccounting 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.
Heavy oilA type of crude petroleum that usually is not economically recoverable in its natural state without being heated or diluted.
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 InterBankInterbank 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)
MMcfMillion cubic feet (of natural gas)
MMcfeMillion cubic feet equivalent
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.”
Order667-APCBAn order issued by FERC to clarify Order 667 entitled “Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005.”
Precedent AgreementAn agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.Polychlorinated 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 these 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 utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundled”) of gas commodity service from transportation service for wholesale and large- volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.
SARStock-settled stock appreciation right
SFASStatement of Financial Accounting Standards
SFAS 35Statement of Financial Accounting Standards No. 3, Reporting5, Accounting Changes in Interim Financial Statementsfor 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 154Statement of Financial Accounting Standards No. 154, Accounting Changes and Error Corrections
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 amendmentAmendment 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, 20062008
CONTENTS
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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 included in thisForm 10-K at itemItem 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, those statements that are designated with an asterisk (“*”) followingregarding 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 statement,adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as those 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
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 consisting ofand reports financial results for five reportable 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 (Empire), a New York joint venture between two wholly-ownedwholly owned subsidiaries of the Company. 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) 2827 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 various other interstate gas pipeline companies. Empire, an intrastate 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 constructing the Empire Connector project, which consists of a compressor station and a77-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. The Millennium Pipeline is expected to serve the New York City area upon its completion. Upon completion of the Empire Connector and Millennium Pipeline projects, which is currently expected to occur in December 2008, the Company acquiredexpects that Empire in February 2003.will become an interstate pipeline company and will merge into Empire Pipeline, Inc. as described below.
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, including offshore areas in federal
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waters and some state waters. Also, ExplorationAt September 30, 2008, the Company had U.S. reserves of 46,198 Mbbl of oil and Production225,899 MMcf of natural gas.
In 2007, Seneca sold its subsidiary, Seneca Energy Canada Inc. (SECI), which conducted exploration and production operations are conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada by Seneca Energy Canada Inc. (SECI), an Alberta, Canada corporation and a subsidiary of Seneca. At September 30, 2006, the Company had U.S. and Canadian reserves of 58,018 Mbbl of oil and 232,575 MMcf of natural gas.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 end-userscustomers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management servicesnatural gas for its customers.
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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, 2006,2008, the Company owned approximately 100,000103,680 acres of timber property and managed an additional 4,0003,122 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 J — Business Segment Information.
The Company’s other direct wholly-ownedwholly owned subsidiaries are not included in any of the five reportablereported business segments and consist of the following:
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| | • | 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-ownedwholly 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; |
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| | • | 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; |
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| | • | Leidy Hub, Inc. (Leidy Hub), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States; |
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| | • | Data-Track Account Services, Inc. (Data-Track), a New York corporation formed to provide collection services principally for the Company’s subsidiaries; |
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| | • | 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; and |
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| | • | 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 |
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| • | National Fuel Gas 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 2006.2008.
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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 atNote C-RegulatoryC — Regulatory Matters.
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. On October 11, 2005,The FERC has authorized Empire
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filed an application with the FERC for the authority to buildconstruct and operate an extension of its natural gas pipelineadditional facilities (the Empire Connector). If the FERC grants that applicationConnector project) and the Company builds and commences operations of the Empire Connector, Empire will at that timeto become a FERC-regulated interstate pipeline company.*company upon placement of those facilities into service, which is currently expected to occur in December 2008. 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 atNote C-RegulatoryC — 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 atNote C-RegulatoryC — 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 36.1%22.9% of the Company’s 20062008 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 40.3%20.1% of the Company’s 20062008 net income available for common stock.
Supply Corporation has service agreements for all of its firm storage capacity, which totals approximatelytotaling 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 3,8884,811 MDth or 5.7%7.1% of the total firm storage capacity. Nonaffiliated customers have contracted for the remaining 36,65535,732 MDth or 53.6%52.2% of the total firm storage capacity. Following an industry trend, mostThe 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 2007, 95.9%2009, 72.0% of Supply Corporation’s total firm storage capacity was committed under contracts that, subject to 20062008 shipper or Supply Corporation notifications, could have been terminated effective in 2007.2009. Supply Corporation neither issued nor receiveddid not issue or
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receive any such storage contract termination noticesnotifications in 2006, however, so it does not expect any storage contract terminations effective in 2007.* In 2006, the increased value of2008. The strong demand for market-area storage affordedenabled Supply Corporation the opportunity to eliminate a significant number of monetaryits remaining storage service rate discounts in 2007, and to sign certain multi-year primary term extensions.effective April 1, 2008, all storage services were contracted at the maximum tariff rates.
Supply Corporation’s firm transportation capacity is not limited to a fixed quantity, due to the diverse weblike 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 1,9952,117 MDth per day (contracted transportation capacity). The Utility segment accounts for approximately 1,0921,065 MDth per day or 54.7%50.3% of contracted transportation capacity, and the Energy Marketing segment representsand Exploration and Production segments represent another 99102 MDth per day or 5.0%4.8% of contracted transportation capacity. The remaining 804950 MDth or 40.3%44.9% of contracted transportation capacity is subject to firm contracts with nonaffiliated customers.
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At the beginning of 2007, 56.9%2009, 49.3% of Supply Corporation’s contracted transportation capacity was committed under affiliate contracts that were scheduled to expire in 20072009 or, subject to 20062008 shipper or Supply Corporation notifications, could have been terminated effective in 2007.2009. Based on contract expirations and termination notices received in 20062008 for 20072009 termination, and taking into account any known contract additions, contracted transportation capacity with affiliates is expected to decrease 0.8%0.3% in 2007.*2009. Similarly, 28.4%26.7% of contracted transportation capacity was committed under unaffiliated shipper contracts that were scheduled to expire in 20072009 or, subject to 20062008 shipper or Supply Corporation notifications, could have been terminated effective in 2007.2009. Based on contract expirations and termination notices received in 20062008 for 20072009 termination, and taking into account any known contract additions, contracted transportation capacity with unaffiliated shippers is expected to decrease 2.4%increase 9.4% in 2007.*2009. 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 itsthis success to continue.*
For the2008-2009 winter period, Empire has service agreements in place for the2006-2007 winter period for all full amount of its firm transportation capacity which totalsto its existing delivery points, totaling approximately 575547 MDth per day. Empire provides service under both annual (12 months per year) and seasonal (winter or summer only) contracts. Approximately 88.7%Most of Empire’s firm capacity (91.2%) has been contracted capacity is on an annualas long-term basis. Annual long-term agreementsfull-year deals. A small number of those contracts are due to expire during fiscal 2009, representing 0.5%1.4% of Empire’s firm contracted capacity expire in 2007. Approximately 3.4%capacity. In addition, Empire has some seasonal (winter-only) contracts that extend for multiple years, representing 2.7% of Empire’s firm contracted capacity is under multi-yearcapacity. One of those seasonal contracts none of whichis due to expire in 2007. The remaining capacity, which represents 7.9%during fiscal 2009; representing 1.1% of Empire’s firm contractedcapacity. Arrangements for the remaining 6.1% of Empire’s firm capacity is under single seasonare seasonal or annual contracts which willthat expire before the end of 2007.fiscal 2009. Empire expects that all of thisavailable capacity arising from expiring capacityagreements will be re-contracted under new seasonaland/or annual arrangements for future contracting periods.*agreements. The Utility segment accounts for approximately 8.6%7.8% of Empire’s firm contracted capacity, and the Energy Marketing segment accounts for approximately 1.7%1.9% of Empire’s firm contracted capacity, with the remaining 89.7%90.3% of Empire’s firm contracted transportation capacity subject to contracts with nonaffiliated customers.
Upon the completion of the Empire Connector project, Empire will have expansion capacity for the2008-2009 winter period. 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 expansion 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.
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 15.2%54.6% of the Company’s 20062008 net income available for common stock.
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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 4.2%2.2% of the Company’s 20062008 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 contributed approximately 4.1% ofsegment’s contribution to the Company’s 20062008 net income available for common stock.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.
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All Other Category and Corporate Operations
The All Other category and Corporate operations contributed less than 1%approximately 0.2% of the Company’s 20062008 net income available for common stock.
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 2006,2008, the Utility segment purchased 74.576.0 Bcf of gas for core market demand. 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 82%89% of these purchases. Purchases of gas on the spot market (contracts for one month or less) accounted for 18%11% of the Utility segment’s 20062008 purchases. Purchases from Chevron Natural Gas (16%), ConocoPhillips Company (15%), Total Gas & Power North America Inc. (11%(18%), Chevron Natural Gas (17%), ConocoPhillips Company (16%) and Anadarko Energy Services CompanyBP Canada (11%) accounted for 53%62% of the Utility’s 20062008 gas purchases. No other producer or supplier provided the Utility segment with more than 10% of its gas requirements in 2006.2008.
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 atNote J-BusinessJ — Business Segment Information andNote O-SupplementaryO — 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-fiveFifty-two percent of the timber processed during 20062008 in Highland’s sawmill operations came from land owned by the Company’s subsidiaries, and 45%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 eight5.4 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 2006,2008, this segment purchased 4757 Bcf of natural gas, of which 45including 56 Bcf servedfor core market demands. The remaining 21 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.
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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.*
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. In both New York and Pennsylvania, Distribution Corporation has retained substantial numbers of residential and small commercial customers as sales customers. However, for many years almost all the industrial and a substantial number of commercial customers have purchased 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, the NYPSC has stepped up its efforts to encourage customer choice at the retail residential level. Inin New York, the Utility segment has instituted a number of programs to accommodate more widespread customer choice. In Pennsylvania, the PaPUC issued a report in October 2005 that concluded “effective competition” does not exist in the retail natural gas supply market statewide. In 2006,On September 11, 2008, the PaPUC reconvenedadopted a stakeholder groupFinal Order and Action Plan designed to explore ways“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 increaseremove “barriers in the market structure” that, in the opinion of the PaPUC, prevented the full participation of unregulated natural gas suppliers in Pennsylvania retail customers in choice programs. The findings of the stakeholder group are expected to be presented to the PaPUC during 2007.markets.
Competition for large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories 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.*
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The Utility segment competes through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets).* by offering unbundled, flexible services. The Utility segment continues to (i) develop or promote new sources and uses of natural gas or new services, rates and contractscontracts. The Utility segment also emphasizes and (ii) emphasize and provideprovides 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 offers 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 particularly 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 pursuingconstructing the Empire Connector project, which wouldwill expand its natural gas pipeline and enable 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.”
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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, each of Seneca and SECI 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.
Competition: The Energy Marketing Segment
The Energy Marketing segment competes with other marketers of natural gas and with other providers of energy management services.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 hardwoodshardwood 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 more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers’ current bills.
Volumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its revenues. Supply Corporation’s allowed rates are based on a straight fixed-variable rate
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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, andwhich 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 can materially affect the volume of gas consumed by customers of the Energy Marketing segment. Volume variations can 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 out lower-grade or lower value trees from the timber stands to encourage the growth of higher-grade or higher value trees.
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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 H — Commitments and Contingencies.
Miscellaneous
The Company and its wholly-ownedwholly owned or majority-owned subsidiaries had a total of 1,9931,943 full-time employees at September 30, 2006, with 1,970 employees in all of its U.S. operations and 23 employees in its Canadian operations at SECI.2008. This is a decrease of 2.5%approximately one-half of one percent from the 2,044 total employed1,952 employees in the Company’s U.S. operations at September 30, 2005.2007.
Agreements covering employees inIn 2008 the Company entered into new agreements with collective bargaining units in New York are scheduled toYork. The new agreements went into effect in February 2008 and expire in February 2008. Certain agreements covering employees in2013. In November 2008 the Company entered into a new agreement with a collective bargaining unitsunit in Pennsylvania are scheduled to expirePennsylvania. The agreement will go into effect in April 2009 and other agreementsexpire in April 2014. An agreement covering employees in another collective bargaining unitsunit in Pennsylvania areis scheduled to expire in May 2009. In November 2008 the Company reached a new agreement with the local leadership of that collective bargaining unit. The members of the collective bargaining unit are scheduled to vote on the agreement in December 2008.
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, 2006 (except as otherwise noted)(1)2008(1)
| | | |
| | | Current Company
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| | | Positions and
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| | | Other Material
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| | | Business Experience
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Name and Age (as of
| | During Past
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November 15, 2006)2008) | | Five Years |
| |
Philip C. AckermanDavid F. Smith
(62)(55) | | Chairman of the Board of Directors since January 2002; Chief Executive Officer since October 2001; and President of Horizon since September 1995. Mr. Ackerman has served as a Director of the Company since March 1994,February 2008 and previously served as President of the Company from July 1999 through January 2006. |
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David F. Smith
(53) | | President of the Company since February 2006;2006. Mr. Smith previously served as Chief Operating Officer of the Company sincefrom February 2006;2006 through January 2008; President of Supply Corporation sincefrom April 2005;2005 through June 2008; President of Empire sincefrom April 2005. Mr. Smith previously served as2005 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. |
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| | |
| | Current Company
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| | Positions and
|
| | Other Material
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| | Business Experience
|
Name and Age (as of
| | During Past
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November 15, 2006)
| | Five Years |
|
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Ronald J. Tanski
(54)(56) | | 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 sincefrom February 2006;2006 through June 2008; Treasurer of Distribution Corporation sincefrom April 2004; Secretary and Treasurer of Supply Corporation since April 2004; Secretary and Treasurer of Horizon since February 1997. Mr. Tanski previously served as2004 through September 2008; Controller of the Company from February 2003 through March 2004; Senior Vice President of Distribution Corporation from July 2001 through January 2006; and Controller of Distribution Corporation from February 1997 through March 2004. |
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Matthew D. Cabell
(48)(50) | | President of Seneca effectivesince December 11, 2006. Prior to joining Seneca, Mr. Cabell previously served as Executive Vice President and General Manager of Marubeni Oil & Gas (USA) Inc., an exploration and production company, with assets of over $1,000,000,000,from June 2003 to December 2006. From January 2002 to June 2003, Mr. Cabell served as Vice President of Randall & Dewey, Inc., a major oil and gas transaction advisory firm, as an independent 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 Gulf of Mexico Exploration for Texaco Corporation.Randall & Dewey, Inc., a major oil and gas transaction advisory firm. Mr. Cabell’s prior employers are not subsidiaries or affiliates of the Company. |
Anna Marie Cellino
(55) | | 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
(47)(49) | | Controller and Principal Accounting Officer of the Company since April 2004; 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) | | 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. |
Anna Marie CellinoPaula M. Ciprich
(53)(48) | | Secretary of the Company since October 1995; Senior Vice President of Distribution Corporation since July 2001. |
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Paula M. Ciprich
(46) | | 2008; General Counsel of the Company since January 2005; Assistant Secretary andof Distribution Corporation since July 2008. Ms. Ciprich previously served as General Counsel of Distribution Corporation sincefrom February 1997. |
| | 1997 through February 2007 and as Assistant Secretary of Distribution Corporation from February 1997 through June 2008. |
Donna L. DeCarolis
(47)(49) | | Vice President Business Development of the Company since October 2007. Ms. DeCarolis previously served as President of NFR sincefrom January 2005;2005 to October 2007; Secretary of NFR sincefrom March 2002;2002 to October 2007; and Vice President of NFR from May 2001 to January 2005. |
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John R. Pustulka
(54)(56) | | Senior Vice President of Supply Corporation since July 2001. |
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James D. Ramsdell
(51)(53) | | Senior Vice President of Distribution Corporation since July 2001. |
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| (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 Fuel depends on its operating subsidiaries to meet its financial obligations.
National Fuel is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, National Fuel relies exclusively on repayments of principal and interest on intercompany loans made by National Fuel 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 financial markets may affect National Fuel’s ability to obtain financing or refinance maturing debt on reasonable terms and may have other adverse effects.
Widely-documented disruptions in financial markets have resulted in a severe tightening of credit availability 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 Fuel to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments and to refinance maturing debt on favorable terms. These difficulties could adversely affect National Fuel’s 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 has relied, and continues to rely,relies upon shorter term bank borrowings and commercial paper to finance the execution of a portion of its operating strategies.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’s ability to borrow under its credit facilities and commercial paper agreements depends on National Fuel’s compliance with its obligations under the facilities and agreements. In addition, all of National Fuel’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 hedges in place to protect against interest rate fluctuations on short-term bank debt. National Fuel has no active interest rate hedges in place with respect to other debt except at the project level of Empire, where there is an interest rate collar on the approximate $22.8 million of project debt (at September 30, 2006). In addition, the interest rates on National Fuel’s short-term bank loans and the ability of National Fuel 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 unsecured credit rating of BBB+ was placed on CreditWatch-with negative implications by S&P. A ratings downgrade could increase the interest cost of this debt issued by National Fuel and decrease future availability of money from banks, commercial paper purchasers and other sources. National FuelFuel’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 Fuel 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’s revenues and cash flows or restrict its future growth. Economic conditions in National Fuel’s utility service territories and energy marketing territories also impact its collections of accounts receivable. All of National Fuel’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’s commodity hedging arrangements might not be able to perform their obligations under these arrangements. Customers of National Fuel’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’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’s credit ratings may not reflect all the risks of an investment in its securities.
National Fuel’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’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’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 Fuel 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’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 its Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC and the PaPUC. 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 if Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover
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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 from marketers, rather than from 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. The purpose of the law wasindustry, to permit consumer choice of natural gas suppliers. To a certain degree, theThe early programs instituted to comply with the Act havedid not been overly successful,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 has reconvened a stakeholder groupin order to explore ways to increaseremove “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 customers in choice programs.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 its efforts to encourage customer choice at the retail residential level. These new formslevel, and customer choice activities increased in Distribution Corporation’s New York service territory. In April 2007, the NYPSC, noting that the retail energy marketplace in New York is established and continuing to expand, commenced a review to determine if existing programs initially designed to promote competition had outlived their usefulness and whether the cost of regulationprograms currently funded by utility rate payers should be shifted to market competitors. Increased retail choice activities, to the extent they occur, may increase Distribution Corporation’s cost 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.
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 Pipeline and Storage segment, National Fuel is subject to the jurisdiction of the FERC with respect to Supply Corporation, and to the jurisdiction of the NYPSC with respect to Empire. (On October 11, 2005,The FERC has authorized Empire filed an application with the FERC for the authority to buildconstruct and operate an extension of its natural gas pipeline (thethe Empire Connector). If the FERC grants that application and the Company buildsConnector 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, approve 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 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.
National Fuel’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’s capital resources. National Fuel has issued commercial paper and used short-term borrowings in the past to temporarily finance storage inventories and purchased gas costs, and although National Fuel expects to do so in the future.*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
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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.
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Uncertain economic conditionsChanges in interest rates may affect National Fuel’s ability to finance capital expenditures and to refinance maturing debt.
National Fuel’s ability to finance capital expenditures and to refinance maturing debt will depend in part upon general economic conditions in the capital markets.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’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’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, National Fuel’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’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 regulations, such as regulation of natural gas transportation, royalties, and price controls. National Fuel sells most of its oil and natural gas at current market prices rather than through fixed-price contracts, although as discussed below, National Fuel frequently hedges the price of a significant portion of its future production in the financial markets. The prices National Fuel receives depend upon factors beyond National Fuel’s control, including the factors affecting price mentioned above. National Fuel 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 Fuel otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.*
National Fuel has significant transactions involving price hedging of its oil and natural gas production.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 periodically 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 70%80% of National Fuel’s expected energy production during the upcoming 12 month12-month period. These contracts reduce exposure to subsequent price drops but can also limit National Fuel’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’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.
In addition, under theUnder applicable accounting rules, suchthe 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, and assumptions regarding the levels of production that will be achieved.achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of
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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 Fuel to the risk of non-performance by a contract counterparty. National Fuel carefully evaluates the financial strength of all contract counterparties, but theseThese parties might not be able to perform their obligations under the hedge arrangements.
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It is National Fuel’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 strictly 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 Fuel maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, couldif they were to occur, that maycould expose National Fuel to substantial losses to cover positions in theseits 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.
You should not place undue reliance on reserve information because such information represents estimates.
ThisForm 10-K contains estimates of National Fuel’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by National Fuel’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’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of National Fuel’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 Fuel 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’s proved reserves is the current market value of National Fuel’s estimated oil and natural gas reserves. In accordance with SEC requirements, National Fuel 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’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’s future reserve estimates.
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’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’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’s earnings. The total and timing of actual future production may
15
vary significantly from reserves and production estimates. National Fuel’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 drynon-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or National Fuel may not recover all or any portion of its investment. Without continued successful exploitation or acquisition activities, National Fuel’s reserves and revenues will decline as a result of its current reserves being depleted by production. National Fuel 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’s profitability.
National Fuel accounts for its exploration and production activities under the full cost method of accounting. Each quarter, on acountry-by-country basis, National Fuel 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.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 revenues,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 Fuel to recognize an immediate expense in that quarter, and its earnings would be reduced. The event that had the most significant impact in 2006, and the main reason for the significant earnings decrease over 2005, was theNational Fuel’s Exploration and Production segment recording after-taxlast recorded an impairment charges totaling $68.6 million related to its Canadian oil and gas assets during 2006charge under the full cost method of accounting.accounting in 2006. Because of the variability in National Fuel’s investment in oil and natural gas properties and the volatile nature of commodity prices, National Fuel cannot predict when in the future it may again be affected by such an impairment calculation.
Environmental regulation significantly affects National Fuel’s business.
National Fuel’s business operations are subject to federal, state, and local laws and regulations (including those of Canada) relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal or discharge of contaminants into the environment and the general protection of public health, natural resources, wildlife and the environment. Costs of compliance and liabilities could negatively affect National Fuel’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. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect National Fuel’s business. Although National Fuel cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local regulations, National Fuel’s costs could increase if environmental laws and regulations become more strict.
The nature of National Fuel’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
National Fuel’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;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’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 Fuel maintains insurance coverage against some, but not all, potential losses. In addition, many of the
16
agreements that National Fuel executes with contractors provide for the division of responsibilities between the contractor and National Fuel, and National Fuel seeks to obtain an indemnification from the contractor for certain of these risks. National Fuel is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes National Fuel is required to indemnify others.
Insurance or indemnification agreements when obtained may not adequately protect National Fuel 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. 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 largethe significant cost of insurance losses caused by Hurricanes Katrina and Ritacoverage for named windstorms in 2005, the insurance industry has significantly increased premiums for insurance on Gulf of Mexico, properties, and has reduced the limits typically available for windstorm damage. As a result, National Fuel has determined that it iswas 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 in the eventcould have a material adverse effect on National Fuel’s results of a named windstorm. National Fuel has procured named windstorm coverage in an amount equal to approximately three times the estimated physical damage loss sustained by National Fuel as a result of named windstorms during the 2005 hurricane season, subject to a deductible of $2 million per occurrence. No assurance can be given, however, that such amount will be sufficient to cover losses that may occur in the future.operations, financial condition and cash flows.
Hazards and risks faced by National Fuel, and insurance and indemnification obtained or provided by National Fuel, may subject National Fuel to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against National Fuel or be resolved on unfavorable terms, the result of which could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.
Significant shareholders or potential shareholders may attempt to effect changes at National Fuel may be adversely affected by economic conditions.
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 activityacquire control over National Fuel, which could adversely affect National Fuel’s revenuesresults of operations and cash flows or restrict its future growth. Economic conditions infinancial condition.
In January 2008, National Fuel 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’s utility service territories also impactBoard of Directors at National Fuel’s 2008 Annual Meeting of Stockholders. Pursuant to the settlement agreement, National Fuel and 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 collectionsbeneficial ownership to more than 9.6% of accounts receivable.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, advance shareholder proposals or otherwise attempt to effect changes or acquire control over National Fuel.
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, restructuring, increased financial leverage, 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’s operations and diverting the attention of National Fuel’s Board of Directors and senior management. As a result, shareholder campaigns could adversely affect National Fuel’s results of operations and financial condition.
| |
| Item 1B | Unresolved Staff Comments |
None
General Information on Facilities
The net investment of the Company in net property, plant and equipment was $2.9$3.2 billion at September 30, 2006.2008. Approximately 61%62% 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%), 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 and in the provinces of Alberta, Saskatchewan and British Columbia in Canada.Alabama. The remaining net investment in net property, plant and equipment consisted primarily of the Timber segment (3%(2%) which is located primarily in northwestern Pennsylvania, and All Other and Corporate operations (1%). 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 $97.0$163.1 million, or 3.5%5.5%, since 2001.2003. 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
17
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, 2006.2008. The net investment in its gas distribution network (including 14,80914,819 miles of distribution pipeline) and its service connections to customers represent approximately 53%52% and 33%34%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2006.2008.
The Pipeline and Storage segment had a net investment of $674.2$826.5 million in property, plant and equipment at September 30, 2006.2008. Transmission pipeline represents 36%27% of this segment’s total net investment and includes 2,5282,371 miles of pipeline requiredutilized to move large volumes of gas throughout its service area. Storage facilities represent 24%21% of this segment’s total net investment and consist of 3231 storage fields, four of which are jointly owned and operated with certain pipeline suppliers, and 439429 miles of pipeline. Net investment in storage facilities includes $93.8$94.8 million of gas stored underground-noncurrent, representing the cost of the gas requiredutilized 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 2827 compressor stations with 75,36175,104 installed compressor horsepower that represent 13%11% 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 $1.0$1.1 billion at September 30, 2006. Of this amount, $914.2 million relates to properties located in the United States. The remaining net investment of $88.0 million relates to properties located in Canada.2008.
19
The Timber segment had a net investment in property, plant and equipment of $90.9$86.4 million at September 30, 2006.2008. Located primarily in northwestern Pennsylvania, the net investment includes two sawmills, approximately 100,000103,680 acres of land and timber, and approximately 4,0003,122 acres of timber rights.
The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet the Company’s 20062008 peak day sendout, including transportation service, of 1,542.41,632 MMcf, which occurred on February 18, 2006.10, 2008. Withdrawals from storage of 545.2768.3 MMcf provided approximately 35.3%47.1% of the requirements on that day.
Company maps are included in exhibit 99.399.2 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. Also, Exploration and Production operations arewere conducted in the provinces of Alberta, Saskatchewan and British Columbia in Canada.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 I — Discontinued Operations. Further discussion of oil and gas producing activities is included in Item 8,Note O-SupplementaryO — Supplementary Information for Oil and Gas Producing Activities. Note O sets forth proved developed and undeveloped reserve information for Seneca. Seneca’s proved developed and undeveloped natural gas reserves decreasedincreased from 238205 Bcf at September 30, 20052007 to 233226 Bcf at September 30, 2006.2008. This decrease can beincrease is attributed primarily to productionextensions and downward reserve revisions relateddiscoveries (40.1 Bcf), primarily toin the Canadian properties. These decreases wereAppalachian region (31.3 Bcf). This increase was partially offset by extensions and discoveries. The downward reserve revisions were largely a functionproduction of a significant decrease in gas prices during the fourth quarter of 2006.22.3 Bcf. Seneca’s proved developed and undeveloped oil reserves decreased from 60,25747,586 Mbbl at September 30, 20052007 to 58,01846,198 Mbbl at September 30, 2006.2008. This decrease can beis attributed mostly to production.production (3,070 Mbbl), primarily occurring in California (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 increaseddecreased from 225233 Bcf at September 30, 20042006 to 238205 Bcf at September 30, 2005.2007. This increase can bedecrease is attributed primarily to the fact that netsale of the Canadian gas properties (40.1 Bcf) and production of 26.3 Bcf. These decreases were partially offset by extensions and discoveries outpaced production. However,of 34.6 Bcf, primarily in the Appalachian region (29.7 Bcf). Seneca’s proved developed and undeveloped oil reserves decreased from 65,21358,018 Mbbl at September 30, 20042006 to 60,25747,586 Mbbl at September 30, 2005.2007. This decrease can beis attributed to revisions of previous estimates (5,963 Mbbl), primarily occurring in California, production (3,450 Mbbl) and the fact that production outpaced net extensionssale of the Canadian oil properties (1,458 Mbbl). On a Bcfe basis, Seneca’s proved developed and discoveries.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 O as of September 30, 20062008 were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Ralph E. DavisNetherland, Sewell & Associates, Inc. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA), a
18
statistical agency of the U.S. Department of Energy. The basis of reporting Seneca’s reservesoil and gas reserve information reported to the EIA is identicalshowed 204 Bcf and 49,899 Mbbl of gas and oil reserves, respectively, which differs from the reserve information summarized in Item 8 at Note O. The reasons for this difference are as follows: (a) reserves are reported to thatthe EIA on a calendar year basis, while reserves disclosed in Item 8 at Note O 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 O.O 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, which are reported on a net revenue interest basis.
20
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 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
United States | | | | | | | | | | | | | | | | | | | | | | | | |
| Gulf Coast Region | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 8.01 | | | $ | 7.05 | | | $ | 5.61 | | | $ | 10.03 | | | $ | 6.58 | | | $ | 8.01 | |
| Average Sales Price per Barrel of Oil | | $ | 64.10 | | | $ | 49.78 | | | $ | 35.31 | | | $ | 107.27 | | | $ | 63.04 | | | $ | 64.10 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 5.89 | | | $ | 6.01 | | | $ | 4.82 | | | $ | 9.49 | | | $ | 6.87 | | | $ | 5.89 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 47.46 | | | $ | 35.03 | | | $ | 31.51 | | | $ | 98.56 | | | $ | 64.09 | | | $ | 47.46 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 0.86 | | | $ | 0.71 | | | $ | 0.60 | | | $ | 1.63 | | | $ | 1.08 | | | $ | 0.86 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 36 | | | | 50 | | | | 73 | | | | 38 | | | | 40 | | | | 36 | |
| West Coast Region | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 7.93 | | | $ | 6.85 | | | $ | 5.54 | | | $ | 8.71 | | | $ | 6.54 | | | $ | 7.93 | |
| Average Sales Price per Barrel of Oil | | $ | 56.80 | | | $ | 42.91 | | | $ | 31.89 | | | $ | 98.17 | | | $ | 56.86 | | | $ | 56.80 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 7.19 | | | $ | 6.15 | | | $ | 5.72 | | | $ | 8.22 | | | $ | 6.82 | | | $ | 7.19 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 37.69 | | | $ | 23.01 | | | $ | 22.86 | | | $ | 77.64 | | | $ | 47.43 | | | $ | 37.69 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 1.35 | | | $ | 1.15 | | | $ | 1.05 | | | $ | 2.01 | | | $ | 1.54 | | | $ | 1.35 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 53 | | | | 53 | | | | 55 | | | | 51 | | | | 50 | | | | 53 | |
| Appalachian Region | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 9.53 | | | $ | 7.60 | | | $ | 5.91 | | | $ | 9.73 | | | $ | 7.48 | | | $ | 9.53 | |
| Average Sales Price per Barrel of Oil | | $ | 65.28 | | | $ | 48.28 | | | $ | 31.30 | | | $ | 97.40 | | | $ | 62.26 | | | $ | 65.28 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 8.90 | | | $ | 7.01 | | | $ | 5.72 | | | $ | 8.85 | | | $ | 8.25 | | | $ | 8.90 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 65.28 | | | $ | 48.28 | | | $ | 31.30 | | | $ | 97.40 | | | $ | 62.26 | | | $ | 65.28 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 0.69 | | | $ | 0.63 | | | $ | 0.54 | | | $ | 0.77 | | | $ | 0.69 | | | $ | 0.69 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 15 | | | | 13 | | | | 14 | | | | 22 | | | | 17 | | | | 15 | |
Total United States | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 8.42 | | | $ | 7.13 | | | $ | 5.66 | | | $ | 9.70 | | | $ | 6.82 | | | $ | 8.42 | |
| Average Sales Price per Barrel of Oil | | $ | 58.47 | | | $ | 44.87 | | | $ | 33.13 | | | $ | 99.64 | | | $ | 58.43 | | | $ | 58.47 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 7.02 | | | $ | 6.26 | | | $ | 5.13 | | | $ | 9.05 | | | $ | 7.25 | | | $ | 7.02 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 40.26 | | | $ | 26.59 | | | $ | 26.06 | | | $ | 81.75 | | | $ | 51.68 | | | $ | 40.26 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 1.09 | | | $ | 0.90 | | | $ | 0.76 | | | $ | 1.64 | | | $ | 1.23 | | | $ | 1.09 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 104 | | | | 117 | | | | 142 | | | | 111 | | | | 108 | | | | 104 | |
1921
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended September 30 | | | For The Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
Canada | | | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 7.14 | | | $ | 6.15 | | | $ | 4.87 | | | $ | — | | | $ | 6.09 | | | $ | 7.14 | |
| Average Sales Price per Barrel of Oil | | $ | 51.40 | | | $ | 42.97 | | | $ | 30.94 | | | $ | — | | | $ | 50.06 | | | $ | 51.40 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 7.47 | | | $ | 6.14 | | | $ | 4.79 | | | $ | — | | | $ | 6.17 | | | $ | 7.47 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 51.40 | | | $ | 42.97 | | | $ | 30.94 | | | $ | — | | | $ | 50.06 | | | $ | 51.40 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 1.57 | | | $ | 1.29 | | | $ | 1.00 | | | $ | — | | | $ | 1.94 | | | $ | 1.57 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 26 | | | | 27 | | | | 22 | | | | — | | | | 21 | | | | 26 | |
Total Company | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Sales Price per Mcf of Gas | | $ | 8.04 | | | $ | 6.86 | | | $ | 5.51 | | | $ | 9.70 | | | $ | 6.64 | | | $ | 8.04 | |
| Average Sales Price per Barrel of Oil | | $ | 57.94 | | | $ | 44.72 | | | $ | 32.98 | | | $ | 99.64 | | | $ | 57.93 | | | $ | 57.94 | |
| Average Sales Price per Mcf of Gas (after hedging) | | $ | 7.15 | | | $ | 6.23 | | | $ | 5.06 | | | $ | 9.05 | | | $ | 6.98 | | | $ | 7.15 | |
| Average Sales Price per Barrel of Oil (after hedging) | | $ | 41.10 | | | $ | 27.86 | | | $ | 26.40 | | | $ | 81.75 | | | $ | 51.58 | | | $ | 41.10 | |
| Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | | $ | 1.18 | | | $ | 0.98 | | | $ | 0.80 | | | $ | 1.64 | | | $ | 1.35 | | | $ | 1.18 | |
| Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | | | 130 | | | | 144 | | | | 164 | | | | 111 | | | | 129 | | | | 130 | |
Productive Wells
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | United States | | | | | | | |
| | | Gulf Coast
| | | West Coast
| | | Appalachian
| | | | |
| | | Region | | | Region | | | Region | | | Total U.S. | |
At September 30, 2006 | | Gas | | | Oil | | | Gas | | | Oil | | | Gas | | | Oil | | | Gas | | | Oil | |
| |
| Productive Wells — Gross | | | 34 | | | | 30 | | | | — | | | | 1,274 | | | | 2,138 | | | | 31 | | | | 2,172 | | | | 1,335 | |
| Productive Wells — Net | | | 21 | | | | 14 | | | | — | | | | 1,266 | | | | 2,052 | | | | 25 | | | | 2,073 | | | | 1,305 | |
Productive Wells
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Canada | | Total Company | | | Gulf Coast
| | West Coast
| | Appalachian
| | | | | |
At September 30, 2006 | | Gas | | Oil | | Gas | | Oil | | |
| | | | Region | | Region | | Region | | Total Company | |
At September 30, 2008 | | | Gas | | Oil | | Gas | | Oil | | Gas | | Oil | | Gas | | Oil | |
| |
| Productive Wells — Gross | | | 217 | | | | 53 | | | | 2,389 | | | | 1,388 | | | | 25 | | | | 42 | | | | — | | | | 1,437 | | | | 2,641 | | | | 6 | | | | 2,666 | | | | 1,485 | |
| Productive Wells — Net | | | 155 | | | | 36 | | | | 2,228 | | | | 1,341 | | | | 14 | | | | 14 | | | | — | | | | 1,426 | | | | 2,570 | | | | 5 | | | | 2,584 | | | | 1,445 | |
Developed and Undeveloped Acreage
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | United States | | | | | | | Gulf
| | West
| | | | | |
| | | Golf
| | West
| | | | | | | | | | | Coast
| | Coast
| | Appalachian
| | Total
| |
| | | Coast
| | Coast
| | Appalachian
| | Total
| | | | Total
| | |
At September 30, 2006 | | Region | | Region | | Region | | U.S. | | Canada | | Company | | |
At September 30, 2008 | | | Region | | Region | | Region | | Company | |
| |
| Developed Acreage | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Gross | | | 144,610 | | | | 10,479 | | | | 514,222 | | | | 669,311 | | | | 117,955 | | | | 787,266 | | | | 113,934 | | | | 11,360 | | | | 531,743 | | | | 657,037 | |
| — Net | | | 104,173 | | | | 10,109 | | | | 487,384 | | | | 601,666 | | | | 84,182 | | | | 685,848 | | | | 80,852 | | | | 10,945 | | | | 501,411 | | | | 593,208 | |
| Undeveloped Acreage | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Gross | | | 174,503 | | | | — | | | | 475,909 | | | | 650,412 | | | | 393,169 | | | | 1,043,581 | | | | 142,118 | | | | — | | | | 458,894 | | | | 601,012 | |
| — Net | | | 85,117 | | | | — | | | | 451,733 | | | | 536,850 | | | | 243,287 | | | | 780,137 | | | | 102,831 | | | | — | | | | 438,040 | | | | 540,871 | |
As of September 30, 2006,2008, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 191,159 acres in 2007 (128,900 net acres), 112,156 acres in 2008 (65,174 net acres), 83,24638,811 acres in 2009 (57,538(23,289 net acres), 23,302 acres in 2010 (11,754 net acres), 82,165 acres in 2011 (67,472 net acres), and 657,020456,734 acres thereafter (528,525(438,356 net acres).
2022
Drilling Activity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Productive | | Dry | | | Productive | | Dry | |
For the Year Ended September 30 | | 2006 | | 2005 | | 2004 | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | | 2008 | | 2007 | | 2006 | |
| |
United States | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gulf Coast Region | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 2.94 | | | | 1.30 | | | | — | | | | 0.85 | | | | 0.47 | | | | 0.50 | | | | 1.14 | | | | 1.31 | | | | 2.94 | | | | 0.37 | | | | 1.42 | | | | 0.85 | |
| — Development | | | 0.78 | | | | 0.23 | | | | 0.65 | | | | — | | | | — | | | | — | | | | — | | | | 1.00 | | | | 0.78 | | | | — | | | | 0.67 | | | | — | |
| West Coast Region Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | |
| West Coast Region | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1.00 | | | | 0.50 | | | | — | | | | — | | | | — | | | | — | |
| — Development | | | 92.98 | | | | 116.97 | | | | 49.00 | | | | 1.00 | | | | — | | | | — | | | | 62.00 | | | | 58.99 | | | | 92.98 | | | | 1.00 | | | | 2.00 | | | | 1.00 | |
| Appalachian Region Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | |
| Appalachian Region | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 3.88 | | | | 3.00 | | | | — | | | | — | | | | 4.00 | | | | 3.00 | | | | 8.00 | | | | 8.10 | | | | 3.88 | | | | 1.00 | | | | — | | | | — | |
| — Development | | | 140.58 | | | | 45.00 | | | | 41.00 | | | | 1.75 | | | | 1.00 | | | | — | | | | 186.00 | | | | 184.00 | | | | 140.58 | | | | — | | | | 2.00 | | | | 1.75 | |
| Total United States Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total United States | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 6.82 | | | | 4.30 | | | | — | | | | 0.85 | | | | 4.47 | | | | 3.50 | | | | 10.14 | | | | 9.91 | | | | 6.82 | | | | 1.37 | | | | 1.42 | | | | 0.85 | |
| — Development | | | 234.34 | | | | 162.20 | | | | 90.65 | | | | 2.75 | | | | 1.00 | | | | — | | | | 248.00 | | | | 243.99 | | | | 234.34 | | | | 1.00 | | | | 4.67 | | | | 2.75 | |
Canada | | | | | | | | | | | | | | | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 12.60 | | | | 21.14 | | | | 52.85 | | | | 1.35 | | | | 2.00 | | | | 6.08 | | | | — | | | | 6.38 | | | | 12.60 | | | | — | | | | — | | | | 1.35 | |
| — Development | | | 2.50 | | | | 3.50 | | | | 10.50 | | | | 1.00 | | | | — | | | | — | | | | — | | | | 1.80 | | | | 2.50 | | | | — | | | | — | | | | 1.00 | |
Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Wells Completed | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Exploratory | | | 19.42 | | | | 25.44 | | | | 52.85 | | | | 2.20 | | | | 6.47 | | | | 9.58 | | | | 10.14 | | | | 16.29 | | | | 19.42 | | | | 1.37 | | | | 1.42 | | | | 2.20 | |
| — Development | | | 236.84 | | | | 165.70 | | | | 101.15 | | | | 3.75 | | | | 1.00 | | | | — | | | | 248.00 | | | | 245.79 | | | | 236.84 | | | | 1.00 | | | | 4.67 | | | | 3.75 | |
Present Activities
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | United States | | | | | | | Gulf
| | West
| | | | | |
| | | Gulf
| | West
| | | | | | | | | | | Coast
| | Coast
| | Appalachian
| | Total
| |
| | | Coast
| | Coast
| | Appalachian
| | Total
| | | | Total
| | |
At September 30, 2006 | | Region | | Region | | Region | | U.S. | | Canada | | Company | | |
At September 30, 2008 | | | Region | | Region | | Region | | Company | |
| |
| Wells in Process of Drilling(1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| — Gross | | | 5.00 | | | | 6.00 | | | | 54.00 | | | | 65.00 | | | | 5.00 | | | | 70.00 | | | | 2.00 | | | | 1.00 | | | | 148.00 | | | | 151.00 | |
| — Net | | | 2.69 | | | | 5.50 | | | | 54.00 | | | | 62.19 | | | | 2.13 | | | | 64.32 | | | | 0.59 | | | | 1.00 | | | | 146.00 | | | | 147.59 | |
| | |
| (1) | | Includes wells awaiting completion. |
In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused the decedent’s death in February 2001. The plaintiff sought damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation denied plaintiff’s material allegations, asserted seven affirmative defenses and asserted a cross-claim against the co-defendant. Distribution Corporation believes, and has vigorously asserted, that plaintiff’s allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. Discovery closed in October 2005, and Distribution Corporation filed a motion for summary judgment in November 2005. On February 24, 2006, the Court granted Distribution Corporation’s motion for summary
21
judgment dismissing plaintiff’s claims for wrongful death and punitive damages. The Court denied Distribution Corporation’s motion for summary judgment to dismiss plaintiff’s negligence claim seeking recovery for conscious pain and suffering. On March 15, 2006, the plaintiff appealed the Court’s decision to the New York State Supreme Court, Appellate Division, Fourth Department. On March 29, 2006, Distribution Corporation filed a cross-appeal. A trial date is scheduled for October 15, 2007 (although it is possible that the Court may change that date or that a trial may become unnecessary, based on the progress or outcome of the pending appeals).
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and a motion for summary disposition against Supply Corporation with the FERC under Sections 5(a) and 13 of the Natural Gas Act. For a discussion of these matters, refer to Part II, Item 7 — MD&A of this report under the heading “Other Matters — Rate and Regulatory Matters.”
On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation, the PaPUC and certain others as a result of its investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. For a discussion of this matter, refer to Part II, Item 7 — MD&A of this report under the heading “Other Matters — Rate and Regulatory Matters.”
The Company believes, based on the information presently known, that the ultimate resolution of the above matters will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcome of these matters, and it is possible that the outcome could be material to results of operations or cash flow for a particular quarter or annual period.*
For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note H — Commitments and Contingencies.
In addition to thethese matters, disclosed above, 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, 2006.2008.
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 atNote E-CapitalizationE — Capitalization and Short-Term Borrowings andNote N-MarketN — Market for Common Stock and Related Shareholder Matters (unaudited).
On July 1, 2006,2, 2008, the Company issued a total of 2,1002,400 unregistered shares of Company common stock to the seveneight 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, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for such directors’ services during the quarter ended September 30, 2006, pursuant to the Company’s Retainer Policy for Non-Employee Directors.2008. 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, 2006 | | | 444,198 | | | $ | 36.32 | | | | 94,400 | | | | 5,621,250 | |
| Aug. 1-31, 2006 | | | 47,155 | | | $ | 37.91 | | | | — | | | | 5,621,250 | |
| Sept. 1-30, 2006 | | | 192,702 | | | $ | 36.46 | | | | 147,800 | | | | 5,473,450 | |
| | | | | | | | | | | | | | | | | |
| Total | | | 684,055 | | | $ | 36.47 | | | | 242,200 | | | | 5,473,450 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | 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 | |
| | | | | | | | | | | | | | | | | |
| | |
| (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, (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) shares of common stock of the Company purchased on the open market pursuant to the Company’s publicly announced share repurchase program. Shares purchased other than through a publicly announced share repurchase program totaled 349,7986,404 in July 2006, 47,1552008, 7,817 in August 20062008 and 44,9027,947 in September 20062008 (a three monththree-month total of 441,855)22,168). OfAll of those shares 27,499 were purchased for the Company’s 401(k) plans and 414,356 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.plans. |
| |
| (b) | | OnIn December 8, 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. RepurchasesThe 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 from time to timein the future if conditions improve. Such repurchases would be made in the open market or through private transactions. |
24
| |
| Item 6 | Selected Financial Data(1)Data |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | | | 2008 | | 2007 | | 2006 | | 2005 | | 2004 | |
| | | (Thousands) | | | (Thousands) | |
| |
Summary of Operations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,311,659 | | | $ | 1,923,549 | | | $ | 1,907,968 | | | $ | 1,921,573 | | | $ | 1,369,869 | | | $ | 2,400,361 | | | $ | 2,039,566 | | | $ | 2,239,675 | | | $ | 1,860,774 | | | $ | 1,867,875 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Purchased Gas | | | 1,267,562 | | | | 959,827 | | | | 949,452 | | | | 963,567 | | | | 462,857 | | | | 1,235,157 | | | | 1,018,081 | | | | 1,267,562 | | | | 959,827 | | | | 949,452 | |
| Operation and Maintenance | | | 413,726 | | | | 404,517 | | | | 385,519 | | | | 361,898 | | | | 372,063 | | | | 432,871 | | | | 396,408 | | | | 395,289 | | | | 388,094 | | | | 374,010 | |
| Property, Franchise and Other Taxes | | | 69,942 | | | | 69,076 | | | | 68,978 | | | | 79,692 | | | | 69,837 | | | | 75,585 | | | | 70,660 | | | | 69,202 | | | | 68,164 | | | | 68,378 | |
| Depreciation, Depletion and Amortization | | | 179,615 | | | | 179,767 | | | | 174,289 | | | | 181,329 | | | | 168,745 | | | | 170,623 | | | | 157,919 | | | | 151,999 | | | | 156,502 | | | | 159,184 | |
| Impairment of Oil and Gas Producing Properties | | | 104,739 | | | | — | | | | — | | | | 42,774 | | | | — | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2,035,584 | | | | 1,613,187 | | | | 1,578,238 | | | | 1,629,260 | | | | 1,073,502 | | | | 1,914,236 | | | | 1,643,068 | | | | 1,884,052 | | | | 1,572,587 | | | | 1,551,024 | |
| Gain (Loss) on Sale of Timber Properties | | | — | | | | — | | | | (1,252 | ) | | | 168,787 | | | | — | | |
| Gain (Loss) on Sale of Oil and Gas Producing Properties | | | — | | | | — | | | | 4,645 | | | | (58,472 | ) | | | — | | |
| Loss on Sale of Timber Properties | | | | — | | | | — | | | | — | | | | — | | | | (1,252 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 276,075 | | | | 310,362 | | | | 333,123 | | | | 402,628 | | | | 296,367 | | | | 486,125 | | | | 396,498 | | | | 355,623 | | | | 288,187 | | | | 315,599 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | |
| Income from Unconsolidated Subsidiaries | | | | 6,303 | | | | 4,979 | | | | 3,583 | | | | 3,362 | | | | 805 | |
| Impairment of Investment in Partnership | | | | — | | | | — | | | | — | | | | (4,158 | ) | | | — | |
| Interest Income | | | | 10,815 | | | | 1,550 | | | | 9,409 | | | | 6,236 | | | | 1,771 | |
| 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 | ) |
| Other Interest Expense | | | | (3,870 | ) | | | (6,029 | ) | | | (5,952 | ) | | | (9,069 | ) | | | (6,354 | ) |
| | | | | | | | | | | | | |
| Income from Continuing Operations Before Income Taxes | | | | 436,650 | | | | 333,488 | | | | 292,859 | | | | 224,058 | | | | 231,740 | |
| Income Tax Expense | | | | 167,922 | | | | 131,813 | | | | 108,245 | | | | 85,621 | | | | 89,820 | |
| | | | | | | | | | | | | |
| Income from Continuing Operations | | | | 268,728 | | | | 201,675 | | | | 184,614 | | | | 138,437 | | | | 141,920 | |
| | | | | | | | | | | | | |
| Discontinued Operations: | | | | | | | | | | | | | | | | | | | | | |
| Income (Loss) from Operations, Net of Tax | | | | — | | | | 15,479 | | | | (46,523 | ) | | | 25,277 | | | | 24,666 | |
| Gain on Disposal, Net of Tax | | | | — | | | | 120,301 | | | | — | | | | 25,774 | | | | — | |
| | | | | | | | | | | | | |
| Income (Loss) from Discontinued Operations, Net of Tax | | | | — | | | | 135,780 | | | | (46,523 | ) | | | 51,051 | | | | 24,666 | |
| | | | | | | | | | | | | |
| Net Income Available for Common Stock | | | $ | 268,728 | | | $ | 337,455 | | | $ | 138,091 | | | $ | 189,488 | | | $ | 166,586 | |
| | | | | | | | | | | | | |
2325
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | | | 2003 | | | 2002 | |
| | | (Thousands) | |
| |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Income from Unconsolidated Subsidiaries | | | 3,583 | | | | 3,362 | | | | 805 | | | | 535 | | | | 224 | |
| Impairment of Investment in Partnership | | | — | | | | (4,158 | ) | | | — | | | | — | | | | (15,167 | ) |
| Interest Income | | | 10,275 | | | | 6,496 | | | | 1,771 | | | | 2,204 | | | | 2,593 | |
| Other Income | | | 2,825 | | | | 12,744 | | | | 2,908 | | | | 2,427 | | | | 3,184 | |
| Interest Expense on Long-Term Debt | | | (72,629 | ) | | | (73,244 | ) | | | (82,989 | ) | | | (91,381 | ) | | | (88,646 | ) |
| Other Interest Expense | | | (5,952 | ) | | | (9,069 | ) | | | (6,763 | ) | | | (11,196 | ) | | | (15,109 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Income from Continuing Operations Before Income Taxes | | | 214,177 | | | | 246,493 | | | | 248,855 | | | | 305,217 | | | | 183,446 | |
| Income Tax Expense | | | 76,086 | | | | 92,978 | | | | 94,590 | | | | 124,150 | | | | 69,944 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income from Continuing Operations | | | 138,091 | | | | 153,515 | | | | 154,265 | | | | 181,067 | | | | 113,502 | |
| | | | | | | | | | | | | | | | | | | | | |
| Discontinued Operations: | | | | | | | | | | | | | | | | | | | | |
| Income from Operations, Net of Tax | | | — | | | | 10,199 | | | | 12,321 | | | | 6,769 | | | | 4,180 | |
| Gain on Disposal, Net of Tax | | | — | | | | 25,774 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Income from Discontinued Operations, Net of Tax | | | — | | | | 35,973 | | | | 12,321 | | | | 6,769 | | | | 4,180 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Cumulative Effect of Changes in Accounting | | | 138,091 | | | | 189,488 | | | | 166,586 | | | | 187,836 | | | | 117,682 | |
| Cumulative Effect of Changes in Accounting | | | — | | | | — | | | | — | | | | (8,892 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income Available for Common Stock | | $ | 138,091 | | | $ | 189,488 | | | $ | 166,586 | | | $ | 178,944 | | | $ | 117,682 | |
| | | | | | | | | | | | | | | | | | | | | |
Per Common Share Data | | | | | | | | | | | | | | | | | | | | |
| Basic Earnings from Continuing Operations per Common Share | | $ | 1.64 | | | $ | 1.84 | | | $ | 1.88 | | | $ | 2.24 | | | $ | 1.42 | |
| Diluted Earnings from Continuing Operations per Common Share | | $ | 1.61 | | | $ | 1.81 | | | $ | 1.86 | | | $ | 2.23 | | | $ | 1.41 | |
| Basic Earnings per Common Share(2) | | $ | 1.64 | | | $ | 2.27 | | | $ | 2.03 | | | $ | 2.21 | | | $ | 1.47 | |
| Diluted Earnings per Common Share(2) | | $ | 1.61 | | | $ | 2.23 | | | $ | 2.01 | | | $ | 2.20 | | | $ | 1.46 | |
| Dividends Declared | | $ | 1.18 | | | $ | 1.14 | | | $ | 1.10 | | | $ | 1.06 | | | $ | 1.03 | |
| Dividends Paid | | $ | 1.17 | | | $ | 1.13 | | | $ | 1.09 | | | $ | 1.05 | | | $ | 1.02 | |
| Dividend Rate at Year-End | | $ | 1.20 | | | $ | 1.16 | | | $ | 1.12 | | | $ | 1.08 | | | $ | 1.04 | |
| At September 30: | | | | | | | | | | | | | | | | | | | | |
Number of Registered Shareholders | | | 17,767 | | | | 18,369 | | | | 19,063 | | | | 19,217 | | | | 20,004 | |
| | | | | | | | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | | | 2008 | | 2007 | | 2006 | | 2005 | | 2004 | |
| | | (Thousands) | | | (Thousands) | |
| |
Per Common Share Data | | | | | | | | | | | | | | | | | | | | | |
| Basic Earnings from Continuing Operations per Common Share | | | $ | 3.27 | | | $ | 2.43 | | | $ | 2.20 | | | $ | 1.66 | | | $ | 1.73 | |
| Diluted Earnings from Continuing Operations per Common Share | | | $ | 3.18 | | | $ | 2.37 | | | $ | 2.15 | | | $ | 1.63 | | | $ | 1.71 | |
| Basic Earnings per Common Share(1) | | | $ | 3.27 | | | $ | 4.06 | | | $ | 1.64 | | | $ | 2.27 | | | $ | 2.03 | |
| Diluted Earnings per Common Share(1) | | | $ | 3.18 | | | $ | 3.96 | | | $ | 1.61 | | | $ | 2.23 | | | $ | 2.01 | |
| Dividends Declared | | | $ | 1.27 | | | $ | 1.22 | | | $ | 1.18 | | | $ | 1.14 | | | $ | 1.10 | |
| Dividends Paid | | | $ | 1.26 | | | $ | 1.21 | | | $ | 1.17 | | | $ | 1.13 | | | $ | 1.09 | |
| Dividend Rate at Year-End | | | $ | 1.30 | | | $ | 1.24 | | | $ | 1.20 | | | $ | 1.16 | | | $ | 1.12 | |
| At September 30: | | | | | | | | | | | | | | | | | | | | | |
Number of Registered Shareholders | | | | 16,544 | | | | 16,989 | | | | 17,767 | | | | 18,369 | | | | 19,063 | |
| | | | | | | | | | | | | |
Net Property, Plant and Equipment | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Utility | | $ | 1,084,080 | | | $ | 1,064,588 | | | $ | 1,048,428 | | | $ | 1,028,393 | | | $ | 960,015 | | | $ | 1,125,859 | | | $ | 1,099,280 | | | $ | 1,084,080 | | | $ | 1,064,588 | | | $ | 1,048,428 | |
| Pipeline and Storage | | | 674,175 | | | | 680,574 | | | | 696,487 | | | | 705,927 | | | | 487,793 | | | | 826,528 | | | | 681,940 | | | | 674,175 | | | | 680,574 | | | | 696,487 | |
| Exploration and Production | | | 1,002,265 | | | | 974,806 | | | | 923,730 | | | | 925,833 | | | | 1,072,200 | | |
| Exploration and Production(2) | | | | 1,095,960 | | | | 982,698 | | | | 1,002,265 | | | | 974,806 | | | | 923,730 | |
| Energy Marketing | | | 59 | | | | 97 | | | | 80 | | | | 171 | | | | 125 | | | | 98 | | | | 102 | | | | 59 | | | | 97 | | | | 80 | |
| Timber | | | 90,939 | | | | 94,826 | | | | 82,838 | | | | 87,600 | | | | 110,624 | | | | 86,392 | | | | 89,902 | | | | 90,939 | | | | 94,826 | | | | 82,838 | |
| All Other | | | 17,394 | | | | 18,098 | | | | 21,172 | | | | 22,042 | | | | 6,797 | | | | 11,946 | | | | 16,735 | | | | 17,394 | | | | 18,098 | | | | 21,172 | |
| Corporate(3) | | | 8,814 | | | | 6,311 | | | | 234,029 | | | | 221,082 | | | | 207,191 | | | | 7,317 | | | | 7,748 | | | | 8,814 | | | | 6,311 | | | | 234,029 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total Net Plant | | $ | 2,877,726 | | | $ | 2,839,300 | | | $ | 3,006,764 | | | $ | 2,991,048 | | | $ | 2,844,745 | | | $ | 3,154,100 | | | $ | 2,878,405 | | | $ | 2,877,726 | | | $ | 2,839,300 | | | $ | 3,006,764 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 3,734,331 | | | $ | 3,725,282 | | | $ | 3,717,603 | | | $ | 3,725,414 | | | $ | 3,429,163 | | | $ | 4,130,187 | | | $ | 3,888,412 | | | $ | 3,763,748 | | | $ | 3,749,753 | | | $ | 3,738,103 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Capitalization | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Comprehensive Shareholders’ Equity | | $ | 1,443,562 | | | $ | 1,229,583 | | | $ | 1,253,701 | | | $ | 1,137,390 | | | $ | 1,006,858 | | | $ | 1,603,599 | | | $ | 1,630,119 | | | $ | 1,443,562 | | | $ | 1,229,583 | | | $ | 1,253,701 | |
| Long-Term Debt, Net of Current Portion | | | 1,095,675 | | | | 1,119,012 | | | | 1,133,317 | | | | 1,147,779 | | | | 1,145,341 | | | | 999,000 | | | | 799,000 | | | | 1,095,675 | | | | 1,119,012 | | | | 1,133,317 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total Capitalization | | $ | 2,539,237 | | | $ | 2,348,595 | | | $ | 2,387,018 | | | $ | 2,285,169 | | | $ | 2,152,199 | | | $ | 2,602,599 | | | $ | 2,429,119 | | | $ | 2,539,237 | | | $ | 2,348,595 | | | $ | 2,387,018 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (1) | | Certain prior year amounts have been reclassified to conform with current year presentation.Includes discontinued operations. |
| |
| (2) | | Includes net plant of SECI discontinued operations as follows: $0 for 2008 and cumulative effect of changes in accounting.2007, $88,023 for 2006, $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, $219,199 for 2003, and $207,191 for 2002.2004. |
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| |
| Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
OVERVIEW
The Company is a diversified energy company consisting ofand reports financial results for five reportable business segments. Refer to Item I,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;
5. Contractual Obligations; and
| | |
| 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; |
|
| 5. | Contractual Obligations; and |
|
| | 6. | Other Matters, including: a.) 2006(a) 2008 and 20072009 funding tofor the Company’s defined benefit retirement planpension and other post-retirement benefit plan, b.)benefits, (b) realizability of deferred tax assets, c.)(c) disclosures and tables concerning market risk sensitive instruments, d.)(d) rate and regulatory matters in the Company’s New York, Pennsylvania and FERC regulated jurisdictions, e.)(e) environmental matters, and f.)(f) new accounting pronouncements. |
The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report.
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The event that had the most significant earnings impact in 2006, and the main reasonOverall, 2008 was a strong year for the significant earnings decrease over 2005, wasCompany. Income from continuing operations in 2008 benefited primarily from higher crude oil and natural gas prices in the Exploration and Production segment recording after-tax impairment charges totaling $68.6combined with an overall increase in natural gas production, primarily in the Appalachian region. These factors led to a $67.1 million relatedincrease 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 Canadiansale 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 gas assets during 2006 under the full cost method of accounting, which is discussed below under Critical Accounting Estimates. In addition,British Columbia in Canada. Combining both income from continuing operations and discontinued operations, the Company’s earningsnet income available for 2006 ascommon stock decreased $68.7 million in 2008 compared to 2005 are impacted by the Company’s 2005 sale of its entire 85.16% interest in U.E., a district heating and electric generation business in the Czech Republic. This sale resulted in a $25.8 million gain in 2005, net of tax. As a result of the decision to sell its majority interest in U.E., the Company began presenting the Czech Republic operations as discontinued operations in June 2005. With this change in presentation, the Company discontinued all reporting for an International segment. Any remaining international activity has been included in corporate operations for all periods presented below.prior year. The Company’s earnings are discussed further in the Results of Operations section that follows.
From a capital resources and liquidity perspective, theThe Company spent $294.2$414.5 million on capital expenditures during 2006,2008, with approximately 71%46 percent being spent in the Exploration and Production segment and 40 percent being spent in the Pipeline and Storage segment. This is in line withManagement continues to believe that these segments provide the best earnings growth opportunities for shareholders. In the Exploration and Production segment, the Company’s expectations.principal focus continues to be the development of its nearly one million acres in the Appalachian region along with continued exploration and development in the Gulf and West Coast regions. In November 2006, the Company announced that it had selected EOG Resources, Inc. (EOG) to jointly explore approximately 770,000 acresPipeline and Storage segment, the majority of the Company’s mineral holdings and 130,000 acresexpenditures were for construction costs of EOG’s mineral holdings in Pennsylvania and New York. EOG will be the operator and the primary exploration targets are the Devonian black shales, which have similar characteristics to the prolific Barnett Shale that is actively producing natural gas in the Fort Worth Basin. Exploratory drilling is expected to begin in 2007; however, the Company does not share in the initial exploratory costs and no capital expenditures have been forecasted for 2007 related to this joint venture.* Earliest production estimates have production starting no sooner than 2008.*
The Company is still pursuing its Empire Connector project to expand its natural gas pipeline operations. In July 2006, Empire revised the planned in-service date for the Empire Connector project. The Empire Connector is anticipated to extend beyond November 2007, as originally reported. The new targetedbe ready to commence service in December 2008 on or before the in-service date is November 2008, or sooner if feasible.* On July 20, 2006, FERC issued a Preliminary Determination regardingof the rate and non-environmental aspects of Empire’s application for FERC approval. Empire then made a compliance filing on September 18, 2006 regarding certain non-environmental issues, whichMillennium Pipeline. The Company’s capital expenditure program is discussed further in the Capital Resources and Liquidity section that follows. On October 13, 2006, FERC subsequently issued a final environmental impact statement
Despite the positives mentioned above, the economy of the United States has become constrained by significant volatility and turmoil 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 Empire Connector project andpart of lenders to extend credit to businesses. In the other related downstream projects, indicating that FERC hascurrent period these events have not identified any environmental reasons why those projects could not be built. There are no other significant changeshad a material impact on the Company, although further disruption in the statusmarkets and tightening of credit availability could negatively impact future periods. At September 30, 2008, the Company had a strong balance sheet and liquidity. The Company had no outstanding short-term notes payable to banks or commercial paper at that date. However, since that date, the Company has borrowed short-term funds under its credit lines and through the commercial paper market to fund working capital needs. The Company maintains 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 projectfinancial 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 continues to await final FERC approval to build and operate the project.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.
TheDuring 2006, the Company also began repurchasing outstanding shares of common stock during the quarter ended March 31, 2006 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizesauthorized the Company to repurchase up to an aggregate amount of 8eight million shares. ThroughThis 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, 2006,2008 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 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 its capital expenditure program, dividends, and operating expenses (including Retirement Plan and other post-retirement benefit funding) 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.
With the turmoil in the credit markets has come a significant decline in the stock markets. This has had repurchased 2,526,550 shares. These matters area 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 Capital Resources and Liquidity section that follows.
From a rate and regulatory matters perspective, management is concerned with declining usage per customer in the Utility segment. It has been one of the items leading to the filing of rate cases in New York and Pennsylvania. In Pennsylvania, the Company filed a rate case in June 2006 that included a revenue decoupling mechanism, or a conservation tracker. A settlement for this rate case was reached in October 2006, and while the revenue decoupling mechanism was withdrawn in order to achieve the settlement, the PaPUC instituted a generic proceeding to look at rate mechanisms such as revenue decoupling across the state. In New York, there is currently a proceeding going on to examine revenue decoupling mechanisms.
Lastly, on April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and motion for summary disposition against Supply Corporation with the FERC. The complainants alleged that Supply Corporation’s rates were unjust and unreasonable, and that Supply Corporation was permitted to retain more gas from shippers than it needed for fuel and loss. It also asked FERC to determine whether Supply Corporation had the authority to make sales of gas retained from shippers (which are referred to under “Results of Operations” as “unbundled pipeline sales”). On September 26, 2006, the active parties
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reached a settlement in principle. On November 17, 2006, Supply Corporation filed a motion asking FERC to approve an uncontested settlement of the proceeding. The proposed settlement would be implemented when and if FERC approves the settlement, but if approved would be effective as of December 1, 2006. This matter, including the primary elements of the settlement, is discussed more fully in the Rate and RegulatoryOther 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). UnevaluatedUnproved properties are excluded from the depletion calculation until theyproved reserves are evaluated. Once theyfound or it is determined that the unproved properties are evaluated,impaired. All costs associated with theserelated 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 depleted.amortized.
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 on acountry-by-country basis andeach quarter, determines a limit, or ceiling, toon 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 revenuescash 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 taxes.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 tofrom 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
27
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. Further decreasesThese impairment charges are included in the priceloss 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. Declines in commodity prices since that date have reduced the ceiling. Using more up to date pricing of $6 per Mcf for natural gas absentand $60 per barrel for crude oil, the additionceiling at September 30, 2008 would have exceeded the book value of new reserves, could result in future impairments.*the Company’s oil and gas properties by approximately $80 million.
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 tofrom proved reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.
Upon the adoption of SFAS 143 on October 1, 2002, the Company recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and capitalized such costs in property, plant and equipment (i.e. the full cost pool). Prior to the adoption of SFAS 143, 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 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, plugging and abandonment costs are already
29
included in capitalized costs and the units-of-production depletion calculation has been modified to exclude from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
Prior to the adoption of SFAS 143, in calculating the full cost ceiling, the Company reduced 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 adoption 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, 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, 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 options and futures contracts. The Company, in its Pipeline and Storage segment, usespreviously used an interest rate collar to limit interest rate fluctuations on certain variable rate debt. In accordance with the provisions of SFAS 133, the Company accountsaccounted for these instruments as effective cash flow hedges or fair value hedges. As such, gainsIn 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. As discussed below, the Company was required to discontinue hedge accounting for a portion of its derivative financial instruments, resulting in a charge to earnings in 2005.
The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The fair valuevalues of the non exchange-traded derivative financial instruments are based on valuations determined by the counterparties. The Company used a model to substantiate the values reported by the counterparties. At September 30, 2008, the Company established a credit reserve of $0.6 million 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. 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 return on plan assets, the rate of compensation increase and, for other post-retirement benefits, the expected
30
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 used byis then determined based on the Company is equalspot interest rate that results in the same present value when applied to the Moody’s Aa Long-Term Corporate Bond index, rounded to the nearest 25 basis points. The duration of the securities underlying that index (approximately 13 years) reasonably matches the
28
expected timing ofsame anticipated future benefit payments (approximately 12 years).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 represented 96%97% and 97%93%, respectively, 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, 20062008 and September 30, 2005.2007.
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 benefit plansbenefits and could impact the Company’s equity. For example, the discount rate used to determine benefit obligations was changed from 5.0% in 2005 to 6.25% in 2006.2007 to 6.75% in 2008. The change in the discount rate from 2007 to 2008 reduced the pension planRetirement Plan projected benefit obligation by $113.1$38.6 million and the accumulated post-retirement benefit obligation by $77.5$26.3 million. As a result of the discount rate change, the Company no longer had to record a minimum pension liability adjustment at September 30, 2006, resulting in an increase to other comprehensive income of $107.8 million, as shown in the Consolidated Statement of Comprehensive Income. 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 obligationsobligation and the accumulated post-retirement benefit obligation for the Post-Retirement Plan.obligation. For 2006,2008, actual versus expected return on plan assets resulted in an increasea decrease to the funded status of the Retirement Plan ($94.2 million) and the Post-Retirement Plan of $18.7 millionVEBA trusts and $12.5 million, respectively.401(h) accounts ($77.2 million). The actual versus expected benefit payments for 20062008 caused a decreasean increase of $1.0 million and $0.3$0.1 million to the projected benefit obligation and a decrease of $3.6 million to the accumulated post-retirement benefit obligation, respectively. In calculating the projected benefit obligation for the Retirement Plan and the accumulated post-retirement obligation, for the Post-Retirement Plan, the actuary takes into account the average remaining service life of active participants. The average remaining service life of active participants inis 11 years for the Retirement Plan is 10 years. The average remaining service life of active participants in the Post-Retirement Plan is 9 years.and 13 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, and to Item 8 at Note G — Retirement Plan and Other Post Retirement Benefits.
31
RESULTS OF OPERATIONS
EARNINGS
20062008 Compared with 20052007
The Company’s earnings were $138.1$268.7 million in 20062008 compared with earnings of $189.5$337.5 million in 2005.2007. As previously discussed, the Company presented its Czech RepublicCanadian operations as discontinued operations in the Exploration and Production segment (in conjunction with the sale of U.E.SECI) as discontinued operations. The Company’s earnings from continuing operations were $138.1$268.7 million in 20062008 compared with $153.5$201.7 million in 2005.2007. The Company’s earnings from discontinued operations were zero in 2006 compared with $36.0$135.8 million in 2005.2007. The decreaseincrease in earnings from continuing operations of $15.4 million is primarily the result of lowerhigher earnings in the Exploration and Production and PipelineUtility segments and Storage segments offset somewhat by higher earnings in the Utility segment, Energy Marketing segment, Timber segment, and All Other category, and aslightly offset by lower lossearnings in the Corporate category and the Timber, Pipeline and Storage, and Energy Marketing segments, as shown in the table below. The decrease in earnings from discontinued operations reflects the non-recurrence of the gain on the sale of U.E. recognized in 2005. In the discussion that follows, note that all amounts used in the earnings discussions are
29
after tax amounts. after-tax amounts, unless otherwise noted. Earnings from continuing operations and discontinued operations were impacted by several events in 20062008 and 2005,2007, including:
2008 Events
| | |
| 2006 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:
32
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 a regulatory mechanism calculation. |
| | |
| • | A $25.8 million gain on the sale of U.E., which was completed in July 2005. This amount is included in earnings from discontinued operations; |
|
| • | A $2.6 million gain in the Pipeline and Storage segment associated with a FERC approved sale of base gas; |
|
| • | A $3.9 million gain in the Pipeline and Storage segment associated with insurance proceeds received in prior years for which a contingency was resolved during 2005; |
|
| • | A $3.3 million loss related to certain derivative financial instruments that no longer qualified as effective hedges; |
|
| • | A $2.7 million impairment in the valueDistribution Corporation’s calculation 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 townsymmetrical sharing component of North East, Pennsylvania; and |
|
| • | A $1.8 million impairment of a gas-powered turbine in the All Other category that the Company had planned to use in the development of a co-generation plant. |
2005 Compared with 2004
The Company’s earnings were $189.5 million in 2005 compared with earnings of $166.6 million in 2004. As previously discussed, the Company has presented its Czech Republic operations as discontinued operations. The Company’s earnings from continuing operations were $153.5 million in 2005 compared with $154.3 million in 2004. The Company’s earnings from discontinued operations were $36.0 million in 2005 compared with $12.3 million in 2004. Earnings from continuing operations did not change significantly as higher earnings in the Pipeline and Storage segment were largely offset by lower earnings in the Utility and Exploration and Production segments and a higher loss in the All Other category. The increase in earnings from discontinued operations resulted from the gain on the sale of U.E. in 2005. Earnings from continuing operations and discontinued operations were impacted by the 2005 events discussed above and the following 2004 events:
2004 Events
| | |
| • | A $5.2 million reduction to deferred income tax expense resulting from a change in the statutory income tax rate in the Czech Republic. This amount is included in earnings from discontinued operations; |
|
| • | Settlement of a pension obligation which resulted in the recording of additional expense amounting to $6.4 million, allocated among the segments as follows: $2.2 million to the Utility segment ($1.2 million in the New York jurisdiction and $1.0 million in the Pennsylvania jurisdiction), $2.0 million to the Pipeline and Storage segment ($1.8 million to Supply Corporation and $0.2 million to Empire State Pipeline), $0.9 million to the Exploration and Production segment, $0.3 million to the Energy Marketing segment and $1.0 million to the Corporate and All Other categories; |
30
| | |
| • | AnYork’s gas adjustment to the 2003 sale of the Company’s Southeast Saskatchewan oil and gas properties in the Exploration and Production segment which increased 2004 earnings by $4.6 million; and |
|
| • | An adjustment to the Company’s 2003 sale of its timber properties in the Timber segment, which reduced 2004 earnings by $0.8 million.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 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Utility | | $ | 49,815 | | | $ | 39,197 | | | $ | 46,718 | | | $ | 61,472 | | | $ | 50,886 | | | $ | 49,815 | |
| Pipeline and Storage | | | 55,633 | | | | 60,454 | | | | 47,726 | | | | 54,148 | | | | 56,386 | | | | 55,633 | |
| Exploration and Production | | | 20,971 | | | | 50,659 | | | | 54,344 | | | | 146,612 | | | | 74,889 | | | | 67,494 | |
| Energy Marketing | | | 5,798 | | | | 5,077 | | | | 5,535 | | | | 5,889 | | | | 7,663 | | | | 5,798 | |
| Timber | | | 5,704 | | | | 5,032 | | | | 5,637 | | | | 107 | | | | 3,728 | | | | 5,704 | |
| | | | | | | | | | | | | | | |
| Total Reportable Segments | | | 137,921 | | | | 160,419 | | | | 159,960 | | |
| Total Reported Segments | | | | 268,228 | | | | 193,552 | | | | 184,444 | |
| All Other | | | 359 | | | | (2,616 | ) | | | 1,530 | | | | 5,672 | | | | 2,564 | | | | 359 | |
Corporate(1) | | | (189 | ) | | | (4,288 | ) | | | (7,225 | ) | | | (5,172 | ) | | | 5,559 | | | | (189 | ) |
| | | | | | | | | | | | | | | |
| Total Earnings from Continuing Operations | | $ | 138,091 | | | $ | 153,515 | | | $ | 154,265 | | | | 268,728 | | | | 201,675 | | | | 184,614 | |
| | | | | | | | | |
| Earnings from Discontinued Operations | | | — | | | | 35,973 | | | | 12,321 | | |
| Earnings (Loss) from Discontinued Operations | | | | — | | | | 135,780 | | | | (46,523 | ) |
| | | | | | | | | | | | | | | |
| Total Consolidated | | $ | 138,091 | | | $ | 189,488 | | | $ | 166,586 | | | $ | 268,728 | | | $ | 337,455 | | | $ | 138,091 | |
| | | | | | | | | | | | | | | |
| | |
(1) | | Includes earnings from the former International segment’s activity other than the activity from the Czech Republic operations included in Earnings from Discontinued Operations. |
UTILITY
Revenues
Utility Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Retail Revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 993,928 | | | $ | 868,292 | | | $ | 808,740 | | | $ | 876,677 | | | $ | 848,693 | | | $ | 993,928 | |
| Commercial | | | 166,779 | | | | 145,393 | | | | 137,092 | | | | 135,361 | | | | 136,863 | | | | 166,779 | |
| Industrial | | | 13,484 | | | | 13,998 | | | | 17,454 | | | | 7,419 | | | | 8,271 | | | | 13,484 | |
| | | | | | | | | | | | | | | |
| | | | 1,174,191 | | | | 1,027,683 | | | | 963,286 | | | | 1,019,457 | | | | 993,827 | | | | 1,174,191 | |
| | | | | | | | | | | | | | | |
| Off-System Sales | | | — | | | | — | | | | 106,841 | | | | 58,225 | | | | 9,751 | | | | — | |
| Transportation | | | 92,569 | | | | 83,669 | | | | 80,563 | | | | 113,901 | | | | 102,534 | | | | 92,569 | |
| Other | | | 14,003 | | | | 5,715 | | | | 1,951 | | | | 18,686 | | | | 14,612 | | | | 14,003 | |
| | | | | | | | | | | | | | | |
| | | $ | 1,280,763 | | | $ | 1,117,067 | | | $ | 1,152,641 | | | $ | 1,210,269 | | | $ | 1,120,724 | | | $ | 1,280,763 | |
| | | | | | | | | | | | | | | |
3133
Utility Throughput — million cubic feet (MMcf)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
| Retail Sales: | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 59,443 | | | | 66,903 | | | | 70,109 | | | | 57,463 | | | | 60,236 | | | | 59,443 | |
| Commercial | | | 10,681 | | | | 11,984 | | | | 12,752 | | | | 9,769 | | | | 10,713 | | | | 10,681 | |
| Industrial | | | 985 | | | | 1,387 | | | | 2,261 | | | | 552 | | | | 727 | | | | 985 | |
| | | | | | | | | | | | | | | |
| | | | 71,109 | | | | 80,274 | | | | 85,122 | | | | 67,784 | | | | 71,676 | | | | 71,109 | |
| | | | | | | | | | | | | | | |
| Off-System Sales | | | — | | | | — | | | | 16,839 | | | | 5,686 | | | | 1,355 | | | | — | |
| Transportation | | | 57,950 | | | | 59,770 | | | | 60,565 | | | | 64,267 | | | | 62,240 | | | | 57,950 | |
| | | | | | | | | | | | | | | |
| | | | 129,059 | | | | 140,044 | | | | 162,526 | | | | 137,737 | | | | 135,271 | | | | 129,059 | |
| | | | | | | | | | | | | | | |
Degree Days
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Percent (Warmer)
| | | | | | | | | Percent (Warmer)
| |
| | | | | | | | | Colder Than | | | | | | | | | Colder Than | |
Year Ended September 30 | | | | Normal | | Actual | | Normal | | Prior Year | | | | | Normal | | Actual | | Normal | | Prior Year | |
| |
| 2008: | | | | Buffalo | | | | 6,729 | | | | 6,277 | | | | (6.7 | )% | | | 0.1 | % |
| | | | | Erie | | | | 6,277 | | | | 5,779 | | | | (7.9 | )% | | | (3.8 | )% |
| 2007: | | | | Buffalo | | | | 6,692 | | | | 6,271 | | | | (6.3 | )% | | | 5.1 | % |
| | | | | Erie | | | | 6,243 | | | | 6,007 | | | | (3.8 | )% | | | 5.6 | % |
| 2006: | | | Buffalo | | | | 6,692 | | | | 5,968 | | | | (10.8 | )% | | | (9.4 | )% | | | Buffalo | | | | 6,692 | | | | 5,968 | | | | (10.8 | )% | | | (9.4 | )% |
| | | | Erie | | | | 6,243 | | | | 5,688 | | | | (8.9 | )% | | | (8.9 | )% | | | Erie | | | | 6,243 | | | | 5,688 | | | | (8.9 | )% | | | (8.9 | )% |
| 2005: | | | Buffalo | | | | 6,692 | | | | 6,587 | | | | (1.6 | )% | | | 0.2 | % | |
| | | | Erie | | | | 6,243 | | | | 6,247 | | | | 0.1 | % | | | 2.6 | % | |
| 2004: | | | Buffalo | | | | 6,729 | | | | 6,572 | | | | (2.3 | )% | | | (7.9 | )% | |
| | | | Erie | | | | 6,277 | | | | 6,086 | | | | (3.0 | )% | | | (10.1 | )% | |
20062008 Compared with 20052007
Operating revenues for the Utility segment increased $163.7$89.5 million in 20062008 compared with 2005.2007. This increase largely resulted from a $146.5$48.5 million increase in off-system sales revenue (see discussion below), a $25.6 million increase in retail gas sales revenues. Transportationrevenues, an $11.3 million increase in transportation revenues, and a $4.1 million increase in other revenues also increased by $8.9 million and $8.3 million, respectively.operating revenues.
The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs (gas(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.” Warmer weather, as shown in the table above, and greater conservationThis change was also affected by customers due to higher natural gas commodity prices, were the principal reasons for the decrease in retail sales volumes.
The increase in transportation revenues was primarily due to a $5.9 million increase in the New York jurisdiction’s calculation of the symmetrical sharing component of the gas adjustment rate. The symmetrical sharing component is a mechanism included in Distribution Corporation’s New York rate settlement that shares with customers 90% of the difference between actual revenues received from large volume customers and the level of revenues that were projected to be received during the rate year. Of the $5.9 million increase, $3.9 million was due to anout-of-period adjustment recorded in fiscal year 2006 when it was determined that certain credits that had been included in the calculation should have been removed during the implementation of a previous rate case. The adjustment related to fiscal years 2002 through 2005.
The impact of the August 2005 New York rate case settlement was to increase operating revenues by $19.1 million (of which $12.4 million was an increase to other operating revenues). This increase consisted of a base rate increase the implementation of a merchant function charge, the elimination of certain bill credits, and the elimination of the gross receipts tax surcharge. The settlement also allowed Distribution Corporation to continue 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 2005, Distribution Corporation utilized
32
$7.8 million of the cost mitigation reserve, which increased other operating revenues, to recover previous under-collections of pension and post-retirement expenses. The impact of that increase in other operating revenues was offset by an equal amount of operation and maintenance expense (thus there was no earnings impact). Distribution Corporation did not record any entries involving the cost mitigation reserve in 2006. Other operating revenues was also impacted by twoout-of-period regulatory adjustments recorded during 2005. The first adjustment related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the 2001 to 2003 time period. As a result of that settlement, the New York rate jurisdiction recorded additional earnings sharing expense (as an offset to other operating revenues) of $0.9 million. The second adjustment related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax. In preparing for the implementation of the settlement agreement in New York, the Company determined that it needed to adjust that regulatory liability by $3.1 million (of which $1.0 million was recorded as a reduction of other operating revenues and $2.1 million was recorded as additional interest expense) related to fiscal years 2004 and prior. These adjustments did not recur in 2006.
In the Pennsylvania jurisdiction the impact of the base rate increase, which became effective in mid-April 2005, was to increase(effective January 2007) that increased operating revenues by $7.5 million. This$4.0 million for 2008. The increase is included within both retail and transportation revenues in the table above.
2005 Compared with 2004
OperatingIn 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 Utility segment decreased $35.6 million in 2005 compared with 2004. This resulted primarily from the absenceimpact of off-system salesthis rate order has been to lower operating revenues of $106.8 million, offset by $1.4 million. It is expected that there will be an increase of $64.4 million in retail revenues. Effective September 22, 2004, Distribution Corporation stopped making off-system salesand 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, on November 17, 2006 the U.S. Court of Appeals vacated and remanded the FERC’s Order No. 2004 “Standardsregarding affiliate standards of Conductconduct, 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 Transmission Providers.” However, duethe 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 have beenare minimal and there was not a material impact to margins in 2005. The increase in retail revenues was primarily the result of the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues), colder weather in the Pennsylvania jurisdiction2008 and the impact of base rate increases in both New York and Pennsylvania. The recovery of higher gas costs resulted from a much higher cost of purchased gas. See further discussion of purchased gas below under the heading “Purchased Gas.” Lower retail sales volumes, due primarily to lower customer usage per account, partially offset the increase in retail revenues associated with the recovery of higher gas costs and the base rate increases. Also, retail industrial sales revenue declined due to fuel switching and production declines of certain large volume industrial customers as a result of a general economic downturn in the Utility segment’s service territory.2007.
The increase in other operating revenues of $3.8$4.1 million is largely related to amounts recorded pursuant to rate settlements withapproved 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,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 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 $12.07$11.23 per Mcf in 2006,2008, an increase of 31%12% from the average cost of $9.19$10.04 per Mcf in 2005.2007. The average cost of purchased gas in 20052007 was 26% higher17% lower than the average cost of $7.30$12.07 per Mcf in 2004.2006. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.
3335
Earnings
20062008 Compared with 20052007
The Utility segment’s earnings in 20062008 were $49.8$61.5 million, an increase of $10.6 million when compared with earnings of $39.2$50.9 million in 2005.2007.
In the New York jurisdiction, earnings increased by $9.2 million,$6.9 million. This was primarily due to the positivea $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 the rate case settlement in this jurisdiction that became effective August 2005 ($13.7 million). In addition, the increase in the New York jurisdiction’s calculation of the symmetrical sharing component of the gas adjustment rate, including theout-of-period adjustment discussed above, contributed $3.9 million to earnings. Twoout-of-period regulatory adjustments recorded during fiscal year 2005 that did not recur during 2006, as discussed above, also contributed an additional $2.6 million to earnings. The first adjustment, related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the fiscal 2001 through 2003 time period, increased earnings in fiscal 2006 by $0.6 million. The second adjustment, related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax, increased earnings in fiscal 2006 by $2.0 million. The increase in earningsthese items more than offset lower base rates due to the New York rate case settlement, the symmetrical sharing component of the gas adjustment rate,design change described above ($0.9 million), and the twoout-of-periodroutine regulatory adjustments recorded in 2005, was partially offsetthat reduced earnings by a decline in margin associated with lower weather-normalized usage by customers ($2.3 million), higher operation expenses ($2.5 million), higher interest expense ($2.7 million), and a higher effective income tax rate ($3.2 million). The higher effective income tax rate is due to positive tax adjustments recorded in 2005 that did not recur in 2006. The increase in operation expenses consisted primarily of higher pension expense offset by lower bad debt expense.$1.8 million.
In the Pennsylvania jurisdiction, earnings increased by $1.4$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). 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 of theassociated with a lower effective tax rate case settlement in this jurisdiction that became effective April 2005 ($4.91.1 million),. Higher intercompany and lower operation expenses ($1.8 million). The decrease in operation expenses consisted primarily of lower bad debt expense offset partially by higher pension expense. These increases to earnings were partially offset by the impact of warmer than normal weather in Pennsylvania ($3.0 million), lower weather-normalized usage by customer ($0.6 million), higherother interest expense ($0.8 million), andcoupled with a higher effective tax rate ($1.3 million).
The decrease in bad debt expense reflects the fact that in the fourth quarter of 2005, the New York and Pennsylvania jurisdictions increased the allowance for uncollectible accounts to reflect the increase in final billed account balances and the increased aging of outstanding active receivables heading into the heating season. A similar adjustment was not required in 2006.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, because itrespectively, as the weather was warmer than normal in the New York service territory. In 2005, the WNC did not have a significant impact on earnings.
2005 Compared with 2004
The Utility segment’s earnings in 2005 were $39.2 million, a decrease of $7.5 million when compared with earnings of $46.7 million in 2004. The major factors driving this decrease were lower weather-normalized usage per customer account in both the New York and Pennsylvania jurisdictions ($8.2 million) and an increase in bad debt expenses of $6.7 million. The increase in bad debt expenses is attributable to the increase in the allowance for uncollectible accounts to reflect the increase in final billed balances, as well as the increased age of outstanding receivables heading into the heating season. These negative factors were partially offset by the impact of base rate increases in both New York and Pennsylvania ($3.9 million) and the recording of accrued interest on a pension related asset in accordance with the New York rate case settlement agreement ($2.4 million), as well as the impact of colder than normal weather in Pennsylvania ($1.0 million). The earnings impact of the twoout-of-period regulatory adjustments discussed above was largely offset by lower interest expense on borrowings due to lower debt balances.normal.
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In 2005, the WNC did not have a significant impact on earnings. For 2004, the WNC preserved earnings of approximately $1.0 million because it was warmer than normal in the New York service territory.
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Firm Transportation | | $ | 118,551 | | | $ | 117,146 | | | $ | 120,443 | | | $ | 122,321 | | | $ | 118,771 | | | $ | 118,551 | |
| Interruptible Transportation | | | 4,858 | | | | 4,413 | | | | 3,084 | | | | 4,330 | | | | 4,161 | | | | 4,858 | |
| | | | | | | | | | | | | | | |
| | | | 123,409 | | | | 121,559 | | | | 123,527 | | | | 126,651 | | | | 122,932 | | | | 123,409 | |
| | | | | | | | | | | | | | | |
| Firm Storage Service | | | 66,718 | | | | 65,320 | | | | 63,962 | | | | 67,020 | | | | 66,966 | | | | 66,718 | |
| Interruptible Storage Service | | | 39 | | | | 267 | | | | 20 | | | | 14 | | | | 169 | | | | 39 | |
| | | | | | | | | | | | | | | |
| | | | 66,757 | | | | 65,587 | | | | 63,982 | | | | 67,034 | | | | 67,135 | | | | 66,757 | |
| | | | | | | | | |
| Other | | | 24,186 | | | | 28,713 | | | | 22,198 | | | | 22,871 | | | | 21,899 | | | | 24,186 | |
| | | | | | | | | | | | | | | |
| | | $ | 214,352 | | | $ | 215,859 | | | $ | 209,707 | | | $ | 216,556 | | | $ | 211,966 | | | $ | 214,352 | |
| | | | | | | | | | | | | | | |
Pipeline and Storage Throughput — (MMcf)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
| Firm Transportation | | | 363,379 | | | | 357,585 | | | | 338,991 | | | | 353,173 | | | | 351,113 | | | | 363,379 | |
| Interruptible Transportation | | | 11,609 | | | | 14,794 | | | | 12,692 | | | | 5,197 | | | | 4,975 | | | | 11,609 | |
| | | | | | | | | | | | | | | |
| | | | 374,988 | | | | 372,379 | | | | 351,683 | | | | 358,370 | | | | 356,088 | | | | 374,988 | |
| | | | | | | | | | | | | | | |
20062008 Compared with 20052007
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 & 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 was due to higher gas prices in the current year.
2007 Compared with 2006
Operating revenues for the Pipeline and Storage segment decreased $1.5$2.4 million in 20062007 as compared with 2005. This decrease consisted of2006, which was due mostly to a $4.5 million decrease in other revenues offset by a $1.8 million increase in firm and interruptible transportation revenues and a $1.2 million increase in firm and interruptible storage service revenues.($2.3 million). The decrease in other revenues is primarily due to a $2.6$4.2 million decrease in revenues from unbundled pipeline sales,efficiency gas revenues. This decrease was due to lower naturalthe Company’s recent settlement with the FERC, which decreased efficiency gas prices, as well asretainage allowances. Offsetting this decrease, there was a $0.7$1.4 million decrease in cashout revenues. Cashout revenues are completely offset by purchased gas expense. The increase in firm and interruptible transportationother revenues is dueattributable to additional contracts with customers and the renewal of contracts at higher rates, both oflease termination fee adjustment in 2006 (an intercompany transaction) for the Company’s former headquarters, which reflect the increased demand for transportation services due to market conditions resulting from the effects of hurricane damage to production and pipeline infrastructuredid not recur in the Gulf of Mexico during the fall of 2005.2007. While Supply Corporation’s transportation volumes increaseddecreased during the year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variablestraight-fixed variable rate design. The increase in storage revenues reflects the renewal of storage contracts at higher rates.
2005 Compared with 2004
Operating revenues for the Pipeline and Storage segment increased $6.2 million in 2005 as compared with 2004. This increase is primarily attributable to higher revenues from unbundled pipeline sales of $5.5 million included in other revenues in the table above, due to higher natural gas prices. Higher cashout revenues of $1.1 million, reported as part of other revenues in the table above, also contributed to the increase. Cashout revenues are completely offset by purchased gas expense. In addition, interruptible transportation revenues increased by $1.3 million, primarily due to an increase in Supply Corporation’s gathering revenues, and firm
35
storage revenues increased $1.4 million, primarily due to higher rate agreements contracted with Supply Corporation customers. Offsetting these increases, the decrease in firm transportation revenues of $3.3 million reflects the cancellation of contracts with Supply Corporation by certain large usage non-affiliated customers ($2.6 million) and the Utility segment’s cancellation of a portion of its firm transportation with Supply Corporation in April 2005 ($0.6 million). In addition, firm transportation revenues decreased by $1.0 million because Supply Corporation no longer charges customers a surcharge for its membership to the Gas Research Institute (GRI). The decrease in revenues resulting from cancellation of the GRI surcharge was completely offset by lower operation expense. While Supply Corporation’s transportation volumes increased during the year, volume fluctuations generally do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable rate design. Offsetting the decreases in Supply Corporation’s firm transportation revenues was a $1.0 million increase in Empire’s firm transportation revenues, primarily due to an increase in transportation volumes.
Earnings
20062008 Compared with 20052007
The Pipeline and Storage segment’s earnings in 20062008 were $55.6$54.1 million, a decrease of $4.9$2.2 million when compared with earnings of $60.5$56.4 million in 2005.2007. The main factors contributing to this decrease reflectswere higher operation and maintenance expenses ($6.1 million), primarily caused by the non-recurrence in 2008 of two events, a $2.6reversal 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 gain on a FERC approved sale of base gas in 2005 and a $3.9 million gainpositive earnings impact during 2007 associated with insurance proceeds received in prior yearsthe discontinuance of hedge accounting for which a contingency was resolved in 2005. Both of these items were recorded in Other Income. It also reflectsEmpire’s interest rate collar that did not recur during 2008, and the earnings impact associated with lower revenues from unbundled pipeline salesPipeline and Storage segment experienced higher interest costs ($1.7 million) and higher operation expenses ($0.61.5 million). These earnings decreases were offset by the positive earnings impact ofassociated with higher transportation and storage revenues ($2.02.4 million), lower depreciation due toan increase in the non-recurrence of a write-down of the Company’s former corporate office in 2005allowance for funds used during construction ($0.94.2 million), and the earnings benefitimpact associated with a lower effective tax ratehigher efficiency gas revenues ($1.70.5 million).
20052007 Compared with 20042006
The Pipeline and Storage segment’s earnings in 20052007 were $60.5$56.4 million, an increase of $12.8$0.8 million when compared with earnings of $47.7$55.6 million in 2004. Contributing2006. The main factor contributing to this increase was the reversal of a reserve for preliminary survey costs ($4.8 million) related to the increaseEmpire 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 gain of $3.9$2.5 million increase in earnings associated with the insurance proceeds receiveddecrease in prior years fordepreciation expense as a result of the most recent settlement with the FERC, which reduced depreciation rates. There was also a contingency was resolved during 2005. The other main factors contributing to the increase were higher revenues from unbundled pipeline sales ($3.6 million), lower interest expense ($2.4 million), $2.0$1.9 million of expense that did not recur in 2005positive earnings impact associated with the settlementdiscontinuance of a pension obligation recognized in 2004, as well as a $2.6hedge accounting for Empire’s interest rate collar. On December 8, 2006, Empire repaid $22.8 million gain onof secured debt. The interest costs of this secured debt were hedged by the FERC approved sale of base gas in March, 2005. An increase ininterest rate collar. Since the reserve for preliminary project costshedged transaction was settled and there will be no future cash flows associated with the Empire Connector projectsecured 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 ($1.83.2 million) partially offset these increases., 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 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
| Gas (after Hedging) | | $ | 184,268 | | | $ | 181,713 | | | $ | 167,127 | |
| Oil (after Hedging) | | | 148,293 | | | | 107,801 | | | | 119,564 | |
| Gas Processing Plant | | | 42,252 | | | | 36,350 | | | | 28,614 | |
| Other | | | 3,771 | | | | (2,733 | ) | | | 1,815 | |
| Intrasegment Elimination(1) | | | (31,704 | ) | | | (29,706 | ) | | | (23,422 | ) |
| | | | | | | | | | | | | |
| | | $ | 346,880 | | | $ | 293,425 | | | $ | 293,698 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (Thousands) | |
| |
| Gas (after Hedging) from Continuing Operations | | $ | 202,153 | | | $ | 143,785 | | | $ | 126,969 | |
| Oil (after Hedging) from Continuing Operations | | | 250,965 | | | | 167,627 | | | | 134,307 | |
| Gas Processing Plant from Continuing Operations | | | 49,090 | | | | 37,528 | | | | 42,252 | |
| Other from Continuing Operations | | | (944 | ) | | | 1,147 | | | | 3,072 | |
| Intrasegment Elimination from Continuing Operations(1) | | | (34,504 | ) | | | (26,050 | ) | | | (31,704 | ) |
| | | | | | | | | | | | | |
| Operating Revenues from Continuing Operations | | $ | 466,760 | | | $ | 324,037 | | | $ | 274,896 | |
| | | | | | | | | | | | | |
| Operating Revenues from Canada — Discontinued Operations | | $ | — | | | $ | 50,495 | | | $ | 71,984 | |
| | | | | | | | | | | | | |
36
| | |
| (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. |
38
Production Volumes
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
Gas Production(MMcf) | | | | | | | | | | | | | | | | | | | | | | | | |
| Gulf Coast | | | 9,110 | | | | 12,468 | | | | 17,596 | | | | 11,033 | | | | 10,356 | | | | 9,110 | |
| West Coast | | | 3,880 | | | | 4,052 | | | | 4,057 | | | | 4,039 | | | | 3,929 | | | | 3,880 | |
| Appalachia | | | 5,108 | | | | 4,650 | | | | 5,132 | | | | 7,269 | | | | 5,555 | | | | 5,108 | |
| Canada | | | 7,673 | | | | 8,009 | | | | 6,228 | | |
| | | | | | | | | | | | | | | |
| Total Production from Continuing Operations | | | | 22,341 | | | | 19,840 | | | | 18,098 | |
| Canada — Discontinued Operations | | | | — | | | | 6,426 | | | | 7,673 | |
| | | | 25,771 | | | | 29,179 | | | | 33,013 | | | | | | | | |
| Total Production | | | | 22,341 | | | | 26,266 | | | | 25,771 | |
| | | | | | | | | | | | | | | |
Oil Production(Mbbl) | | | | | | | | | | | | | | | | | | | | | | | | |
| Gulf Coast | | | 685 | | | | 989 | | | | 1,534 | | | | 505 | | | | 717 | | | | 685 | |
| West Coast | | | 2,582 | | | | 2,544 | | | | 2,650 | | | | 2,460 | | | | 2,403 | | | | 2,582 | |
| Appalachia | | | 69 | | | | 36 | | | | 20 | | | | 105 | | | | 124 | | | | 69 | |
| Canada | | | 272 | | | | 300 | | | | 324 | | |
| | | | | | | | | | | | | | | |
| Total Production from Continuing Operations | | | | 3,070 | | | | 3,244 | | | | 3,336 | |
| Canada — Discontinued Operations | | | | — | | | | 206 | | | | 272 | |
| | | | 3,608 | | | | 3,869 | | | | 4,528 | | | | | | | | |
| Total Production | | | | 3,070 | | | | 3,450 | | | | 3,608 | |
| | | | | | | | | | | | | | | |
Average Prices
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
Average Gas Price/Mcf | | | | | | | | | | | | | | | | | | | | | | | | |
| Gulf Coast | | $ | 8.01 | | | $ | 7.05 | | | $ | 5.61 | | | $ | 10.03 | | | $ | 6.58 | | | $ | 8.01 | |
| West Coast | | $ | 7.93 | | | $ | 6.85 | | | $ | 5.54 | | | $ | 8.71 | | | $ | 6.54 | | | $ | 7.93 | |
| Appalachia | | $ | 9.53 | | | $ | 7.60 | | | $ | 5.91 | | | $ | 9.73 | | | $ | 7.48 | | | $ | 9.53 | |
| Canada | | $ | 7.14 | | | $ | 6.15 | | | $ | 4.87 | | |
| Weighted Average | | $ | 8.04 | | | $ | 6.86 | | | $ | 5.51 | | |
| Weighted Average After Hedging(1) | | $ | 7.15 | | | $ | 6.23 | | | $ | 5.06 | | |
| Weighted Average for Continuing Operations | | | $ | 9.70 | | | $ | 6.82 | | | $ | 8.42 | |
| Weighted Average After Hedging for Continuing Operations(1) | | | $ | 9.05 | | | $ | 7.25 | | | $ | 7.02 | |
| Canada — Discontinued Operations | | | $ | — | | | $ | 6.09 | | | $ | 7.14 | |
Average Oil Price/Barrel (bbl) | | | | | | | | | | | | | | | | | | | | | | | | |
| Gulf Coast | | $ | 64.10 | | | $ | 49.78 | | | $ | 35.31 | | | $ | 107.27 | | | $ | 63.04 | | | $ | 64.10 | |
| West Coast(2) | | $ | 56.80 | | | $ | 42.91 | | | $ | 31.89 | | | $ | 98.17 | | | $ | 56.86 | | | $ | 56.80 | |
| Appalachia | | $ | 65.28 | | | $ | 48.28 | | | $ | 31.30 | | | $ | 97.40 | | | $ | 62.26 | | | $ | 65.28 | |
| Canada | | $ | 51.40 | | | $ | 42.97 | | | $ | 30.94 | | |
| Weighted Average | | $ | 57.94 | | | $ | 44.72 | | | $ | 32.98 | | |
| Weighted Average After Hedging(1) | | $ | 41.10 | | | $ | 27.86 | | | $ | 26.40 | | |
| Weighted Average for Continuing Operations | | | $ | 99.64 | | | $ | 58.43 | | | $ | 58.47 | |
| Weighted Average After Hedging for Continuing Operations(1) | | | $ | 81.75 | | | $ | 51.68 | | | $ | 40.26 | |
| Canada — Discontinued Operations | | | $ | — | | | $ | 50.06 | | | $ | 51.40 | |
| | |
| (1) | | Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note F — Financial Instruments in Item 8 of this report. |
| |
| (2) | | Includes low gravity oil which generally sells for a lower price. |
20062008 Compared with 20052007
Operating revenues from continuing operations for the Exploration and Production segment increased $53.5$142.7 million in 20062008 as compared with 2005.2007. Oil production revenue after hedging from continuing operations increased $40.5$83.3 million due primarily to highera $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
3739
after hedging from continuing operations increased $58.4 million due to a $1.80 per Mcf increase in weighted average prices after hedging ($13.24 per barrel). Thisand a 2,501 MMcf increase was offset slightly by a decrease in production (261,000 barrels). Gas production revenue after hedging increased $2.6 million. Increases in the weighted average price of gas after hedging ($0.92 per Mcf) more than offset an overall decreaseproduction. The increase in gas production (3,408 MMcf). The decrease in gas productionfrom continuing operations occurred primarily in the Gulf Coast (a 3,358 MMcf decline)Appalachian region (1,714 MMcf), which is partly attributable to last fall’s hurricane damage and partly attributable to the expected decline rates for the Company’s productionconsistent with increased drilling activity in the region. Other revenues increased $6.5 million largelyThe 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 the non-recurrencerepair work on third party pipelines and onshore processing facilities. The majority of a $5.1 millionmark-to-market adjustment, recorded in 2005, for losses on certain derivative financial instruments that no longer qualified as effective hedges duethis production is anticipated to the anticipated delays in oil and gas production volumes causedreturn by Hurricane Rita.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.
20052007 Compared with 20042006
Operating revenues from continuing operations for the Exploration and Production segment decreased $0.3increased $49.1 million in 20052007 as compared with 2004.2006. Oil production revenue after hedging decreased $11.8increased $33.3 million due primarily to a 659 Mbbl declinean $11.42 per barrel increase in production offset partly by higher weighted average prices after hedging, ($1.46 per barrel). Most of thewhich more than offset a slight decrease in oil production occurred in the Gulf Coast Region (a 545 Mbbl decrease).of 92,000 barrels. Gas production revenue after hedging increased $14.6 million. Increases$16.8 million in the weighted average price of gas after hedging ($1.17 per Mcf) more than offset an overall decrease2007 as compared with 2006. An increase in gas production (3,834 MMcf). Most of 1,742 MMcf and an increase in weighted average prices after hedging of $0.23 per Mcf both contributed to the decreaseincrease. The increase in gas production occurred primarily in the Gulf Coast (a 5,128 MMcf decline)region (1,246 MMcf). The decreases in Gulf Coast oil and gasDuring the quarter ended December 31, 2005, Seneca experienced significant production are consistent withdelays due largely to the expected decline ratesimpact of hurricane damage to pipeline infrastructure in the region. This decreaseGulf 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 Gulf Coast gas production was partially offset by a 1,781 MMcf increase in Canadian gas production. The increase in Canadian gas production is attributable to the Sukunka 60-E well, in which the Company has a 20% working interest. Other revenues decreased $4.5 million largelythis segment’s Appalachian region (447 MMcf), primarily due to a $5.1 millionmark-to-market adjustment for losses on certain derivative financial instruments that no longer qualifiedincreased drilling in this region during 2007, as effective hedges due to the anticipated delayshighlighted in oilItem 2 under “Exploration and gas production volumes caused by Hurricane Rita. These volumes were originally forecast to be produced in the first quarter of 2006.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
20062008 Compared with 20052007
The Exploration and Production segment’s earnings in 2006from continuing operations for 2008 were $21.0$146.6 million, a decreasean increase of $29.7$71.7 million when compared with earnings from continuing operations of $50.7$74.9 million in 2005. The decrease is primarily the result of the impairment charges of $68.6for 2007. Higher crude oil prices, higher natural gas prices and higher natural gas production increased earnings by $60.0 million, on this segment’s Canadian$26.2 million and $11.8 million, respectively, while lower crude oil and gas producing properties. Also, lower oil and gas production decreased earnings by $18.5$5.8 million. Further contributing to the decrease were higherHigher lease operating expensescosts ($3.211.9 million), higher depletion expense ($9.1 million), higher income tax expense ($1.1 million) and higher general and administrative and other operating costsexpenses ($2.06.2 million) also negatively impacted earnings. Lower interest expense and higher depletion expense ($2.5 million).interest income of $6.6 million and $0.7 million, respectively, partially offset these decreases to earnings. The increase in lease operating expenses was primarilycosts resulted from thestart-up of production at the High Island 24L field in the West Coast region due toOctober 2007, higher steaming costs associated with heavy crude oil production in the California, Midway-Sunset and North Lost Hills fields. The higher steaming costs are due to an increase in the price for natural gas purchasedcosts associated with a higher number of producing properties in the field and used in the steaming operations, primarily in the second quarter of fiscal 2006, compared to the second quarter of fiscal 2005. Beginning in April 2006, a scrubber facility in the Midway-Sunset field was in full operation and is burning waste gas rather than purchased gas to generate the steam for its thermal recovery project. It is anticipated that the scrubber facility will reduce steaming costs in the future.*Appalachia. The increase in depletion expense was mainly due tocaused by higher findingproduction and developmentan 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 the Canadian region, coupled with a 10.5 Bcfe downward revisionexcess of the proved reserve estimate (resulting in an increase to the per unit depletion rate) in this region in 2006. Partially offsetting these decreases, higher oil and gas prices, as discussed above, contributed $46.5 million to earnings. Also, the non-recurrence of the 2005mark-to-market adjustment discussed under Revenues above, contributed $3.3 million to earnings and strong cash flow provided higher interest income ($2.6 million). In the second quarter of 2006, a $5.1 million benefit to earningspreviously accrued amounts.
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was realized for an adjustment to a deferred income tax balance. Under GAAP, a company may recognize the benefit of certain expected future income tax deductions as a deferred tax asset only if it anticipates sufficient future taxable income to utilize those deductions. As a result of the rise in commodity prices, the Company increased its forecast of future taxable income in the Exploration and Production segment’s Canadian division and, as a result, recorded a deferred tax asset for certain drilling costs that it now expects to deduct on future income tax returns. In the third quarter of 2006, a $6.1 million benefit to earnings related to income taxes was recognized. The Company reversed a valuation allowance ($2.9 million) associated with the capital loss carryforward that resulted from the 2003 sale of certain of Seneca’s oil properties, and also recognized a tax benefit of $3.2 million related to the favorable resolution of certain open tax issues.
20052007 Compared with 20042006
The Exploration and Production segment’s earnings in 2005from continuing operations for 2007 were $50.7$74.9 million, a decreasean increase of $3.6$7.4 million when compared with earnings from continuing operations of $54.3$67.5 million in 2004. Lowerfor 2006. Higher crude oil andprices, 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 discussed above,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 $23.9 million. Also, in 2004, the Company recorded an adjustment to the sale of its Southeast Saskatchewan properties that increased 2004 earnings by $4.6 million. In 2005, the Company recorded amark-to-market adjustment, as discussed above under “Revenues”, that decreased 2005 earnings by $3.3 million. Higher lease operating and depletion expenses also decreased 2005 earnings by $2.1$2.4 million and $0.6 million, respectively. The increase in lease operating expenses resulted mainly from increased Canadian production and higher steaming costs associated with heavy crude oil production in the West Coast Region. Depletion expense increased despite a drop in production mostly due to an increase in the per unit depletion rate, which was largely the result of the higher finding and development costs experienced by Seneca in 2005. All of these factors, which collectively resulted in a $34.5 million decrease in 2005 earnings,Earnings were partially offsetalso negatively impacted by higher oil and gas prices, as discussed above, that contributed $25.9 million to earnings. Also, 2005 earnings benefited from higher interest income ($1.8 million) and lower interesttax expense ($1.26.3 million). The fluctuations in interest income and interest expense reflect the fact that the Exploration and Production segment has been operating solely within its own cash flow from operations. Short-term borrowings have been eliminated and excess cash has been invested, resulting in higher interest income. This excess cash will be used to fund operations and future capital expenditures.* Lower general and administrative expenses, largely due to lower legal costs, also increased 2005 earnings by $1.0 million.
ENERGY MARKETING
Revenues
Energy Marketing Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Natural Gas (after Hedging) | | $ | 496,769 | | | $ | 329,560 | | | $ | 283,747 | | | $ | 551,243 | | | $ | 413,405 | | | $ | 496,769 | |
| Other | | | 300 | | | | 154 | | | | 602 | | | | (11 | ) | | | 207 | | | | 300 | |
| | | | | | | | | | | | | | | |
| | | $ | 497,069 | | | $ | 329,714 | | | $ | 284,349 | | | $ | 551,232 | | | $ | 413,612 | | | $ | 497,069 | |
| | | | | | | | | | | | | | | |
Energy Marketing Volumes
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | |
| |
| Natural Gas — (MMcf) | | | 45,270 | | | | 40,683 | | | | 41,651 | |
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2008 | | | 2007 | | | 2006 | |
| |
| Natural Gas — (MMcf) | | | 56,120 | | | | 50,775 | | | | 45,270 | |
20062008 Compared with 20052007
Operating revenues for the Energy Marketing segment increased $167.4$137.6 million in 20062008 as compared with 2005.2007. The increase is primarily reflectsdue to higher gas sales revenue, as a result of an increase in the price of natural gas commodity prices that werewas recovered through revenues, and, to a lesser extent,coupled with an increase in throughput.volumes. The increase in throughput was duevolumes is primarily attributable to an increase in volumes sold to low-margin wholesale customers, as well as an increase in the
39
addition number of certain large commercial and industrial customers which more thanserved by the Energy Marketing segment. The increase in volumes also reflects certain sales transactions undertaken to offset any decrease in throughput duecertain basis risks that the Energy Marketing segment was exposed to warmer weatherunder certain commodity purchase contracts. The offsetting purchase and greater conservation by customers duesale transactions had the effect of increasing revenue and volumes sold with minimal impact to higher natural gas prices.earnings.
20052007 Compared with 20042006
Operating revenues for the Energy Marketing segment increased $45.4decreased $83.5 million in 20052007 as compared with 2004.2006. The increasedecrease primarily reflects lower gas sales revenue due to a decrease in natural gas commodity prices for the period that were recovered through revenues, offset in part by an increase in the price of natural gas. Volumes were down compared to the prior yearvolumes. The increase in volumes was due to the lossaddition of certain lower marginlarge, low-margin commercial and industrial customers, an increase in sales to wholesale customers.customers, and colder weather.
Earnings
20062008 Compared with 20052007
The Energy Marketing segment’s earnings in 20062008 were $5.8$5.9 million, an increasea decrease of $0.7$1.8 million when compared with earnings of $5.1$7.7 million in 2005. Despite warmer weather and greater conservation by customers, gross2007. Higher operating costs of $1.1 million (primarily due to an increase in bad debt expense) coupled with lower margins of $1.1 million are primarily responsible for the decrease in earnings. A major factor in the margin increaseddecrease 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 numberresolution of factors, including highera contingency. The increase in volumes noted above, the profitable sale of certain gas held as inventory, and the marketing flexibility associated with stored gas. Thethat the Energy Marketing segment’ssegment derives from its contracts for significant storage and transportation volumes provided operational flexibility resulting in increased sales throughput and earnings. The increase in grosscapacity partially offset the margin more than offset an increase in operation expense.decrease associated with the purchased gas adjustment.
20052007 Compared with 20042006
The Energy Marketing segment’s earnings in 20052007 were $5.1$7.7 million, a decreasean increase of $0.4$1.9 million when compared with earnings of $5.5$5.8 million in 2004.2006. Higher margins of $2.3 million are responsible for the increase in earnings. The decrease primarily reflects lower margins caused byincrease in margin is mainly the result of a reduction$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 the benefit of storage gas and,volume is related to a lesser extent, lower throughput.sales to low margin customers.
TIMBER
Revenues
Timber Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Log Sales | | $ | 23,077 | | | $ | 22,478 | | | $ | 21,790 | | | $ | 19,989 | | | $ | 21,927 | | | $ | 23,077 | |
| Green Lumber Sales | | | 7,123 | | | | 7,296 | | | | 5,923 | | | | 4,864 | | | | 5,097 | | | | 7,123 | |
| Kiln Dry Lumber Sales | | | 32,809 | | | | 29,651 | | | | 27,416 | | |
| Kiln-Dried Lumber Sales | | | | 22,914 | | | | 27,908 | | | | 32,809 | |
| Other | | | 2,020 | | | | 1,861 | | | | 841 | | | | 1,749 | | | | 3,965 | | | | 2,020 | |
| | | | | | | | | | | | | | | |
| | | $ | 65,029 | | | $ | 61,286 | | | $ | 55,970 | | | $ | 49,516 | | | $ | 58,897 | | | $ | 65,029 | |
| | | | | | | | | | | | | | | |
Timber Board Feet
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Log Sales | | | 9,527 | | | | 7,601 | | | | 6,848 | | | | 9,272 | | | | 8,660 | | | | 9,527 | |
| Green Lumber Sales | | | 10,454 | | | | 10,489 | | | | 9,552 | | | �� | 9,747 | | | | 9,358 | | | | 10,454 | |
| Kiln Dry Lumber Sales | | | 16,862 | | | | 15,491 | | | | 15,020 | | |
| Kiln-Dried Lumber Sales | | | | 13,425 | | | | 14,778 | | | | 16,862 | |
| | | | | | | | | | | | | | | |
| | | | 36,843 | | | | 33,581 | | | | 31,420 | | | | 32,444 | | | | 32,796 | | | | 36,843 | |
| | | | | | | | | | | | | | | |
20062008 Compared with 20052007
Operating revenues for the Timber segment increased $3.7decreased $9.4 million in 20062008 as compared with 2005. This increase can be chiefly attributed to an increase2007. 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 drykiln-dried lumber sales. The decrease in kiln-dried lumber sales of $3.2 million principallywas due to an increaseboth a decline in kiln drythe 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 of 2.0volumes). Log sales also decreased $1.9 million board feet. Other kiln dry lumber sales volumes
40
decreased by 0.6 million board feet, but there was little impactprimarily due to revenues. The addition of two new kilns in February 2005 allowed for greater processing capacity in 2006 as compared to 2005 since the kilns were in operation for all of 2006. Higher log sales revenue of $0.6 million also contributed to the increase in revenues. An increase in cherry export log sales as a result of greater market demand and an increase in saw log sales were the primary factors contributing to the increase. Offsetting these increases was a decline in cherry veneer log sales due to lower volumes of cherry328,000 board feet. Cherry veneer logs harvested becauseare 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 unfavorable weather conditions.timber rights and recorded a gain of $1.6 million in other revenues. This event did not recur in 2008.
42
20052007 Compared with 20042006
Operating revenues for the Timber segment increased $5.3decreased $6.1 million in 20052007 as compared with 2004.2006. This increase can be partiallydecrease is attributed to an increaseunfavorable 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 kiln drya 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 $2.2$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 an increase in cherry lumber sales volumesthe sale of 1.63.1 million board feet. While there was a decline in kiln dry lumber sales volumes from other species (1.1 million board feet), the revenue from those species is not significant. Cherry kiln dry lumber revenues represent over 90%feet of the Timber segment’s total kiln dry lumber revenues. The increase in volume is a result of the addition of two new kilns as discussed above, allowing for an increase in the amount of kiln dry lumber that can be processed. In addition, green lumber sales also increased by $1.4 million due to increased sales of maple green lumber primarily as a result of favorable weather conditions that allowed for an increase in harvesting.timber rights ($1.6 million).
Earnings
20062008 Compared with 20052007
The Timber segment earnings in 20062008 were $5.7$0.1 million, an increasea decrease of $0.7$3.6 million when compared with earnings of $5.0$3.7 million in 2005. Higher2007. The decrease was primarily due to lower margins from kiln dry lumber, log and timber rights sales and cherry export log sales accounted for($4.2 million) as a result of the decline in revenues noted above. This decrease was partially offset by the earnings increase.benefit associated with a lower effective tax rate ($0.8 million).
20052007 Compared with 20042006
The Timber segment earnings in 20052007 were $5.0$3.7 million, a decrease of $0.6$2.0 million when compared with earnings of $5.6$5.7 million in 2004. Increases in the cost of goods sold during 20052006. The decrease was primarily due to lower margins from lumber and log sales ($2.5 million) as a greater amountresult of timber being harvested on purchased stumpage, which has a higher cost basis than other raw material sources, is primarily responsible for the earnings decline. Also contributing to the decline were overall increases in operating expenses due to higher utility costs. Partially offsetting these declines in earnings were the increased sales of kiln dry lumber and green lumber discussedrevenues 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 favorable earnings impact associated withcutting of more low cost or no cost basis timber from Company owned land as well as the non-recurrence of a $0.8 million loss recordedoverall decrease in 2004 related to the Company’s fiscal 2003 sale of timber properties. In 2004, the Company received final timber cruise information of the properties it sold in 2003 and, based on that information, determined that property records pertaining to $1.3 million of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a loss of $0.8 million.logs harvested.
ALL OTHER AND CORPORATE OPERATIONS
All Other and Corporate Operationsoperations primarily includes the operations of Horizon LFG, Horizon Power, former International segment activity other than the activity from the Czech Republic operations, and corporate operations. 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 Operations ofIncome from Unconsolidated Subsidiaries on the Consolidated StatementStatements 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. Horizon Power also owns a gas-powered turbine and other assets which it had planned to use in the development of a co-generation plant. The Company is in the process of selling these
41
assets. The former International segment activity primarily consists of project development activities, the largest being projects in Italy and Bulgaria.
Earnings
20062008 Compared with 20052007
All Other and Corporate operations experienced incomehad earnings of $0.2$0.5 million in 2006, which was $7.12008, a decrease of $7.6 million greater thancompared with earnings of $8.1 million for 2007. The positive earnings impact of higher income from unconsolidated subsidiaries ($0.9 million) and a loss of $6.9 million in 2005. The increase is due primarily to the non-recurrence of $4.5 million of impairment charges recorded in 2005, as discussed below. Also contributing to the increase were higher interest income ($4.7 million) during 2006, resulting primarily from the investment of proceeds fromgain on the sale of U.E. in July 2005, combined with higher average interest rates in 2006 versus 2005. These increasesa turbine by Horizon Power ($0.6 million) were partiallymore than offset by higher operating expensescosts ($1.36.1 million), higher income tax expense ($1.7 million) and lower margins on landfill gas salesinterest income ($0.51.3 million). The increase in operating costs is primarily the result of the proxy contest with New Mountain Vantage GP, L.L.C.
43
20052007 Compared with 20042006
All Other and Corporate operations experienced a losshad earnings of $6.9$8.1 million in 2005, which2007, an increase of $7.9 million compared with earnings of $0.2 million for 2006. This improvement was $1.2largely due to an increase in interest income of $4.1 million greater than a loss of $5.7 million in 2004. During 2005, Horizon Power recorded a $2.7 million impairment in(primarily intercompany interest). In the value of its 50% investment in ESNE. Management determined that there was a decline in the fair market value of ESNE that was other than temporary in nature given continuing high commodity prices for natural gas and the negative impact these prices had on operations. ESNE has experienced losses over the last few years. It also recorded a $1.8 million impairment of the gas-powered turbine mentioned above. This impairment was based on a review of current market prices for similar turbines. However, these impairments were partially offset by higher equity method income from Horizon Power’s investments in Seneca Energy and Model City ($1.4 million).All Other category, Horizon LFG’s earnings decreased by $1.3benefited from higher margins of $1.0 million duein 2007 as compared to lower margins on gas sales. The overall decreases experienced by Horizon Power2006, and Horizon LFG were partially offset by a $1.7Power’s income from unconsolidated subsidiaries increased $0.9 million, improvementalso contributing to the increase in the losses experienced by the former International segment, largely due toearnings. The Corporate and All Other categories also had an earnings benefit associated with lower project development costs, and a $1.2 million improvement in earnings of Corporate operations.income tax expense ($2.0 million).
INTEREST INCOME
Interest income was $3.8$9.3 million higher in 20062008 as compared to 2005. As discussed in the earnings discussion by segment above, the2007. The main reasonsreason for this increase were strong cash flow from operations,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 U.E.SECI in July 2005 and higher average annual interest rates. Additionally, interest income on a pension related asset in accordance with the New York rate case settlement agreement increased by $0.5 million.August 2007.
Interest income was $4.7$7.9 million higherlower in 20052007 as compared to 2004.2006. As discussed in the Utility earnings discussion by segmentsection above, the main reason for this increasedecrease was the accrual of $3.7a $7.4 million decrease in interest income on a pension relatedpension-related regulatory asset in accordance with the Utility segment’s New York rate case settlement agreement that was completed in 2005.jurisdiction.
OTHER INCOME
Other income was $9.9 million lower in 2006 compared to 2005. As discussed in the earnings discussion by segment above, the main reasons for this decrease included non-recurring gains recorded during 2005 in the Pipeline and Storage segment related to the sale of base gas ($2.6 million), and the disposition of insurance proceeds ($3.9 million) received in prior years for which a contingency was resolved.
Other income was $9.8$2.4 million higher in 20052008 as compared to 2004. As discussed2007. This increase is attributed to the increase in the earnings discussion by segment above, the main reasonsallowance for this increase included a $2.6 million gainfunds used during construction, in the Pipeline and Storage segment, associated with the Empire Connector project of $4.2 million. This increase was partially offset by the non-recurrence of a FERC approved saledeath benefit gain on life insurance proceeds of base gas in 2005 and a $3.9$1.9 million gainrecognized in the Pipeline and Storage segment associated withCorporate 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 receivedof $1.9 million recognized in prior years for which a contingency was resolved during 2005.the Corporate category.
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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 decreased $0.6increased $1.7 million in 2006 and $9.72008 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 $4.2 million in 2005.2007 as compared to 2006. The decrease in 20052007 was primarily the result of a lower average amount of long-term debt outstanding.
Other interest charges were $3.1 In addition, the Company recognized a $1.9 million lower in 2006 comparedbenefit to 2005. The decrease resulted primarily from the non-recurrence of $2.1 million of interest expense as a result of the discontinuance of hedge accounting for Empire’s interest rate collar, as discussed below,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 byin accumulated other comprehensive income associated with the Utility segment in 2005 and a lower average amount of short-term debt outstandinginterest rate collar was reclassified to interest expense during the quarter ended December 31, 2006.
Other interest charges were $2.3decreased $2.2 million higher in 20052008 compared to 2004.2007. 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 resulted mainly from $2.1 million of interest expense recorded byin the Utility segment as part of an adjustmentallowance for borrowed funds used during construction related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax.the Empire Connector project.
44
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 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Millions) | | | (Millions) | |
| |
| Provided by Operating Activities | | $ | 471.4 | | | $ | 317.3 | | | $ | 437.1 | | | $ | 482.8 | | | $ | 394.2 | | | $ | 471.4 | |
| Capital Expenditures | | | (294.2 | ) | | | (219.5 | ) | | | (172.3 | ) | | | (397.7 | ) | | | (276.7 | ) | | | (294.2 | ) |
| Net Proceeds from Sale of Foreign Subsidiary | | | — | | | | 111.6 | | | | — | | |
| Investment in Partnership | | | | — | | | | (3.3 | ) | | | — | |
| Net Proceeds from Sale of Foreign Subsidiaries | | | | — | | | | 232.1 | | | | — | |
| Cash Held in Escrow | | | | 58.4 | | | | (58.2 | ) | | | — | |
| Net Proceeds from Sale of Oil and Gas Producing Properties | | | — | | | | 1.4 | | | | 7.1 | | | | 5.9 | | | | 5.1 | | | | — | |
| Other Investing Activities | | | (3.2 | ) | | | 3.2 | | | | 2.0 | | | | 4.4 | | | | (0.8 | ) | | | (3.2 | ) |
| Change in Short-Term Debt | | | — | | | | (115.4 | ) | | | 38.6 | | |
| Reduction of Long-Term Debt | | | (9.8 | ) | | | (13.3 | ) | | | (243.1 | ) | | | (200.0 | ) | | | (119.6 | ) | | | (9.8 | ) |
| Net Proceeds from Issuance of Long-Term Debt | | | | 296.6 | | | | — | | | | — | |
| Issuance of Common Stock | | | 23.3 | | | | 20.3 | | | | 23.8 | | | | 17.4 | | | | 17.5 | | | | 23.3 | |
| Dividends Paid on Common Stock | | | (98.2 | ) | | | (94.1 | ) | | | (89.1 | ) | | | (103.7 | ) | | | (100.6 | ) | | | (98.2 | ) |
| Dividends Paid to Minority Interest | | | — | | | | (12.7 | ) | | | — | | |
| Excess Tax Benefits Associated with Stock- Based Compensation Awards | | | 6.5 | | | | — | | | | — | | | | 16.3 | | | | 13.7 | | | | 6.5 | |
| Shares Repurchased under Repurchase Plan | | | (85.2 | ) | | | — | | | | — | | | | (237.0 | ) | | | (48.1 | ) | | | (85.2 | ) |
| Effect of Exchange Rates on Cash | | | 1.4 | | | | 1.3 | | | | 3.5 | | | | — | | | | (0.1 | ) | | | 1.4 | |
| | | | | | | | | | | | | | | |
| Net Increase in Cash and Temporary Cash Investments | | $ | 12.0 | | | $ | 0.1 | | | $ | 7.6 | | |
| Net Increase (Decrease) in Cash and Temporary Cash Investments | | | $ | (56.6 | ) | | $ | 55.2 | | | $ | 12.0 | |
| | | | | | | | | | | | | | | |
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 minority interest in foreign subsidiaries, loss on sale of timber properties, gain on sale of oil and gas producing properties, and gain on the 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
43
The majority of the Utility capital expenditures were made for replacement of mains and main extensions, as well as for the replacement of service lines.
The Exploration and Production segment’s capital expenditures were primarily well drilling and completion expenditures and included approximately $41.8 million for the Canadian region, $103.4$63.6 million for the Gulf Coast region, ($102.8 millionsubstantially all of which was for the off-shore program in the shallow waters of the Gulf of Mexico), $36.1Mexico, $62.8 million for the West Coast region and $27.0$65.8 million for the Appalachian region. The significant amount spent in the Gulf Coast region is related to high commodity prices, which has improved the economics of investment in the area, plus
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 $44.0$32.3 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters computer equipment 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 $7.1$3.0 million. The Company has guaranteed 50%, or $3.5$1.5 million, of these capital lease commitments.
The following table summarizes the Company’s expected future contractual cash obligations as of September 30, 2006,2008, and the twelve-month periods over which they occur:
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 sheet in accordance with the SFAS 133 (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 sheet as a current liability; and (iii) other obligations which are reflected on the consolidated balance sheet. 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.*
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, 2006:2008:
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
| | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Minimum Pension Liability Adjustment | | $ | — | | | $ | (107,844 | ) | |
| Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | $ | (19,741 | ) | | $ | (12,482 | )(1) |
| Cumulative Foreign Currency Translation Adjustment | | | 34,701 | | | | 28,009 | | | | (71 | ) | | | (83 | ) |
| Net Unrealized Loss on Derivative Financial Instruments | | | (11,510 | ) | | | (123,339 | ) | |
| Net Unrealized Gain (Loss) on Derivative Financial Instruments | | | | 15,949 | | | | (3,886 | ) |
| Net Unrealized Gain on Securities Available for Sale | | | 7,225 | | | | 5,546 | | | | 6,826 | | | | 10,248 | |
| | | | | | | | | | | |
| Accumulated Other Comprehensive Income (Loss) | | $ | 30,416 | | | $ | (197,628 | ) | | $ | 2,963 | | | $ | (6,203 | ) |
| | | | | | | | | | | |
| | |
| (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, 2006,2008, it is estimated that of the $11.5$15.9 million net unrealized lossgain on derivative financial instruments shown in the table above, $12.7$13.1 million will be reclassified into the Consolidated Statement of Income during 2007.2009. The remaining unrealized gain on derivative financial instruments of $1.2$2.8 million will be reclassified into the Consolidated Statement of Income in subsequent years. As disclosed in Note F — Financial Instruments, the Company’s derivative financial instruments extend out to 2012.
70
NATIONAL FUEL GAS COMPANYThe 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 million and $1.0 million at September 30, 2008 and September 30, 2007, respectively. The total amount for accumulated losses was $19.3 million and $11.4 million at September 30, 2008 and September 30, 2007, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Gas Stored Underground — Current
In the Utility segment, gas stored underground — current in the amount of $29.5$34.1 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 2006,2008, 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 $136.0$195.4 million at September 30, 2006.2008. 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, the 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 a consistentan 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 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 | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Materials and Supplies | | $ | 13,174 | | | $ | 10,610 | | | $ | 9,911 | | | $ | 8,925 | |
| Other Assets | | | 3,218 | | | | 11,510 | | | | 7,383 | | | | 5,641 | |
| | | | | | | | | | | |
| | | $ | 16,392 | | | $ | 22,120 | | | $ | 17,294 | | | $ | 14,566 | |
| | | | | | | | | | | |
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.
71
NATIONAL FUEL GAS COMPANY 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 been excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represents a non-cash investing activity at that date.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Hedging Collateral Account
Cash held in margin accounts serves as collateral for open positions on exchange-traded futures contracts, exchange-traded options andover-the-counter swaps and collars.
70
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Cash Held in Escrow
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 $25.7$10.6 million and $23.9$14.1 million at September 30, 20062008 and 2005,2007, respectively, prepaid property and other taxes of $11.2 million and $14.1 million at September 30, 2008 and 2007, respectively, federal income taxes receivable in the amounts of $7.5$27.5 million and $27.1$8.7 million at September 30, 20062008 and 2005,2007, respectively, state income taxes receivable in the amounts of $7.4$5.0 million and $2.6 millionzero at September 30, 20062008 and 2005,2007, respectively, and fair values of firm commitments in the amounts of $23.1$10.9 million and $13.7$8.2 million at September 30, 20062008 and 2005,2007, respectively.
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. TheFor purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options.options and stock-settled SARs. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflectreflects 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 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 optionsstock-settled SARs excluded as being antidilutive for 2005. For 2004, 2,296,828 stock options were excluded as being antidilutive.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.
72
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Effective October 1, 2005, the Company adopted SFAS 123R, which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options.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 is recordingrecorded compensation cost for the portion of awards granted prior to October 1, 2005 for which the requisite service had not been rendered and is recognizingrecognized such compensation cost as the requisite service iswas 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 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. There were no stock options granted during the year ended September 30, 2008. There were 448,000 and 317,000 700,000 and 87,000 stock-based compensation awardsstock options granted during the years ended September 30, 2007 and 2006, 2005respectively. The Company granted 321,000 performance based stock-settled SARs during the year ended September 30, 2008. There were no 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 no non-performance based stock-settled SARs granted during the year ended September 30, 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 2004,non-performance based stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R. 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 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, no compensation expense is recognized and any recognized compensation expense is reversed. The Company also granted 25,000, 25,000 and 16,000 restricted share awards (non-vested stock as defined by SFAS 123R) during the years ended September 30, 2008, 2007 and 2006, respectively. Stock-based compensation expense for the years ended September 30, 2006, September 30, 2005,2008, 2007 and September 30, 20042006 was approximately $1,705,000 ($442,000 of which relates to the application of the non-substantive vesting period approach discussed below), $517,000$2,332,000, $3,727,000, and $835,000,$1,705,000, 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, 2006, 20052008, 2007 and 20042006 was approximately $653,000, $206,000$945,000, $1,488,000 and $333,000,$653,000, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 20062008 and September 30, 2005.2007.
Prior to the adoption of SFAS 123R, the Company followed the nominal vesting period approach under the disclosure requirements of SFAS 123 for determining the vesting period for awards with retirement-eligible provisions, which recognized stock-based compensation expense over the nominal vesting period. As a result of the adoption of SFAS 123R, the Company currently applies the non-substantive vesting period approach for determining the vesting period of such awards. Under this approach, the retention of the award is not contingent on providing subsequent service and the vesting period would begin at the grant date and end at the retirement-eligible date. For the year ended September 30, 2006, the Company recognized an additional $442,000 ($288,000 net of tax) of stock-based compensation expense by applying the non-substantive vesting approach. For the year ended September 30, 2005, stock-based compensation expense would have been $4,282,000 ($2,752,000 net of tax) for pro forma recognition purposes had the non-substantive vesting period approach been used. The pro forma stock-based compensation expense would have been $2,670,000 ($1,798,000 net of tax) under the non-substantive vesting period approach for the year ended September 30, 2004. Pro forma stock-based compensation expense following the nominal vesting period approach is shown in the table below.
7372
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table illustrates the effect on net income and earnings per share of the Company had the Company applied the fair value recognition provisions of SFAS 123 relating to stock-based employee compensation for the years ended September 30, 2005 and 2004:
| | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2005 | | | 2004 | |
| | | (Thousands, except per share amounts) | |
| |
| Net Income, Available for Common Stock, As Reported | | $ | 189,488 | | | $ | 166,586 | |
| Add: Stock-Based Employee Compensation Expense Included in Reported Net Income, Net of Tax(1) | | | 336 | | | | 543 | |
| Deduct: Total Stock-Based Employee Compensation Expense Determined Under Fair Value Based Methods for all Awards, Net of Related Tax Effects | | | (2,782 | ) | | | (1,861 | ) |
| | | | | | | | | |
| Pro Forma Net Income Available for Common Stock | | $ | 187,042 | | | $ | 165,268 | |
| | | | | | | | | |
| Earnings Per Common Share: | | | | | | | | |
| Basic — As Reported | | $ | 2.27 | | | $ | 2.03 | |
| Basic — Pro Forma | | $ | 2.24 | | | $ | 2.01 | |
| Diluted — As Reported | | $ | 2.23 | | | $ | 2.01 | |
| Diluted — Pro Forma | | $ | 2.20 | | | $ | 1.99 | |
| | |
(1) | | Stock-based compensation expense in 2005 and 2004 represented compensation expense related to restricted stock awards. The pre-tax expense was $517,000 and $835,000, respectively, for the years ended September 30, 2005 and 2004. |
Stock Options
The total intrinsic value of stock options exercised during the years ended September 30, 2006, September 30, 2005,2008, 2007 and September 30, 20042006 totaled approximately $30.9$24.6 million, $19.8$38.7 million, and $12.4$30.9 million, respectively. For 2006, 20052008, 2007 and 2004,2006, the amount of cash received by the Company from the exercise of such stock options was approximately $18.5 million, $26.0 million, and $30.1 million, $24.8 million, and $16.4 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, 2005, December 31, 2004,2007, 2006, and December 31, 2003,2005, the Company realized a tax benefit of $4.4 million, $3.2 million, and $0.9 million, $1.1respectively. For stock options exercised during the period of January 1, 2008 through September 30, 2008, the Company will realize a tax benefit of approximately $4.3 million and $0.1in 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 respectively.in the quarter ended December 31, 2007. For stock options exercised during the period of January 1, 2006 through September 30, 2006, the Company will realizerealized a tax benefit of approximately $11.4 million in the quarter ended December 31, 2006. For stock options exercised during the period of January 1, 2005 through September 30, 2005, the Company realized a tax benefit of approximately $6.3 million in the quarter ended December 31, 2005. For stock options exercised during the period of January 1, 2004 through September 30, 2004, the Company realized a tax benefit of approximately $4.8 million in the quarter ended December 31, 2004. The weighted average grant date fair value of options granted in 2007 and 2006 2005 and 2004 is $6.68 per share, $4.59$7.27 per share and $4.66$6.68 per share, respectively. For the years ended September 30, 2008, 2007 and 2006, 2005358,000, 327,501 and 2004, 89,665 1,375,105 and 729,156 stock options became fully vested, respectively. The total fair value of these stock options was approximately $0.4$2.6 million, $6.2$2.1 million and $3.3$0.4 million, respectively, for the years ended September 30, 2006, 20052008, 2007 and 2004.2006. As of September 30, 2006,2008, unrecognized compensation expense related to stock options totaled approximately $0.9$0.3 million, which will be recognized over a weighted average period of one year.8.6 months. For a summary of transactions during 20062008 involving option shares for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
74
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. 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 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| |
| Risk Free Interest Rate | | | 5.08 | % | | | 4.46 | % | | | 4.61 | % | | | N/A | | | | 4.46 | % | | | 5.08 | % |
| Expected Life (Years) | | | 7.0 | | | | 7.0 | | | | 7.0 | | | | N/A | | | | 7.0 | | | | 7.0 | |
| Expected Volatility | | | 17.71 | % | | | 17.76 | % | | | 21.77 | % | | | N/A | | | | 17.73 | % | | | 17.71 | % |
| Expected Dividend Yield (Quarterly) | | | 0.83 | % | | | 1.00 | % | | | 1.12 | % | | | N/A | | | | 0.76 | % | | | 0.83 | % |
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 prior to October 1, 2005, the Company used a forfeiture rate of 13.6% for calculating stock-based compensation expense related to stock options and this rate is based on the Company’s historical experience of forfeitures on unvested stock option grants. For grants during the yearyears 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 no non-performance based stock-settled SARs exercised during the years ended September 30, 2008, 2007 and 2006 as none of the non-performance based stock-settled SARs granted have vested. 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 no non-performance based stock-settled SARs granted during 2008 or 2006. As of September 30, 2008, unrecognized compensation expense related to non-performance based stock-settled SARs totaled approximately $0.2 million, which will be recognized over a weighted average period of 10.2 months. For a summary of transactions during
73
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2008 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 Rate | | | 4.53 | % |
| Expected Life (Years) | | | 7.0 | |
| Expected Volatility | | | 17.55 | % |
| Expected Dividend Yield (Quarterly) | | | 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 no performance based stock-settled SARs exercised during the years ended September 30, 2008, 2007 and 2006 as none of the performance based stock-settled SARs granted have vested. There were 321,000 performance based stock-settled SARs granted during 2008. The weighted average grant date fair value of performance based stock-settled SARs granted in 2008 is $9.06 per share. There were no performance based stock-settled SARs granted during 2007 or 2006. For the years ended September 30, 2008, 2007 and 2006, there were no performance based stock-settled SARs that became fully vested. As of September 30, 2008, unrecognized compensation expense related to performance based stock-settled SARs totaled approximately $1.9 million, which will be recognized over a weighted average period of 1.1 years. For a summary of transactions during 2008 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 Rate | | | 3.78 | % |
| Expected Life (Years) | | | 7.25 | |
| Expected Volatility | | | 17.69 | % |
| Expected Dividend Yield (Quarterly) | | | 0.64 | % |
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 year ended September 30, 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 2008, 2007 and 2006 is $48.41 per share, $40.18 per share and $34.94 per share, respectively. As of September 30, 2008, unrecognized compensation expense related to restricted share awards totaled approximately $1.6 million, which will be recognized over a weighted average period of 2.5 years. For a summary of transactions during 20062008 involving restricted share awards, refer to Note E — Capitalization and Short-Term Borrowings.
As of September 30, 2006, unrecognized compensation expense related to restricted share awards totaled approximately $577,000, which will be recognized over a weighted average period of 2.1 years.
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 Accounting Pronouncements
In March 2005, the FASB issued 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, a company must record a liability for a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. 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. The Company has adopted FIN 47 as of September 30, 2006. Refer to Note B — Asset Retirement Obligations for further disclosure regarding the impact of FIN 47 on the Company’s consolidated financial statements.
In May 2005, the FASB issued SFAS 154. SFAS 154 replaces APB 20 and SFAS 3 and changes the requirements for the accounting for and reporting of a change in accounting principle. The Company is required to adopt SFAS 154 for accounting changes and corrections of errors that occur in 2007. The Company’s financial condition and results of operations will only be impacted by SFAS 154 if there are any accounting changes or corrections of errors in the future.
75
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In June 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes and reduces the diversity in current practice associated with the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return by defining a “more-likely-than-not” threshold regarding the sustainability of the position. The Company is required to adopt FIN 48 by the first quarter of fiscal 2008. The Company is currently evaluating the impact of FIN 48 on its consolidated financial statements.
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement 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 157 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. The pronouncementIn accordance with FASB Staff PositionFAS No. 157-2, SFAS 157 is effective 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 Position 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. The Company is currently evaluating the impactdoes not expect that the adoption of SFAS 157 will have a significant impact on its consolidated financial statements.
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 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 the Company’s fiscal year, with limited exceptions. TheIn accordance with SFAS 158, the Company is required to recognizehas recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 by the fourth quarter of fiscalat 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. IfCurrently, the Company recognizedmeasures its plan assets and benefit obligations using a June 30th measurement date. At September 30, 2007, in order to recognize the funded status of its pension and post-retirement benefit plans at September 30, 2006,in accordance with SFAS 158, the Company recorded additional liabilities or reduced assets by a cumulative amount of $78.7 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, $12.5 million (net of deferred tax benefits of $7.6 million) was recorded as an increase to Accumulated Other Comprehensive Loss, and $3.3 million was recorded as an increase to Other Regulatory Liabilities 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. Refer to Note G — Retirement Plan and Other Post-Retirement Benefits for further disclosures regarding the impact of SFAS 158 on the Company’s consolidated balance sheet would reflect a liability of $220.8 million instead of the prepaid pension and post-retirement costs of $64.1 million and pension and post-retirement liabilities of $32.9 million that are currently presented on the balance sheet at September 30, 2006. The Company expects that it will record a regulatory asset for the majority of this liability with the remainder reflected in accumulated other comprehensive income (loss).financial statements.
75
NATIONAL FUEL GAS COMPANY
Note BNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Asset Retirement Obligations(Continued)
Effective October 1, 2002,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 adopteddoes 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 will significantly change 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, 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 141R 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 change 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 160 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 161 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 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective as of the Company’s second quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 161 will have on its disclosures in the notes to the consolidated financial statements.
| |
| Note B — | Asset Retirement Obligations |
The Company accounts for asset retirement obligations in accordance with the provisions of SFAS 143. SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. 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. Upon the adoption of SFAS 143 on October 1, 2002, the Company recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells.wells and capitalized such costs in property, plant and equipment (i.e. the full cost pool). Prior to the adoption of SFAS 143, 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 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, plugging and abandonment costs are already included in capitalized costs and the units-of-production depletion calculation has been modified to exclude 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 to the adoption of SFAS 143, in calculating the full
76
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
cost ceiling, the Company reduced 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 adoption 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, 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 liability and a corresponding asset for 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.
76
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As a result ofUpon the adoption of FIN 47, the Company identifiedrecorded 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 also identified 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.
A reconciliation of the Company’s asset retirement obligation calculated in accordance with SFAS 143 is shown below ($000s):
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
| Balance at Beginning of Year | | $ | 41,411 | | | $ | 32,292 | | | $ | 27,493 | |
| Additions — Adoption of FIN 47 | | | 23,234 | | | | — | | | | — | |
| Liabilities Incurred and Revisions of Estimates | | | 11,244 | | | | 8,343 | | | | 3,510 | |
| Liabilities Settled | | | (1,303 | ) | | | (1,938 | ) | | | (831 | ) |
| Accretion Expense | | | 2,671 | | | | 2,448 | | | | 1,933 | |
| Exchange Rate Impact | | | 135 | | | | 266 | | | | 187 | |
| | | | | | | | | | | | | |
| Balance at End of Year | | $ | 77,392 | | | $ | 41,411 | | | $ | 32,292 | |
| | | | | | | | | | | | | |
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, 20062008 and 2005,2007, the costs of removal reclassified to other regulatory liabilities amounted to $85.1$103.1 million and $90.4$91.2 million, respectively.
Pursuant to FIN 47,A reconciliation of the financial statements for periods prior to September 30, 2006 have not been restated. If FIN 47 had been in effect, the Company would have recorded additionalCompany’s asset retirement obligations of $21.9 million at September 30, 2005, and $20.6 million at October 1, 2004.obligation calculated in accordance with SFAS 143 is shown below:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | (Thousands) | | | | |
| |
| Balance at Beginning of Year | | $ | 75,939 | | | $ | 77,392 | | | $ | 41,411 | |
| Additions — Adoption of FIN 47 | | | — | | | | — | | | | 23,234 | |
| Liabilities Incurred and Revisions of Estimates | | | 18,739 | | | | (932 | ) | | | 11,244 | |
| Liabilities Settled | | | (6,871 | ) | | | (6,108 | ) | | | (1,303 | ) |
| Accretion Expense | | | 5,440 | | | | 5,394 | | | | 2,671 | |
| Exchange Rate Impact | | | — | | | | 193 | | | | 135 | |
| | | | | | | | | | | | | |
| Balance at End of Year | | $ | 93,247 | | | $ | 75,939 | | | $ | 77,392 | |
| | | | | | | | | | | | | |
77
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 | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Thousands) | | | (Thousands) | |
| |
Regulatory Assets(1): | | | | | | | | | | | | | | | | |
| Pension and Other Post-Retirement Benefit Costs(2) (Note G) | | | $ | 147,909 | | | $ | 98,787 | |
| Recoverable Future Taxes (Note D) | | $ | 79,511 | | | $ | 85,000 | | | | 82,506 | | | | 83,954 | |
| Pension and Post-Retirement Benefit Costs(2) (Note G) | | | 47,368 | | | | 27,135 | | |
| Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A) | | | 12,970 | | | | 14,817 | | | | 37,708 | | | | 14,769 | |
| Environmental Site Remediation Costs(2) (Note H) | | | 12,937 | | | | 13,054 | | | | 22,530 | | | | 20,738 | |
| Asset Retirement Obligation(2) (Note B) | | | 9,018 | | | | — | | |
| Asset Retirement Obligations(2) (Note B) | | | | 8,155 | | | | 8,315 | |
| Unamortized Debt Expense (Note A) | | | 8,399 | | | | 9,088 | | | | 7,524 | | | | 8,470 | |
| Recoverable Worker Compensation Expense(2) | | | | 4,518 | | | | 4,445 | |
| Other(2) | | | 7,594 | | | | 6,839 | | | | 6,475 | | | | 5,292 | |
| | | | | | | | | | | |
| Total Regulatory Assets | | | 177,797 | | | | 155,933 | | | | 317,325 | | | | 244,770 | |
| | | | | | | | | | | |
Regulatory Liabilities: | | | | | | | | | | | | | | | | |
| Cost of Removal Regulatory Liability (Note B) | | | 85,076 | | | | 90,396 | | | | 103,100 | | | | 91,226 | |
| Pension and Other Post-Retirement Benefit Costs(3) (Note G) | | | | 42,994 | | | | 21,676 | |
| Tax Benefit on Medicare Part D Subsidy(3) | | | | 23,502 | | | | 19,147 | |
| New York Rate Settlements(3) | | | 40,881 | | | | 53,205 | | | | 19,012 | | | | 27,964 | |
| Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | | | 23,935 | | | | 1,158 | | |
| Tax Benefit on Medicare Part D Subsidy(3) | | | 13,791 | | | | — | | |
| Pension and Post-Retirement Benefit Costs(3) (Note G) | | | 13,063 | | | | 12,751 | | |
| Taxes Refundable to Customers (Note D) | | | 10,426 | | | | 11,009 | | | | 18,449 | | | | 14,026 | |
| Deferred Insurance Proceeds(3) | | | 7,516 | | | | — | | | | 3,933 | | | | 7,422 | |
| Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | | | | 2,753 | | | | 10,409 | |
| Other(3) | | | 205 | | | | 383 | | | | 2,492 | | | | 450 | |
| | | | | | | | | | | |
| Total Regulatory Liabilities | | | 194,893 | | | | 168,902 | | | | 216,235 | | | | 192,320 | |
| | | | | | | | | | | |
| Net Regulatory Position | | $ | (17,096 | ) | | $ | (12,969 | ) | | $ | 101,090 | | | $ | 52,450 | |
| | | | | | | | | | | |
| | |
| (1) | | The Company recovers the cost of its regulatory assets but, with the exception of Unrecovered Purchased Gas Costs, does not earn a return on them. |
| |
| (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 sheet 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.
78
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
New York Rate Settlements
With respect to utility services provided in New York, the Company has entered into rate settlements approved by 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, 20062008 and 20052007 of $19.8$4.1 million and $34.3$6.7 million, respectively. Under the terms of its 2005 rate settlement,agreement, Distribution Corporation will passhas been passing back that regulatory liability to rate payers over a twenty-four month period that begansince 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 can be used to offset certain expense items specified in Distribution Corporation’s rate settlements. The source of the CMR iswas principally the accumulation of certain refunds from upstream pipeline companies. During 2005, under the terms of the 2005 rate settlement,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, 20062008 and 20052007 amounted to $7.6$0.3 million and $7.0$7.4 million, respectively.
Other — The 2005 settlementagreement also established a reserve to fund area development projects. The balance in the area development projects reserve at September 30, 20062008 and 20052007 amounted to $3.9$3.0 million and $3.8$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 $9.6$11.6 million and $8.1$10.3 million at September 30, 20062008 and 2005,2007, respectively.
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 rate payerratepayer funds the Company’s post-retirement benefit plans. As such, any tax benefit received under the Act must be flowed-through to the rate payer.ratepayer. Refer to Note G — 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, received $7.5 million inhas deferred environmental insurance settlement proceeds.proceeds amounting to $3.9 million and $7.4 million at September 30, 2008 and 2007, 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 rate payersratepayers funded the premiums on the former insurance policies.
Recoverable Worker Compensation Expense
The Company has established a liability in its Utility segment in accordance with the provisions of SFAS 112 for future worker compensation liabilities. Such amounts have been deferred as a regulatory asset because the Company is allowed to recover worker compensation expense in rates.
79
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | | | (Thousands) | | | |
| |
| Operating Expenses: | | | | | | | | | | | | | |
| Current Income Taxes — | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal | | $ | 65,593 | | | $ | 40,062 | | | $ | 42,679 | | | $ | 75,079 | | | $ | 99,608 | | | $ | 65,593 | |
| State | | | 13,511 | | | | 14,413 | | | | 7,871 | | | | 20,257 | | | | 21,700 | | | | 13,511 | |
| Foreign | | | 2,212 | | | | 1,503 | | | | 206 | | | | 90 | | | | 22 | | | | 2,212 | |
| Deferred Income Taxes — | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal | | | 19,111 | | | | 27,412 | | | | 29,559 | | | | 56,668 | | | | 39,340 | | | | 19,111 | |
| State | | | 9,024 | | | | 2,280 | | | | 9,620 | | | | 15,828 | | | | 10,751 | | | | 9,024 | |
| Foreign | | | (33,365 | ) | | | 7,308 | | | | 4,655 | | | | — | | | | 2,756 | | | | (33,365 | ) |
| | | | | | | | | | | | | | | |
| | | | 76,086 | | | | 92,978 | | | | 94,590 | | | | 167,922 | | | | 174,177 | | | | 76,086 | |
| Other Income: | | | | | | | | | | | | | |
| Deferred Investment Tax Credit | | | (697 | ) | | | (697 | ) | | | (697 | ) | | | (697 | ) | | | (697 | ) | | | (697 | ) |
| Discontinued Operations | | | | | | | | | | | | | |
| Operations | | | — | | | | 9,310 | | | | (1,479 | ) | |
| Gain on Sale | | | — | | | | 1,612 | | | | — | | |
| | | | | | | | | | | | | | | |
| Total Income Taxes | | $ | 75,389 | | | $ | 103,203 | | | $ | 92,414 | | | $ | 167,225 | | | $ | 173,480 | | | $ | 75,389 | |
| | | | | | | | | | | | | | | |
| Presented as Follows: | | | | | | | | | | | | | |
| Other Income | | | $ | (697 | ) | | $ | (697 | ) | | $ | (697 | ) |
| Income Tax Expense — Continuing Operations | | | | 167,922 | | | | 131,813 | | | | 108,245 | |
| Discontinued Operations — | | | | | | | | | | | | | |
| Income From Operations | | | | — | | | | 2,792 | | | | (32,159 | ) |
| Gain on Disposal | | | | — | | | | 39,572 | | | | — | |
| | | | | | | | | |
| Total Income Taxes | | | $ | 167,225 | | | $ | 173,480 | | | $ | 75,389 | |
| | | | | | | | | |
The U.S. and foreign components of income (loss) before income taxes are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | | | (Thousands) | | | |
| |
| U.S. | | $ | 293,887 | | | $ | 223,113 | | | $ | 232,928 | | | $ | 435,982 | | | $ | 496,074 | | | $ | 293,887 | |
| Foreign | | | (80,407 | ) | | | 69,578 | | | | 26,072 | | | | (29 | ) | | | 14,861 | | | | (80,407 | ) |
| | | | | | | | | | | | | | | |
| | | $ | 213,480 | | | $ | 292,691 | | | $ | 259,000 | | | $ | 435,953 | | | $ | 510,935 | | | $ | 213,480 | |
| | | | | | | | | | | | | | | |
80
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 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | | | (Thousands) | | | |
| |
| Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% | | $ | 74,718 | | | $ | 102,442 | | | $ | 90,650 | | | $ | 152,584 | | | $ | 178,827 | | | $ | 74,718 | |
| Increase in Taxes Resulting from: | | | | | | | | | | | | | | | | | | | | | | | | |
| State Income Taxes | | | 14,648 | | | | 10,850 | | | | 11,369 | | | | 23,455 | | | | 21,093 | | | | 14,648 | |
| Foreign Tax Differential | | | (3,718 | ) | | | (4,845 | ) | | | (1,166 | ) | | | 69 | | | | (20,980 | ) | | | (3,718 | ) |
| Foreign Tax Rate Reduction | | | — | | | | — | | | | (5,174 | ) | |
| Reversal of Capital Loss Valuation Allowance | | | (2,877 | ) | | | — | | | | — | | | | — | | | | — | | | | (2,877 | ) |
| Miscellaneous | | | (7,382 | ) | | | (5,244 | ) | | | (3,265 | ) | | | (8,883 | ) | | | (5,460 | ) | | | (7,382 | ) |
| | | | | | | | | | | | | | | |
| Total Income Taxes | | $ | 75,389 | | | $ | 103,203 | | | $ | 92,414 | | | $ | 167,225 | | | $ | 173,480 | | | $ | 75,389 | |
| | | | | | | | | | | | | | | |
80
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 and the amount for 2005 includes tax effects relating to the disposition of a foreign subsidiary. The foreign tax rate reduction amount shown above for 2004 relates to the reduction of the statutory income tax rate in the Czech Republic.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 | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Deferred Tax Liabilities: | | | | | | | | | | | | | | | | |
| Property, Plant and Equipment | | $ | 569,677 | | | $ | 567,850 | | | $ | 673,313 | | | $ | 612,648 | |
| Pension and Other Post-Retirement Benefit Costs — SFAS 158 | | | | 43,340 | | | | 21,892 | |
| Other | | | 37,865 | | | | 52,436 | | | | 55,391 | | | | 39,724 | |
| | | | | | | | | | | |
| Total Deferred Tax Liabilities | | | 607,542 | | | | 620,286 | | | | 772,044 | | | | 674,264 | |
| | | | | | | | | | | |
| Deferred Tax Assets: | | | | | | | | | | | | | | | | |
| Minimum Pension Liability Adjustment | | | — | | | | (58,069 | ) | |
| Capital Loss Carryover | | | (8,786 | ) | | | (9,145 | ) | |
| Unrealized Hedging Losses | | | (4,653 | ) | | | (75,657 | ) | |
| Pension and Other Post-Retirement Benefit Costs — SFAS 158 | | | | (43,340 | ) | | | (21,892 | ) |
| Other | | | (82,006 | ) | | | (74,346 | ) | | | (92,461 | ) | | | (85,566 | ) |
| | | | | | | |
| | | | (95,445 | ) | | | (217,217 | ) | |
| Valuation Allowance | | | — | | | | 2,877 | | |
| | | | | | | | | | | |
| Total Deferred Tax Assets | | | (95,445 | ) | | | (214,340 | ) | | | (135,801 | ) | | | (107,458 | ) |
| | | | | | | | | | | |
| Total Net Deferred Income Taxes | | $ | 512,097 | | | $ | 405,946 | | | $ | 636,243 | | | $ | 566,806 | |
| | | | | | | | | | | |
| Presented as Follows: | | | | | | | | | | | | | | | | |
| Net Deferred Tax Asset — Current | | $ | (23,402 | ) | | $ | (83,774 | ) | |
| Net Deferred Tax Asset — Non-Current | | | (9,003 | ) | | | — | | |
| Net Deferred Tax Liability/(Asset) — Current | | | $ | 1,871 | | | $ | (8,550 | ) |
| Net Deferred Tax Liability — Non-Current | | | 544,502 | | | | 489,720 | | | | 634,372 | | | | 575,356 | |
| | | | | | | | | | | |
| Total Net Deferred Income Taxes | | $ | 512,097 | | | $ | 405,946 | | | $ | 636,243 | | | $ | 566,806 | |
| | | | | | | | | | | |
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 $10.4$18.4 million and $11.0$14.0 million at September 30, 20062008 and 2005,2007, 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 $79.5$82.5 million and $85.0$84.0 million at September 30, 20062008 and 2005,2007, respectively.
The American Jobs Creation Act of 2004, signed into law on October 22, 2004, included a provision which provided a substantially reduced tax rate of 5.25% on certain dividends received from foreign affiliates. During 2005, the Company received a dividend of $72.8 million from a foreign affiliate and recorded a tax of $3.8 million on such dividend.
A capital loss carryover of $25.1 million exists at September 30, 2006, which expires if not utilized by September 30, 2008. Although realization is not assured, management determined that it is more likely than not that the entire deferred tax asset associated with this carryover will be realized during the carryover period. As such, the valuation allowance of $2.9 million was reversed during 2006.
81
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company adopted FIN 48 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.
A deferredtabular reconciliation of the change in unrecognized tax assetbenefits for the twelve months ended September 30, 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 | |
| | | | | |
Within the next twelve months, the Company believes it is reasonably possible that the total amount of $9.0 millionunrecognized 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.
The Company recognizes estimated interest payable relating to Canadian operations exists atincome taxes in Other Interest Expense and estimated penalties relating to income taxes in Other Income. The Company has accrued interest of $0.5 million through September 30, 2006. Although realization2008 and has not accrued any penalties.
The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is not assured, management determinedcurrently conducting an examination of the Company for fiscal 2008 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 it is more likely than not that future taxable income will be generatedintended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2005 and later years, IRS examinations for fiscal 2007 and prior years have been completed and the Company believes such years are effectively settled.
For the major states in Canada to fully utilize this asset, andwhich the various subsidiary companies operate, the earliest tax year open for examination is as such, no valuation allowance was provided.follows:
| | |
| New York | | Fiscal 2002 |
| Pennsylvania | | Fiscal 2003 |
| California | | Fiscal 2004 |
| Texas | | Fiscal 2004 |
82
Note E — Capitalization and Short-Term BorrowingsNATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| 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, 2003 | | | 81,438 | | | $ | 81,438 | | | $ | 478,799 | | | $ | 642,690 | | | $ | (65,537 | ) | |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | 166,586 | | | | | | |
| Dividends Declared on Common Stock ($1.10 Per Share) | | | | | | | | | | | | | | | (90,350 | ) | | | | | |
| Other Comprehensive Income, Net of Tax | | | | | | | | | | | | | | | | | | | 10,762 | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | 1,552 | | | | 1,552 | | | | 27,761 | | | | | | | | | | |
| | | | | | | | | | | | | |
| Balance at September 30, 2004 | | | 82,990 | | | | 82,990 | | | | 506,560 | | | | 718,926 | | | | (54,775 | ) | |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | 189,488 | | | | | | |
| Dividends Declared on Common Stock ($1.14 Per Share) | | | | | | | | | | | | | | | (95,394 | ) | | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | (142,853 | ) | |
| Cancellation of Shares | | | (2 | ) | | | (2 | ) | | | (52 | ) | | | | | | | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | 1,369 | | | | 1,369 | | | | 23,326 | | | | | | | | | | |
| | | | | | | | | | | | |
| Balance at September 30, 2005 | | | 84,357 | | | | 84,357 | | | | 529,834 | | | | 813,020 | | | | (197,628 | ) | | | 84,357 | | | $ | 84,357 | | | $ | 529,834 | | | $ | 813,020 | | | $ | (197,628 | ) |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | 138,091 | | | | | | | | | | | | | | | | | | | | 138,091 | | | | | |
| Dividends Declared on Common Stock ($1.18 Per Share) | | | | | | | | | | | | | | | (98,829 | ) | | | | | | | | | | | | | | | | | | | (98,829 | ) | | | | |
| Other Comprehensive Income, Net of Tax | | | | | | | | | | | | | | | | | | | 228,044 | | | | | | | | | | | | | | | | | | | | 228,044 | |
| Share-Based Payment Expense(2) | | | | | | | | | | | 1,705 | | | | | | | | | | | | | | | | | | | | 1,705 | | | | | | | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | 1,572 | | | | 1,572 | | | | 28,564 | | | | | | | | | | | | 1,572 | | | | 1,572 | | | | 28,564 | | | | | | | | | |
| Share Repurchases | | | (2,526 | ) | | | (2,526 | ) | | | (16,373 | ) | | | (66,269 | ) | | | | | | | (2,526 | ) | | | (2,526 | ) | | | (16,373 | ) | | | (66,269 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Balance at September 30, 2006 | | | 83,403 | | | $ | 83,403 | | | $ | 543,730 | | | $ | 786,013 | (3) | | $ | 30,416 | | | | 83,403 | | | | 83,403 | | | | 543,730 | | | | 786,013 | | | | 30,416 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | | 337,455 | | | | | |
| Dividends Declared on Common Stock ($1.22 Per Share) | | | | | | | | | | | | | | | | (101,496 | ) | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | | (24,137 | ) |
| Adjustment to Recognize the Funded Position of the Pension and Other Post-Retirement Benefit Plans | | | | | | | | | | | | | | | | | | | | (12,482 | ) |
| Share-Based Payment Expense(2) | | | | | | | | | | | | 3,727 | | | | | | | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | | 1,367 | | | | 1,367 | | | | 30,193 | | | | | | | | | |
| Share Repurchases | | | | (1,309 | ) | | | (1,309 | ) | | | (8,565 | ) | | | (38,196 | ) | | | | |
| | | | | | | | | | | | | |
| Balance at September 30, 2007 | | | | 83,461 | | | | 83,461 | | | | 569,085 | | | | 983,776 | | | | (6,203 | ) |
| | | | | | | | | | | | | |
| Net Income Available for Common Stock | | | | | | | | | | | | | | | | 268,728 | | | | | |
| Dividends Declared on Common Stock ($1.27 Per Share) | | | | | | | | | | | | | | | | (103,523 | ) | | | | |
| Cumulative Effect of the Adoption of FIN 48 | | | | | | | | | | | | | | | | (406 | ) | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | | 9,166 | |
| Share-Based Payment Expense(2) | | | | | | | | | | | | 2,332 | | | | | | | | | |
| Common Stock Issued Under Stock and Benefit Plans(1) | | | | 854 | | | | 854 | | | | 33,335 | | | | | | | | | |
| Share Repurchases | | | | (5,194 | ) | | | (5,194 | ) | | | (37,036 | ) | | | (194,776 | ) | | | | |
| | | | | | | | | | | | | |
| Balance at September 30, 2008 | | | | 79,121 | | | $ | 79,121 | | | $ | 567,716 | | | $ | 953,799 | (3) | | $ | 2,963 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Paid in Capital includes tax benefits of $6.5$16.3 million, $3.7$13.7 million and $1.5$6.5 million for September 30, 2006, 20052008, 2007 and 2004,2006, respectively, associated with the exercise of stock options. |
| |
| (2) | | As of October 1, 2005, Paid in Capital includes compensation costs associated with stock option, andstock-settled SARs and/or restricted stock awards, in accordance with SFAS 123R. 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, 2006, $692.72008, $808.8 million of accumulated earnings was free of such limitations. |
8283
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 2006,2008, the Company issued 2,292,639890,944 original issue shares of common stock as a result of stock option exercises and 16,00025,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R). 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 2006, 744,5672008, 72,205 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 Programdirector stock program under which it issues shares of the Company common stock to itsthe 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. Under this program, the Company issued 8,4009,600 original issue shares of common stock to the non-employee directors of the Company during 2006.2008.
OnIn December 8, 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 8eight million shares in the open market or through privately negotiated transactions. During 2006,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 2,526,5501,028,981 shares under this program,for $46.0 million through September 17, 2008. 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. All share repurchases mentioned above were funded with cash provided by operating activities. At September 30, 2006,activitiesand/or through the Company had made commitments to repurchase an additional 99,100 shares of common stock. These commitments were settled and recorded as a reductionuse of the Company’s outstanding shareslines of common stock in October 2006.credit.
Shareholder Rights Plan
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). Effective April 30, 1999, theThe Plan has been amended five times since it was amendedadopted and is now embodied in an Amended and Restated Rights Agreement undereffective July 11, 2008, which the Board of Directors made adjustments in connection with theis an Exhibit to this Annual Report andtwo-for-oneForm 10-K. stock split of September 7, 2001.
The holders of the Company’s common stock have one right (Right) for each of their shares. Each Right which willis initially be evidenced by the Company’s common stock certificates representing the outstanding shares of common stock, entitlesstock.
The Rights have anti-takeover effects because they will cause substantial dilution of the holder to purchase one-half of one share ofCompany’s common stock atif a purchase priceperson attempts to acquire the Company on terms not approved by the Board of $65.00 per share, being $32.50 per half share, subject to adjustment (Purchase Price)Directors (an Acquiring Person).
The Rights become exercisable upon the occurrence of a distribution date.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 distribution date,
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 number of shares of common stock (or, underdetermined in accordance with a Plan formula that is based on the current market value of the Company’s common stock. Under certain circumstances, each holder of a Right may instead receive other property of the Company) having a value equal to two times the Purchase Price of the Right then in effect.Company. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
A distribution dateDistribution 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
83
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 number of shares of common stock determined in accordance with a Plan formula based on the current market value of the acquiring company having a value equal to two times the Purchase PriceCompany’s common stock, or other property of the Right then in effect.Company. 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 announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company,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 announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company,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.
After a distribution date, Rights that are owned by an acquiring person will be null and void. 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, 2008,2018, unless earlier than that date, they are exchanged or redeemed earlier than thator the Plan is amended to extend the expiration date.
The Rights have anti-takeover effects because they will cause substantial dilution of the common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors.
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.
8485
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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, 2005 | | | 10,996,893 | | | $ | 23.78 | | | | | | | | | |
| Granted in 2006 | | | 317,000 | | | $ | 35.21 | | | | | | | | | |
| Exercised in 2006 | | | (2,292,639 | ) | | $ | 21.77 | | | | | | | | | |
| Forfeited in 2006 | | | (5,000 | ) | | $ | 24.94 | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Outstanding at September 30, 2006 | | | 9,016,254 | | | $ | 24.69 | | | | 4.21 | | | $ | 105,096 | |
| | | | | | | | | | | | | | | | | |
| Option shares exercisable at September 30, 2006 | | | 8,643,753 | | | $ | 24.32 | | | | 4.01 | | | $ | 103,999 | |
| | | | | | | | | | | | | | | | | |
| Option shares available for future grant at September 30, 2006(1) | | | 434,911 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | 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 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | |
| (1) | | Including shares available for stock-settled SARs and restricted stock grants. |
The following table summarizes information about options outstanding at September 30, 2006:Transactions involving non-performance based stock-settled SARs for all plans are summarized as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | | Options Outstanding | | | Options Exercisable | |
| | | | | | Weighted
| | | | | | | | | | |
| | | Number
| | | Average
| | | Weighted
| | | Number
| | | Weighted
| |
| | | Outstanding
| | | Remaining
| | | Average
| | | Exercisable
| | | Average
| |
| | | at
| | | Contractual
| | | Exercise
| | | at
| | | Exercise
| |
Range of Exercise Price | | 9/30/06 | | | Life | | | Price | | | 9/30/06 | | | Price | |
| |
| $18.55-$22.26 | | | 1,598,641 | | | | 3.3 | | | $ | 21.31 | | | | 1,568,641 | | | $ | 21.32 | |
| $22.27-$25.97 | | | 4,500,219 | | | | 3.5 | | | $ | 23.33 | | | | 4,480,718 | | | $ | 23.32 | |
| $25.98-$29.68 | | | 2,600,394 | | | | 5.3 | | | $ | 27.85 | | | | 2,594,394 | | | $ | 27.85 | |
| $29.69-$33.39 | | | — | | | | — | | | | — | | | | — | | | | — | |
| $33.40-$37.10 | | | 317,000 | | | | 9.6 | | | $ | 35.21 | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | 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 | | | — | | | | — | | | | — | | | $ | — | |
| | | | | | | | | | | | | | | | | |
86
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 | | | — | | | | — | | | | — | | | $ | — | |
| | | | | | | | | | | | | | | | | |
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.
85
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Transactions involving optionrestricted 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, 2005 | | | 64,928 | | | $ | 24.46 | |
| Granted in 2006 | | | 16,000 | | | $ | 34.94 | |
| Vested in 2006 | | | (38,600 | ) | | $ | 24.43 | |
| | | | | | | | | |
| Restricted Share Awards Outstanding at September 30, 2006 | | | 42,328 | | | $ | 28.44 | |
| | | | | | | | | |
| | | | | | | | | |
| | | 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 | |
| | | | | | | | | |
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 20062008 will lapse as follows: 2007 — 25,000 shares; 20082009 — 2,500 shares; 2009 — 4,500 shares; 2010 — 5,82828,828 shares; 2011 — 2,500 shares; 2012 — 5,000 shares; 2013 — 5,000 shares; 2014 — 5,000 shares; 2015 — 5,000 shares; and 20112016 — 4,5005,000 shares.
Redeemable Preferred Stock
As of September 30, 2006,2007, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
87
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 | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Medium-Term Notes(1): | | | | | | | | | | | | | | | | |
| 6.0% to 7.50% due May 2008 to June 2025 | | $ | 749,000 | | | $ | 749,000 | | |
| 6.0% to 7.50% due March 2009 to June 2025 | | | $ | 549,000 | | | $ | 749,000 | |
| Notes(1): | | | | | | | | | | | | | | | | |
| 5.25% to 6.50% due March 2013 to September 2022(2) | | | 346,665 | | | | 347,222 | | |
| 5.25% to 6.5% due March 2013 to September 2022(2) | | | | 550,000 | | | | 250,000 | |
| | | | | | | | | | | |
| | | | 1,095,665 | | | | 1,096,222 | | | | 1,099,000 | | | | 999,000 | |
| | | | | | | | | | | |
| Other Notes: | | | | | | | | | | | | | | | | |
| Secured(3) | | | 22,766 | | | | 32,100 | | |
| Unsecured | | | 169 | | | | 83 | | | | — | | | | 24 | |
| | | | | | | | | | | |
| Total Long-Term Debt | | | 1,118,600 | | | | 1,128,405 | | | | 1,099,000 | | | | 999,024 | |
| Less Current Portion | | | 22,925 | | | | 9,393 | | | | 100,000 | | | | 200,024 | |
| | | | | | | | | | | |
| | | $ | 1,095,675 | | | $ | 1,119,012 | | | $ | 999,000 | | | $ | 799,000 | |
| | | | | | | | | | | |
| | |
| (1) | | TheseThe medium-term notes and notes are unsecured. |
| |
| (2) | | At September 30, 2006 and 2005, $96,665,000 and $97,222,000, respectively,In April 2008, the Company issued $300.0 million of these6.50% senior, unsecured notes were callable at par at any time after September 15, 2006.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 amount outstanding from yearprincipal amount. In addition, the Company is required to year is attributableeither offer to the estates of individual note holders exercising put options due to the death of an individual note holder. |
|
(3) | | These notes constitute “project financing” and are secured by the various project documentation and natural gas transportation contracts related to the Empire State Pipeline. The interest rate on these notes is a variable rate based on LIBOR. It is the Company’s intention to pay off these notes within one year. As such,exchange the notes have been classified as current.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. |
86
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As of September 30, 2006,2008, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $22.9 million in 2007, $200.0 million in 2008, $100.0 million in 2009, zero in 2010, $200.0 million in 2011, $150.0 million in 2012, $250.0 million in 2013, and $595.7$399.0 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 (bi-lateral) 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 $445.0$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 which is committed to the Companythat extends through September 30, 2010.
At September 30, 20062008 and September 30, 2005,2007, the Company had no outstanding short-term notes payable to banks or commercial paper.
88
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 from September 30, 2005 through September 30, 2010. At September 30, 2006,2008, the Company’s debt to capitalization ratio (as calculated under the facility) was .44..41. The constraints specified in the committed credit facility would permit an additional $1.56$1.88 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, 2006,2008, the Company would have been permitted to issue up to a maximum of $1.03$1.3 billion 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 1974 indenture pursuant to which $399.0$199.0 million (or 36%18%) of the Company’s long-term debt (as of September 30, 2006)2008) 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 or 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 failsfail 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
87
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2006,2008, the Company had no debt outstanding under the committed credit facility.
Note F — Financial Instruments
| |
| Note F — | Financial Instruments |
Fair Values
The fair market value of the Company’s long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
| | | | | | | | | | | | | | | | | |
| | | At September 30 | |
| | | 2006 Carrying
| | | 2006 Fair
| | | 2005 Carrying
| | | 2005 Fair
| |
| | | Amount | | | Value | | | Amount | | | Value | |
| | | (Thousands) | |
| |
| Long-Term Debt | | $ | 1,118,600 | | | $ | 1,148,089 | | | $ | 1,128,405 | | | $ | 1,181,599 | |
| | | | | | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | | | | | |
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay.
Temporary cash investments, notes payable to banks and commercial paper are stated at cost, which approximates their fair value due to the short-term maturities of those financial instruments. Investments in life
89
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 includesinclude cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The cash surrender values of the insurance contracts amounted to $62.5$53.6 million and $59.6$54.7 million at September 30, 20062008 and 2005,2007, respectively. The fair value of the equity mutual fund was $12.9$12.4 million and $9.8$14.7 million at September 30, 20062008 and September 30, 2005,2007, respectively. The gross unrealized gainloss on this equity mutual fund was $1.0 million and $0.4$(1.0) million at September 30, 2006 and September 30, 2005, respectively. During 2005, the Company sold all of its interest in one2008. The equity mutual fund for $8.5was in a gross unrealized gain position of $2.2 million and reinvested the proceeds in another equity mutual fund. The Company recognized a gain of $0.7 million on the sale of the equity mutual fund.at September 30, 2007. The fair value of the stock of an insurance company was $12.7$14.5 million and $10.5$16.3 million at September 30, 20062008 and 2005,2007, respectively. The gross unrealized gain on this stock was $10.3$12.1 million and $8.1$13.8 million at September 30, 20062008 and 2005,2007, 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 of derivative financial instruments to manage a portion of the market risk associated with the fluctuations in the price of natural gas and crude oil. These instruments include price swap agreements, no cost collars options 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 “Inside FERC.”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 production in the Exploration and Production segment and the All Other category. The Energy Marketing segment accounts for these derivative financial instruments as fair value hedges and uses them to hedge against falling prices, a risk to which they are
88
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 price sales commitments. At September 30, 2006,2008, the Company had natural gas price swap agreements covering a notional amount of 7.415.1 Bcf extending through 20092011 at a weighted average fixed rate of $7.24$9.69 per Mcf. Of this amount, 1.10.9 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $6.98$9.64 per Mcf. The remaining 6.314.2 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $7.29$9.69 per Mcf. At September 30, 2006,2008, the Company would have had to payreceived a net $7.4$20.3 million to terminate the price swap agreements. The Company also had crude oil price swap agreements covering a notional amount of 900,0001,920,000 bbls extending through 20082011 at a weighted average fixed rate of $37.13$90.50 per bbl. At September 30, 2006,2008, the Company would have had to pay a net $27.6$0.8 million to terminate the price swap agreements.
Under the no cost collars, the Company receives monthly payments from (or makes payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). The variable price is either a crude oil price quoted on the NYMEX or a quotedEnergy Marketing segment also used natural gas swaps to hedge basis risk on their fixed price in “Inside FERC.” These derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price range for the anticipated sale of natural gas and crude oil production in the Exploration and Production segment.purchase commitments. At September 30, 2006,2008, the Company had no cost collars on natural gas swap agreements covering a notional amount of 7.11.4 Bcf extending through 2008 withat a weighted average floor pricefixed rate of $8.26 per Mcf and a weighted average ceiling price of $17.25$0.47 per Mcf. At September 30, 2006,These are treated as fair value hedges and the Company would have received $10.4had to pay $0.2 million at September 30, 2008 to terminate the no cost collars. At September 30, 2006, the Company had no cost collars on crude oil covering a notional amount of 180,000 bbls extending through 2007 with a weighted average floor price of $70.00 per bbl and a weighted average ceiling price of $77.00 per bbl. At September 30, 2006, the Company would have received $0.9 million to terminate these no cost collars.agreements.
At September 30, 2006,2008, the Company had long (purchased) futures contracts covering 14.59.1 Bcf of gas extending through 2012 at a weighted average contract price of $9.20$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 $22.4$9.9 million to terminate these futures contracts at September 30, 2006.2008.
90
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
At September 30, 2006,2008, the Company had short (sold) futures contracts covering 7.56.7 Bcf of gas extending through 20092010 at a weighted average contract price of $10.57$11.02 per Mcf. Of this amount, 4.73.5 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 2.83.2 Bcf is accounted for as fair value hedges.hedges used to hedge against falling prices on their fixed price gas purchasing commitments and hedge against decreases in natural gas prices associated with the eventual sale of gas in storage. The Company would have received $17.5$18.6 million to terminate these futures contracts at September 30, 2006.2008.
The Company may be exposed to credit risk on someany of the derivative financial instruments discussed above.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 ongoing basis monitors counterparty credit exposure. Management has obtained guarantees from many of the parent companies of the respective counterparties to its derivative financial instruments. At September 30, 2006,2008, the Company used sixhad eleven counterparties for its over the counter derivative financial instruments. At September 30, 2006,instruments and no individual counterparty represented greater than 39%42% of total credit risk (measured as volumes hedged by an individual counterparty as a percentage of the Company’s total over the counter volumes hedged). AllThe Company recorded a $0.6 million reduction to the fair market value of its derivative contracts that are in a gain position based on its assessment of counterparty credit risk. This credit reserve was determined by applying default probabilities to the counterparties (oranticipated cash flows that the parent of the counterparty) were rated as investment grade entities at September 30, 2006.Company is expecting from its counterparties.
The Company uses an interest rate collar to limit interest rate fluctuations on certain variable rate debt in the Pipeline and Storage segment. Under the interest rate collar the Company makes quarterly payments to (or receives payments from) another party when a variable rate falls below an established floor rate (the Company
89
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
pays the counterparty) or exceeds an established ceiling rate (the Company receives payment from the counterparty). Under the terms of the collar, which extends until 2009, the variable rate is based on LIBOR. The floor rate of the collar is 5.15% and the ceiling rate is 9.375%. At September 30, 2006 the notional amount on the collar was $25.7 million. The Company would have had to pay $0.1 million to terminate the interest rate collar at September 30, 2006.
Note G — Retirement Plan and Other Post-Retirement Benefits
| |
| Note G — | Retirement Plan and Other Post-Retirement Benefits |
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers approximately 77%65% of the domestic 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 $0.2 million, $0.2 million and $0.1 million of costs occurring in 2008, 2007 and 2006, respectively). Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans were $4.0 million, $4.1 million, and $4.1 million for the years ended September 30, 2008, 2007 and 2006, respectively.
The Company provides health care and life insurance benefits (other post-retirement benefits) for substantially all domestica majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees under a post-retirement benefit plan (Post-Retirement Plan).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 Post-Retirement Plan.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 health care and life insurance benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its Post-Retirement Plan.other post-retirement benefits. They are separate accounts within the Retirement Plan used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan, 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 investments accumulate tax-free.regulations. Retirement Plan, VEBA trust and Post-Retirement Plan401(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 returnsreturn on plan assets, a component of net periodic benefit cost shown in the Retirement Plan and Post-Retirement Plan aretables below, is applied to the market-related value of plan assets of the respective plans.assets. The market-related valuesvalue of the Retirement Plan and Post-Retirement Planplan assets areis 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 Post-Retirement Planother post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is June 30, 2006, 20052008, 2007 and 2004,2006, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Retirement Plan | | | Other Post-Retirement Benefits | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | | |
| Benefit Obligation at Beginning of Period | | $ | 825,204 | | | $ | 693,532 | | | $ | 694,960 | | | $ | 546,273 | | | $ | 422,003 | | | $ | 467,418 | |
| Service Cost | | | 16,416 | | | | 13,714 | | | | 14,598 | | | | 8,029 | | | | 6,153 | | | | 6,027 | |
| Interest Cost | | | 40,196 | | | | 42,079 | | | | 40,565 | | | | 26,804 | | | | 25,783 | | | | 26,393 | |
| Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 1,559 | | | | 1,017 | | | | 627 | |
| Actuarial (Gain) Loss | | | (108,112 | ) | | | 115,128 | | | | (19,593 | ) | | | (115,052 | ) | | | 110,663 | | | | (62,146 | ) |
| Benefits Paid | | | (41,497 | ) | | | (39,249 | ) | | | (36,998 | ) | | | (21,682 | ) | | | (19,346 | ) | | | (16,316 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation at End of Period | | $ | 732,207 | | | $ | 825,204 | | | $ | 693,532 | | | $ | 445,931 | | | $ | 546,273 | | | $ | 422,003 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
9092
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 | |
| | | 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value of Assets at Beginning of Period | | $ | 616,462 | | | $ | 573,366 | | | $ | 491,333 | | | $ | 271,636 | | | $ | 229,485 | | | $ | 166,494 | |
| Actual Return on Plan Assets | | | 68,649 | | | | 56,201 | | | | 81,946 | | | | 34,785 | | | | 20,577 | | | | 38,960 | |
| Employer Contribution | | | 20,907 | | | | 26,144 | | | | 37,085 | | | | 39,326 | | | | 39,903 | | | | 39,720 | |
| Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 1,559 | | | | 1,017 | | | | 627 | |
| Benefits Paid | | | (41,497 | ) | | | (39,249 | ) | | | (36,998 | ) | | | (21,682 | ) | | | (19,346 | ) | | | (16,316 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Assets at End of Period | | $ | 664,521 | | | $ | 616,462 | | | $ | 573,366 | | | $ | 325,624 | | | $ | 271,636 | | | $ | 229,485 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Reconciliation of Funded Status | | | | | | | | | | | | | | | | | | | | | | | | |
| Funded Status | | $ | (67,686 | ) | | $ | (208,742 | ) | | $ | (120,166 | ) | | $ | (120,307 | ) | | $ | (274,637 | ) | | $ | (192,518 | ) |
| Unrecognized Net Actuarial Loss | | | 107,626 | | | | 257,553 | | | | 159,554 | | | | 54,487 | | | | 205,423 | | | | 108,943 | |
| Unrecognized Transition Obligation | | | — | | | | — | | | | — | | | | 49,890 | | | | 57,017 | | | | 64,144 | |
| Unrecognized Prior Service Cost | | | 7,185 | | | | 8,142 | | | | 9,171 | | | | 12 | | | | 17 | | | | 20 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Amount Recognized at End of Period | | $ | 47,125 | | | $ | 56,953 | | | $ | 48,559 | | | $ | (15,918 | ) | | $ | (12,180 | ) | | $ | (19,411 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts Recognized in the Balance Sheets Consist of: | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued Benefit Liability | | $ | — | | | $ | (117,103 | ) | | $ | (43,147 | ) | | $ | (32,918 | ) | | $ | (26,584 | ) | | $ | (27,263 | ) |
| Prepaid Benefit Cost | | | 47,125 | | | | — | | | | — | | | | 17,000 | | | | 14,404 | | | | 7,852 | |
| Intangible Assets | | | — | | | | 8,142 | | | | 9,171 | | | | — | | | | — | | | | — | |
| Accumulated Other Comprehensive Loss (Pre-Tax) | | | — | | | | 165,914 | | | | 82,535 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Amount Recognized at End of Period | | $ | 47,125 | | | $ | 56,953 | | | $ | 48,559 | | | $ | (15,918 | ) | | $ | (12,180 | ) | | $ | (19,411 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount Rate | | | 6.25 | % | | | 5.00 | % | | | 6.25 | % | | | 6.25 | % | | | 5.00 | % | | | 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 | | $ | 16,416 | | | $ | 13,714 | | | $ | 14,598 | | | $ | 8,029 | | | $ | 6,153 | | | $ | 6,027 | |
| Interest Cost | | | 40,196 | | | | 42,079 | | | | 40,565 | | | | 26,804 | | | | 25,783 | | | | 26,393 | |
| Expected Return on Plan Assets | | | (49,943 | ) | | | (49,545 | ) | | | (48,281 | ) | | | (22,302 | ) | | | (18,862 | ) | | | (14,898 | ) |
| Amortization of Prior Service Cost | | | 957 | | | | 1,029 | | | | 1,103 | | | | 4 | | | | 4 | | | | 4 | |
| Amortization of Transition Amount | | | — | | | | — | | | | — | | | | 7,127 | | | | 7,127 | | | | 7,127 | |
| Recognition of Actuarial Loss | | | 23,108 | | | | 10,473 | | | | 9,438 | | | | 23,402 | | | | 12,467 | | | | 17,092 | |
| Net Amortization and Deferral for Regulatory Purposes | | | (6,409 | ) | | | 1,988 | | | | 722 | | | | (11,084 | ) | | | (410 | ) | | | (9,731 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Periodic Benefit Cost | | $ | 24,325 | | | $ | 19,738 | | | $ | 18,145 | | | $ | 31,980 | | | $ | 32,262 | | | $ | 32,014 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change In Additional Minimum Liability Recognition | | $ | (165,914 | ) | | $ | 83,379 | | | $ | (56,612 | ) | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
9193
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Retirement Plan | | | Other Post-Retirement Benefits | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
| Discount Rate | | | 5.00 | % | | | 6.25 | % | | | 6.00 | % | | | 5.00 | % | | | 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) | | The weighted average discount rate was 6.0% through 12/8/2003. Subsequent to 12/8/2003,In Fiscal 2008, the discount rate used was 6.25%.Company passed an amendment, 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 costCost 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 106 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) 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.
95
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The amounts recognized in accumulated other comprehensive loss, regulatory assets, and regulatory liabilities in fiscal 2008, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2009 are presented in the table below:
| | | | | | | | | | | | | |
| | | | | | Other
| | | | |
| | | Retirement
| | | Post-Retirement
| | | Non-Qualified
| |
| | | Plan | | | Benefits | | | Benefit Plan | |
| | | (Thousands) | |
| |
Amounts Recognized In Accumulated Other Comprehensive Loss, Regulatory Assets and Regulatory Liabilities(1) | | | | | | | | | | | | |
| Net Actuarial Gain/(Loss) | | $ | (71,637 | ) | | $ | (53,108 | ) | | $ | (13,530 | ) |
| Transition Obligation | | | — | | | | (11,326 | ) | | | — | |
| Prior Service (Cost) Credit | | | (5,495 | ) | | | 7,561 | | | | (11 | ) |
| | | | | | | | | | | | | |
| Net Amount Recognized | | $ | (77,132 | ) | | $ | (56,873 | ) | | $ | (13,541 | ) |
| | | | | | | | | | | | | |
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 | ) |
| Transition Obligation | | | — | | | | (2,265 | ) | | | — | |
| Prior Service (Cost) Credit | | | (731 | ) | | | 1,074 | | | | — | |
| | | | | | | | | | | | | |
| Net Amount Expected to be Recognized | | $ | (6,407 | ) | | $ | (10,462 | ) | | $ | (1,322 | ) |
| | | | | | | | | | | | | |
| | |
| (1) | | Amounts presented are shown before recognizing deferred taxes. |
In accordance with the provisions of SFAS 87, the Company recorded an additional minimum pension liability at September 30, 2005 and 2004 representing the excess of the accumulated benefit obligation over the fair value of plan assets plus accrued amounts previously recorded. An intangible asset as shown in the table above, 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 the change in accumulated other comprehensive (income) loss related to the additional minimum pension liability adjustment at September 30, 2006 2005 and 2004 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 planRetirement Plan were as follows:
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | 2008 | | 2007 | | 2006 | |
| | | 2006 | | 2005 | | 2004 | | | (Thousands) | |
| |
| Projected Benefit Obligation | | $ | 732,207 | | | $ | 825,204 | | | $ | 693,532 | | | $ | 719,059 | | | $ | 742,519 | | | $ | 732,207 | |
| Accumulated Benefit Obligation | | $ | 660,026 | | | $ | 733,565 | | | $ | 616,513 | | | $ | 659,004 | | | $ | 672,340 | | | $ | 660,026 | |
| Fair Value of Plan Assets | | $ | 664,520 | | | $ | 616,462 | | | $ | 573,366 | | | $ | 695,089 | | | $ | 765,144 | | | $ | 664,520 | |
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. 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. The effect of the discount rate change for the Retirement Plan in 2005 was to increase the projected benefit obligation by $113.0 million. The discount rate change for the Retirement Plan in 2004 caused the projected benefit obligation to decrease by $20.2 million.
96
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company made cash contributions totaling $20.9$16.0 million to the Retirement Plan during the year ended September 30, 2006.2008. The Company expects that the annual contribution to the Retirement Plan in 20072009 will be in the range of $15.0 million to $20.0 million. As a result of the recent downturn in the stock markets and general economic conditions, it is likely that the Company will have to fund larger amounts to the Retirement Plan subsequent to 2009 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: $45.2 million in 2007; $46.1 million in 2008; $47.3$50.5 million in 2009; $48.7$51.0 million in 2010; $50.0$51.4 million in 2011; $51.9 million in 2012; $52.9 million in 2013; and $275.6$286.7 million in the five years thereafter.
92
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Retirement Plan covers certain domestic employees hired before July 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 $0.2 million through September 30, 2006 (with $0.1 million of costs occurring in fiscal 2006). Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans were $4.1 million, $4.2 million, and $4.2 million for the years ended September 30, 2006, 2005 and 2004, respectively.
In addition to the Retirement Plan discussed above, the Company also has a Non 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 $5.0 million, $5.5 million and $5.4 million $4.3in 2008, 2007 and 2006, respectively. At September 30, 2008, an $8.0 million and $13.7 million(pre-tax) loss was included in 2006, 2005 and 2004, respectively.accumulated other comprehensive income (loss) on the Consolidated Balance Sheet. This was first recognized in 2007 upon adoption of SFAS 158. There were no amounts recognized in other comprehensive income (loss) attributable to the recognition of an additional minimum liability for 2006. The accumulated benefit obligation for this plan was $26.5$31.8 million and $25.2$28.8 million at September 30, 20062008 and 2005,2007, respectively. The projected benefit obligation for the plan was $44.5$47.5 million and $47.6$43.8 million at September 30, 20062008 and 2005,2007, respectively. The actuarial valuations for this plan were determined based on a discount rate of 6.25%6.75%, 5.0%6.25% and 6.25% as of September 30, 2006, 20052008, 2007 and 2004,2006, respectively; a rate of compensation increase of 10.0% as of September 30, 2006, 20052008, 2007 and 2004;2006; and an expected long-term rate of return on plan assets of 8.25% at September 30, 2006, 20052008, 2007 and 2004.2006.
In January 2004, a participantThe effect of the Non Qualified benefit plan received a $23 million lump sum payment under a provision of an agreement previously entered into betweendiscount rate change in 2008 was to decrease the Company and the participant. Under GAAP, this payment was considered a partial settlement of the projectedother 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 plan. Accordingly, GAAP required that a pro rata portionother 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 this plan’s unrecognizedthese assumption changes was to increase the other post-retirement benefit obligation by $8.6 million. Other actuarial loses resulting from experience different from that assumed and from changesdecreased the other post-retirement benefit obligation in assumption be currently recognized. Therefore, $9.9 million before tax ($6.4 million, after tax) was recognized as a settlement expense (included in Operation and Maintenance Expense) on the income statement.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.
The effect of the discount rate change in 2005 was to increase the other post-retirement benefit obligation by $78.2 million. Effective July 1, 2005, 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 $21.7 million. Also effective July 1, 2005, the percent of active female participants who are assumed to be married at retirement was changed. The effect of this assumption change was to decrease the other post-retirement benefit obligation by $6.9 million. Other actuarial experience increased the other post-retirement benefit obligation in 2005 by $17.9 million.
On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introducesintroduced 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 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”, since 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. The discount rate was changed from 6.0% to 6.25% per annum as of the remeasurement date, which resulted in a decrease in the benefit obligation of $15.9 million in 2004. The other post-retirement benefit obligation decreased by $42.9 million and the Net Periodic Post-Retirement Benefit Cost
9397
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
decreased by $4.2 million as a result of the Act for 2004. Effective July 1, 2004, the Medicare B Reimbursement trend assumption was changed. The effect of this change was to decrease the other post-retirement benefit obligation by $3.5 million for 2004.
The estimated gross benefit payments and gross amount of subsidy receipts are as follows:
| | | | | | | | | |
| | | Benefit Payments | | | Subsidy Receipts | |
| |
| First Year | | $ | 22,994,788 | | | $ | (1,475,584 | ) |
| Second Year | | $ | 24,993,192 | | | $ | (1,712,545 | ) |
| Third Year | | $ | 26,857,371 | | | $ | (1,959,704 | ) |
| Fourth Year | | $ | 28,913,929 | | | $ | (2,191,014 | ) |
| Fifth Year | | $ | 30,877,647 | | | $ | (2,413,305 | ) |
| Next Five Years | | $ | 175,465,690 | | | $ | (15,964,373 | ) |
| | | | | | | | | |
| | | Benefit Payments | | | Subsidy Receipts | |
| |
| 2009 | | $ | 26,210,000 | | | $ | (1,714,000 | ) |
| 2010 | | $ | 28,248,000 | | | $ | (1,942,000 | ) |
| 2011 | | $ | 30,122,000 | | | $ | (2,167,000 | ) |
| 2012 | | $ | 31,484,000 | | | $ | (2,437,000 | ) |
| 2013 | | $ | 32,687,000 | | | $ | (2,719,000 | ) |
| 2014 through 2018 | | $ | 181,354,000 | | | $ | (17,304,000 | ) |
| | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| |
| Rate of Increase for Pre Age 65 Participants | | | 9.0 | %(1) | | | 8.0 | %(2) | | | 9.0 | %(2) |
| Rate of Increase for Post Age 65 Participants | | | 7.0 | %(1) | | | 6.67 | %(2) | | | 7.0 | %(2) |
| Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits | | | 10.0 | %(1) | | | 10.0 | %(2) | | | 11.0 | %(2) |
| Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement | | | 7.0 | %(1) | | | 7.0 | %(3) | | | 5.25 | %(4) |
The annual rate of increase in the per capita cost of covered medical care benefits for both Pre and Post age 65 participants was assumed to be 10.0% for 2004. In 2005, the Company began making separate estimates of the annual rate of increase in the per capita cost of covered medical care benefits for Pre and Post age 65 participants. The rate of increase for Pre age 65 participants was assumed to be 10% while the rate of increase for Post age 65 participants was assumed to be 7.5%. In 2006, the rate of increase for Pre age 65 participants was 9% and was assumed to gradually decline to 5.0% by the year 2014. The rate of increase for the Post age 65 participants was 7.0% and was assumed to gradually decline to 5.0% by the year 2014. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 12.0% for 2004, 12.5% for 2005, 11.0% for 2006, and gradually decline to 5.0% by the year 2014 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 9.25% for 2004, 6.0% for 2005, and 5.25% for 2006. The annual rate of increase for the Medicare Part B Reimbursement is expected to fluctuate between 0% and 5.0% over the next 10 years and reach 5.0% by 2016.
| | |
| (1) | | It was assumed that this rate would gradually decline to 5.0% by 2018. |
|
| (2) | | It was assumed that this rate would gradually decline to 5.0% by 2014. |
|
| (3) | | It was assumed that this rate would gradually decline to 5.0% by 2016. |
|
| (4) | | It was assumed that this rate would gradually decline to 5.0% by 2017. |
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 Obligationother post-retirement benefit obligation as of October 1, 20062008 would be increasedincrease by $57.3$45.1 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 20062008 by $6.1$4.7 million. If the health care cost trend rates were decreased by 1% in each year, the Other Post-Retirement Benefit Obligationother post-retirement benefit obligation as of October 1, 20062008 would be decreaseddecrease by $47.5$38.4 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 20062007 by $4.9$3.9 million.
The Company made cash contributions including payments made directly to participants totaling $39.3$29.1 million to the Post-Retirement PlanVEBA trusts and 401(h) accounts during the year ended September 30, 2006.2008. In addition, the Company made direct payments of $0.1 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2008. The Company expects that the annual contribution to the Post-Retirement PlanVEBA trusts and 401(h) accounts in 20062009 will be in the range of $35.0$25.0 million to $45.0$30.0 million.
The Company’s Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2006, 20052008, 2007 and 20042006 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 | | 2007 | | 2006 | | 2005 | | 2004 | | | 2009 | | 2008 | | 2007 | | 2006 | |
| |
| Equity Securities | | | 60-75 | % | | | 67 | % | | | 63 | % | | | 61 | % | | | 60-75 | % | | | 67 | % | | | 70 | % | | | 67 | % |
| Fixed Income Securities | | | 20-35 | % | | | 26 | % | | | 28 | % | | | 28 | % | | | 20-35 | % | | | 29 | % | | | 24 | % | | | 26 | % |
| Other | | | 0-15 | % | | | 7 | % | | | 9 | % | | | 11 | % | | | 0-15 | % | | | 4 | % | | | 6 | % | | | 7 | % |
| | | | | | | | | | | | | | | |
| Total | | | | | | | 100 | % | | | 100 | % | | | 100 | % | | | | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | |
9498
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company’s Post-Retirement Plan weighted average asset allocations for its VEBA trusts and 401(h) accounts at September 30, 2006, 20052008, 2007 and 20042006 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 | | 2007 | | 2006 | | 2005 | | 2004 | | | 2009 | | 2008 | | 2007 | | 2006 | |
| |
| Equity Securities | | | 85-100 | % | | | 93 | % | | | 92 | % | | | 91 | % | | | 85-100 | % | | | 93 | % | | | 95 | % | | | 95 | % |
| Fixed Income Securities | | | 0-15 | % | | | 1 | % | | | 2 | % | | | 1 | % | | | 0-15 | % | | | 2 | % | | | 1 | % | | | 1 | % |
| Other | | | 0-15 | % | | | 6 | % | | | 6 | % | | | 8 | % | | | 0-15 | % | | | 5 | % | | | 4 | % | | | 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 Post-Retirement Plan VEBA trusts401(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 Post-Retirement PlanCompany’s other post-retirement benefits is 6.25%6.75% as of September 30, 2006. This2008. 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 equalthen determined based on the spot interest rate that results in the same present value when applied to the Moody’s Aa Long-Term Corporate Bond index, rounded to the nearest 25 basis points. The duration of the securities underlying that index (approximately 13 years) reasonably matches the expected timing ofsame anticipated future benefit payments (approximately 12 years).payments.
| |
| Note H — | Commitments and Contingencies |
Note H — 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.
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. TheAt September 30, 2008, the Company has estimated its remainingclean-up costs related to theformer manufactured gas plant sites described below in paragraphs (i) and (ii)third party waste disposal sites will be $3.8in the range of $19.4 million to $23.6 million. ThisThe minimum estimated liability of $19.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2006.2008. 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, adverse changes in environmental regulations, new information or other factors could adversely impact the Company.
99
(i) Former Manufactured Gas Plant SitesNATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| (i) | Former Manufactured Gas Plant Sites |
The Company has incurred or is incurringinvestigationclean-upand/orclean-up costs at fiveseveral former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing maintenance at one
95
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
site. At a second site in New York, the Company settled its environmental obligations related to this site during 2005. No future liability is anticipated at this site. At a third site, remediation is completemonitoring and long-term maintenance and monitoring activities are ongoing. A fourth site, which allegedly contains, among other things,at two sites.
With respect to another former manufactured gas plant waste, is insite, the investigation stage. Remediation and post-remedial construction care and maintenance have been completed at a fifth site, and the Company has been released from any future liability related to this site by the Pennsylvania Department of Environmental Protection.
(ii) Third Party Waste Disposal Sites
The Company has been identified by the Department of Environmental Conservation (DEC) or the United States Environmental Protection Agency as one of a number of companies considered to be PRPs with respect to two waste disposal sites in New York which were operated by unrelated third parties. The PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to the Company with respect to the remediation of these sites will depend on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion of responsibility, if any, attributed to the Company. The remediation has been completed at one site, with costs subject to an ongoing final reallocation process among five PRPs. At a second waste disposal site, settlement was reached in the amount of $9.3 million to be allocated among five PRPs. The allocation process is currently being determined. Further negotiations remain in process for additional settlements related to this site.
(iii) Other
The Company received, in 1998 and again in October 1999, notice that the DECNYDEC believes the Company is responsible for contamination discovered at an additional former manufactured gas plantthe site located in New York. TheYork for which the Company however, hashad 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 respondedfiled a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and, without admitting liability or fault, agreed to these notices that other companies operated that site before its predecessor did, that liability could be imposed upon it only if hazardous substances were disposed atthe terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site during a period whenconsistent 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 was operatedfrom 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 its predecessor,the NYDEC after May 30, 2007 and that it was unawareany costs incurred by the New York Department of any such disposal.Health. The Company has not incurredreceived and does not expect to receive any estimates of such additional costs. The Company has submitted a Remedial Design/Remedial Action work plan to the NYDEC in accordance with the Order on Consent and has increased its recorded estimated minimum liability for this site to $16.5 million.
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 atunder 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 nor has it been able to reasonably estimate the probability or extent of potential liability.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: $793.5 million in 2007, $195.2 million in 2008, $48.9$793.2 million in 2009, $17.6$168.0 million in 2010, $9.9$55.6 million in 2011, $47.0 million in 2012, $21.6 million in 2013, and $68.8$100.7 million thereafter. 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: $8.1 million in 2007, $7.2 million in 2008, $6.0 million in 2009, $4.3$4.6 million in 2010, $2.7$3.6 million in 2011, $3.2 million in 2012, $2.5 million in 2013, and $15.7$12.4 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 matters arising in the normal course of business thatbusiness. 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.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
96
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 I — | Discontinued Operations |
On July 18, 2005,August 31, 2007, the Company, in its Exploration and Production segment, completed the sale of its entire 85.16% interestSECI, Seneca’s wholly owned subsidiary that operated in U.E.,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 district heating and electric generation business intax clearance certificate from the Bohemia regionCanadian government. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of the Czech Republic, to Czech Energy Holdings, a.s. for sales proceeds of approximately $116.3 million.December 31, 2007. The sale resulted in the recognition of a gain of approximately $25.8$120.3 million, net of tax, at September 30, 2005. Market conditions during 2005, including the increasing valuefourth quarter of 2007. SECI is engaged in the Czech currency as compared toexploration for, and the U.S. dollar, causeddevelopment and purchase of, natural gas and oil reserves in the valueprovinces of the assets of U.E. to increase, providing an opportunityAlberta, Saskatchewan and British Columbia in Canada. The decision to sell was based on lower than expected returns from the U.E. operations at a profit forCanadian oil and gas properties combined with difficulty in finding significant new reserves. Seneca will continue its exploration and development activities in Appalachia, the Company.Gulf of Mexico, and California. As a result of the decision to sell its majority interest in U.E.,SECI, the Company began presenting the Czech Republicall SECI operations which are primarily comprised of U.E., as discontinued operations in June 2005. U.E. wasduring the major componentfourth quarter of the Company’s International segment. With this change in presentation, the Company discontinued all reporting for an International segment.2007.
The following is selected financial information of the discontinued operations for U.E.:SECI:
| | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
| Operating Revenues | | $ | 124,840 | | | $ | 123,425 | |
| Operating Expenses | | | 103,155 | | | | 112,178 | |
| | | | | | | | | |
| Operating Income | | | 21,685 | | | | 11,247 | |
| | | | | | | | | |
| Other Income | | | 2,048 | | | | 1,992 | |
| Interest Expense | | | (558 | ) | | | (838 | ) |
| | | | | | | | | |
| Income before Income Taxes and Minority Interest | | | 23,175 | | | | 12,401 | |
| | | | | | | | | |
| Income Tax Expense | | | 10,331 | | | | (1,853 | ) |
| Minority Interest, Net of Taxes | | | 2,645 | | | | 1,933 | |
| | | | | | | | | |
| Income from Discontinued Operations | | | 10,199 | | | | 12,321 | |
| | | | | | | | | |
| Gain on Disposal, Net of Taxes of $1,612 | | | 25,774 | | | | — | |
| | | | | | | | | |
| Income from Discontinued Operations | | $ | 35,973 | | | $ | 12,321 | |
| | | | | | | | | |
| | | 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 | ) |
| | | | | | | | | |
101
NATIONAL FUEL GAS COMPANY
Note JNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Business Segment Information(Continued)
| |
| Note J — | Business Segment Information |
The Company hasreports financial results for five reportablebusiness segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Timber. The breakdown 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.
The Pipeline and Storage segment operations are regulated. The FERC regulates the operations of 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
97
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
is constructing the Empire Connector 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 commence service in early December 2008, on or before the in-service date of the Millennium Pipeline. 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 and in the provinces of Alberta, Saskatchewan and British Columbia in Canada.Alabama. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. On September 30, 2003,As disclosed in Note I — Discontinued Operations, on August 31, 2007, Seneca soldcompleted the sale of SECI, its southeast Saskatchewan oil and gas propertieswholly owned subsidiary operating in Canada, for a lossgain of $58.5 million. Proved reserves associated withapproximately $120.3 million, net of tax, during the properties sold were 19.4 million barrelsfourth quarter of oil and 0.3 Bcf of natural gas. When the transaction closed, the initial proceeds received were subject to an adjustment based on working capital and the resolution of certain income tax matters. In 2004, those items were resolved with the buyer and, as2007. As a result of the Company received an additional $4.6 million of sales proceeds,sale, SECI’s operations have been reported as shown in the table below for the year ended September 30, 2004.discontinued operations.
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential end-userscustomers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced energy and energy management servicesnatural 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. On August 1, 2003, the Company sold approximately 70,000 acres of timber property in Pennsylvania and New York. A gain of $168.8 million was recognized on the sale of this timber property. During 2004, the Company received final timber cruise information of the properties it sold and, based on that information, determined that property records pertaining to $1.3 million of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a pretax loss of $1.3 million, as shown in the table for the year ended September 30, 2004.
The data presented in the tables below reflect financial information for the reportable 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.
As disclosed in Note I — Discontinued Operations, the Company completed the sale of its majority interest in U.E., a district heating and electric generation business in the Czech Republic, on July 18, 2005. As a result of the sale of its majority interest in U.E., the Company discontinued all reporting for an International segment and previous period segment information has been restated to reflect this change. All Czech Republic operations have been reported as discontinued operations. Any remaining international activity has been included in corporate operations.
98102
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30, 2006 | |
| | | | | | | | | | | | | | | | | | | | | | | | Corporate
| | | | |
| | | | | | Pipeline
| | | Exploration
| | | | | | | | | Total
| | | | | | and
| | | | |
| | | | | | and
| | | and
| | | Energy
| | | | | | Reportable
| | | All
| | | Intersegment
| | | Total
| |
| | | Utility | | | Storage | | | Production | | | Marketing | | | Timber | | | Segments | | | Other | | | Eliminations | | | Consolidated | |
| | | (Thousands) | |
| |
| Revenue from External Customers | | $ | 1,265,695 | | | $ | 132,921 | | | $ | 346,880 | | | $ | 497,069 | | | $ | 65,024 | | | $ | 2,307,589 | | | $ | 3,304 | | | $ | 766 | | | $ | 2,311,659 | |
| Intersegment Revenues | �� | $ | 15,068 | | | $ | 81,431 | | | $ | — | | | $ | — | | | $ | 5 | | | $ | 96,504 | | | $ | 9,444 | | | $ | (105,948 | ) | | $ | — | |
| Interest Income | | $ | 4,889 | | | $ | 454 | | | $ | 8,682 | | | $ | 445 | | | $ | 747 | | | $ | 15,217 | | | $ | 22 | | | $ | (4,964 | ) | | $ | 10,275 | |
| 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 | | | $ | 94,738 | | | $ | 53 | | | $ | 6,495 | | | $ | 178,334 | | | $ | 789 | | | $ | 492 | | | $ | 179,615 | |
| Income Tax Expense (Benefit) | | $ | 35,699 | | | $ | 33,896 | | | $ | (2,808 | ) | | $ | 3,748 | | | $ | 3,277 | | | $ | 73,812 | | | $ | 969 | | | $ | 1,305 | | | $ | 76,086 | |
| Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,583 | | | $ | — | | | $ | 3,583 | |
| Significant Non-Cash Item: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Impairment of Oil and Gas Producing Properties | | $ | — | | | $ | — | | | $ | 104,739 | | | $ | — | | | $ | — | | | $ | 104,739 | | | $ | — | | | $ | — | | | $ | 104,739 | |
| Segment Profit (Loss): Net Income (Loss) | | $ | 49,815 | | | $ | 55,633 | | | $ | 20,971 | | | $ | 5,798 | | | $ | 5,704 | | | $ | 137,921 | | | $ | 359 | | | $ | (189 | ) | | $ | 138,091 | |
| Expenditures for Additions to Long-Lived Assets | | $ | 54,414 | | | $ | 26,023 | | | $ | 208,303 | | | $ | 16 | | | $ | 2,323 | | | $ | 291,079 | | | $ | 85 | | | $ | 2,995 | | | $ | 294,159 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30, 2006 | |
| | | (Thousands)
| |
| |
| Segment Assets | | $ | 1,471,422 | | | $ | 767,889 | | | $ | 1,209,969 | | | $ | 78,977 | | | $ | 159,421 | | | $ | 3,687,678 | | | $ | 64,287 | | | $ | (17,634 | ) | | $ | 3,734,331 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30, 2008 | |
| | | | | | | | | | | | | | | | | | | | | | | | 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 | | $ | 1,194,657 | | | $ | 135,052 | | | $ | 466,760 | | | $ | 549,932 | | | $ | 49,516 | | | $ | 2,395,917 | | | $ | 3,749 | | | $ | 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 | | | $ | 1,053 | | | $ | 14,976 | | | $ | 179 | | | $ | (4,340 | ) | | $ | 10,815 | |
| Interest Expense | | $ | 27,683 | | | $ | 13,783 | | | $ | 41,645 | | | $ | 175 | | | $ | 3,142 | | | $ | 86,428 | | | $ | 640 | | | $ | (13,099 | ) | | $ | 73,969 | |
| Depreciation, Depletion and Amortization | | $ | 39,113 | | | $ | 32,871 | | | $ | 92,221 | | | $ | 42 | | | $ | 4,904 | | | $ | 169,151 | | | $ | 783 | | | $ | 689 | | | $ | 170,623 | |
| Income Tax Expense | | $ | 36,303 | | | $ | 34,008 | | | $ | 92,686 | | | $ | 3,180 | | | $ | (378 | ) | | $ | 165,799 | | | $ | 2,564 | | | $ | (441 | ) | | $ | 167,922 | |
| Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 6,303 | | | $ | — | | | $ | 6,303 | |
| Segment Profit: Net Income (Loss) | | $ | 61,472 | | | $ | 54,148 | | | $ | 146,612 | | | $ | 5,889 | | | $ | 107 | | | $ | 268,228 | | | $ | 5,672 | | | $ | (5,172 | ) | | $ | 268,728 | |
| Expenditures for Additions to Long-Lived Assets | | $ | 57,457 | | | $ | 165,520 | | | $ | 192,187 | | | $ | 39 | | | $ | 1,354 | | | $ | 416,557 | | | $ | 131 | | | $ | (2,186 | ) | | $ | 414,502 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30, 2005 | |
| | | | | | | | | | | | | | | | | | | | | | | | Corporate
| | | | |
| | | | | | Pipeline
| | | Exploration
| | | | | | | | | Total
| | | | | | and
| | | | |
| | | | | | and
| | | and
| | | Energy
| | | | | | Reportable
| | | All
| | | Intersegment
| | | Total
| |
| | | Utility | | | Storage | | | Production | | | Marketing | | | Timber | | | Segments | | | Other | | | Eliminations | | | Consolidated | |
| | | (Thousands) | |
| |
| Revenue from External Customers | | $ | 1,101,572 | | | $ | 132,805 | | | $ | 293,425 | | | $ | 329,714 | | | $ | 61,285 | | | $ | 1,918,801 | | | $ | 4,748 | | | $ | — | | | $ | 1,923,549 | |
| Intersegment Revenues | | $ | 15,495 | | | $ | 83,054 | | | $ | — | | | $ | — | | | $ | 1 | | | $ | 98,550 | | | $ | 8,606 | | | $ | (107,156 | ) | | $ | — | |
| Interest Income | | $ | 4,111 | | | $ | 76 | | | $ | 4,661 | | | $ | 783 | | | $ | 438 | | | $ | 10,069 | | | $ | 19 | | | $ | (3,592 | ) | | $ | 6,496 | |
| Interest Expense | | $ | 22,900 | | | $ | 7,128 | | | $ | 48,856 | | | $ | 11 | | | $ | 2,764 | | | $ | 81,659 | | | $ | 1,726 | | | $ | (1,072 | ) | | $ | 82,313 | |
| Depreciation, Depletion and Amortization | | $ | 40,159 | | | $ | 38,050 | | | $ | 90,912 | | | $ | 41 | | | $ | 6,601 | | | $ | 175,763 | | | $ | 3,537 | | | $ | 467 | | | $ | 179,767 | |
| Income Tax Expense (Benefit) | | $ | 23,102 | | | $ | 39,068 | | | $ | 28,353 | | | $ | 3,210 | | | $ | 2,271 | | | $ | 96,004 | | | $ | (1,425 | ) | | $ | (1,601 | ) | | $ | 92,978 | |
| Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,362 | | | $ | — | | | $ | 3,362 | |
| Significant Non-Cash Item: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Impairment of Investment in Partnership | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (4,158 | )(1) | | $ | — | | | $ | (4,158 | ) |
| Segment Profit (Loss): Income (Loss) from Continuing Operations | | $ | 39,197 | | | $ | 60,454 | | | $ | 50,659 | | | $ | 5,077 | | | $ | 5,032 | | | $ | 160,419 | | | $ | (2,616 | ) | | $ | (4,288 | ) | | $ | 153,515 | |
| Expenditures for Additions to Long-Lived Assets from Continuing Operations | | $ | 50,071 | | | $ | 21,099 | | | $ | 122,450 | | | $ | 58 | | | $ | 18,894 | | | $ | 212,572 | | | $ | 463 | | | $ | 618 | | | $ | 213,653 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30, 2005 | |
| | | (Thousands)
| |
| |
| Segment Assets | | $ | 1,401,128 | | | $ | 782,546 | | | $ | 1,213,525 | | | $ | 90,468 | | | $ | 162,052 | | | $ | 3,649,719 | | | $ | 73,354 | | | $ | 2,209 | | | $ | 3,725,282 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
99103
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
(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. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30, 2004 | |
| | | | | | Pipeline
| | | Exploration
| | | | | | | | | Total
| | | | | | Corporate and
| | | | |
| | | | | | and
| | | and
| | | Energy
| | | | | | Reportable
| | | All
| | | Intersegment
| | | Total
| |
| | | Utility | | | Storage | | | Production | | | Marketing | | | Timber | | | Segments | | | Other | | | Eliminations | | | Consolidated | |
| | | (Thousands) | |
| |
| Revenue from External Customers | | $ | 1,137,288 | | | $ | 122,970 | | | $ | 293,698 | | | $ | 284,349 | | | $ | 55,968 | | | $ | 1,894,273 | | | $ | 13,695 | | | $ | — | | | $ | 1,907,968 | |
| Intersegment Revenues | | $ | 15,353 | | | $ | 86,737 | | | $ | — | | | $ | — | | | $ | 2 | | | $ | 102,092 | | | $ | — | | | $ | (102,092 | ) | | $ | — | |
| Interest Income | | $ | 552 | | | $ | 217 | | | $ | 1,831 | | | $ | 521 | | | $ | 312 | | | $ | 3,433 | | | $ | 15 | | | $ | (1,677 | ) | | $ | 1,771 | |
| Interest Expense | | $ | 21,945 | | | $ | 10,933 | | | $ | 50,642 | | | $ | 33 | | | $ | 2,218 | | | $ | 85,771 | | | $ | 919 | | | $ | 3,062 | | | $ | 89,752 | |
| Depreciation, Depletion and Amortization | | $ | 39,101 | | | $ | 37,345 | | | $ | 89,943 | | | $ | 102 | | | $ | 6,277 | | | $ | 172,768 | | | $ | 1,071 | | | $ | 450 | | | $ | 174,289 | |
| Income Tax Expense (Benefit) | | $ | 31,393 | | | $ | 30,968 | | | $ | 28,899 | | | $ | 3,964 | | | $ | 3,320 | | | $ | 98,544 | | | $ | 829 | | | $ | (4,783 | ) | | $ | 94,590 | |
| Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 805 | | | $ | — | | | $ | 805 | |
| Significant Item: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Loss on Sale of Timber Properties | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,252 | | | $ | 1,252 | | | $ | — | | | $ | — | | | $ | 1,252 | |
| Significant Item: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gain on Sale of Oil and Gas Producing Properties | | $ | — | | | $ | — | | | $ | 4,645 | | | $ | — | | | $ | — | | | $ | 4,645 | | | $ | — | | | $ | — | | | $ | 4,645 | |
| Segment Profit (Loss): Income (Loss) from Continuing Operations | | $ | 46,718 | | | $ | 47,726 | | | $ | 54,344 | | | $ | 5,535 | | | $ | 5,637 | | | $ | 159,960 | | | $ | 1,530 | | | $ | (7,225 | ) | | $ | 154,265 | |
| Expenditures for Additions to Long-Lived Assets from Continuing Operations | | $ | 55,449 | | | $ | 23,196 | | | $ | 77,654 | | | $ | 10 | | | $ | 2,823 | | | $ | 159,132 | | | $ | 200 | | | $ | 5,511 | | | $ | 164,843 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30, 2004 | |
| | | (Thousands)
| |
| |
| Segment Assets | | $ | 1,355,964 | | | $ | 783,145 | | | $ | 1,078,217 | | | $ | 68,599 | | | $ | 140,992 | | | $ | 3,426,917 | | | $ | 77,013 | | | $ | 213,673 | (1) | | $ | 3,717,603 | |
| | |
| (1) | | Amount includes $268,119$134,930 of assets of the former International segment, the majority ofSECI, which has been classified as discontinued with the saleoperations as of U.E.September 30, 2007. (See Note I — Discontinued Operations). |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended September 30 | | | For The Year Ended September 30 | |
Geographic Information | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
Revenues from External Customers (1): | | | | | | | | | | | | | |
Revenues from External Customers(1): | | | | | | | | | | | | | |
| United States | | $ | 2,242,155 | | | $ | 1,860,684 | | | $ | 1,867,335 | | | $ | 2,400,361 | | | $ | 2,039,566 | | | $ | 2,239,675 | |
| Canada | | | 69,504 | | | | 62,865 | | | | 40,633 | | |
| | | | | | | | | | | | | | | |
| | | $ | 2,311,659 | | | $ | 1,923,549 | | | $ | 1,907,968 | | |
| | | | | | | | | |
100
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30 | | | At September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
Long-Lived Assets: | | | | | | | | | | | | | | | | | | | | | | | | |
| United States | | $ | 3,117,644 | | | $ | 2,978,680 | | | $ | 2,941,779 | | | $ | 3,630,709 | | | $ | 3,334,274 | | | $ | 3,181,769 | |
| Canada | | | 97,234 | | | | 171,196 | | | | 143,042 | | |
| Assets of Discontinued Operations | | | — | | | | — | | | | 228,179 | | | | — | | | | — | | | | 97,234 | |
| | | | | | | | | | | | | | | |
| | | $ | 3,214,878 | | | $ | 3,149,876 | | | $ | 3,313,000 | | | $ | 3,630,709 | | | $ | 3,334,274 | | | $ | 3,279,003 | |
| | | | | | | | | | | | | | | |
| | |
| (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. |
Note K — Investments in Unconsolidated Subsidiaries
| |
| Note K — | Investments in Unconsolidated Subsidiaries |
The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy, Model City and ESNE. The Company has 50% interests in each of these entities. 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.
In September 2005, the Company recorded an impairment of $4.2 million of its equity investment in ESNE due to a decline in the fair market value of ESNE. This impairment was recorded in accordance with APB 18.
A summary of the Company’s investments in unconsolidated subsidiaries at September 30, 20062008 and 20052007 is as follows:
| | | | | | | | | | | | | | | | | |
| | | At September 30 | | | At September 30 | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Thousands) | | | (Thousands) | |
| |
| ESNE | | $ | 4,486 | | | $ | 5,298 | | | $ | 3,958 | | | $ | 4,652 | |
| Seneca Energy | | | 5,366 | | | | 5,839 | | | | 10,589 | | | | 12,033 | |
| Model City | | | 1,738 | | | | 1,521 | | | | 1,732 | | | | 1,571 | |
| | | | | | | | | | | |
| | | $ | 11,590 | | | $ | 12,658 | | | $ | 16,279 | | | $ | 18,256 | |
| | | | | | | | | | | |
101
104
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note L — Intangible Assets
| |
| Note L — | Intangible Assets |
As a result of the Empire and Toro acquisitions, the Company acquired certain intangible assets during 2003. 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
| |
| | | At September 30, 2006 | | | 30, 2005 | |
| | | Gross Carrying
| | | | | | Net Carrying
| | | Net Carrying
| |
| | | Amount | | | Accumulated Amortization | | | Amount | | | Amount | |
| |
| Intangible Assets Subject to Amortization: | | | | | | | | | | | | | | | | |
| Long-Term Transportation Contracts | | $ | 8,580 | | | $ | (3,920 | ) | | $ | 4,660 | | | $ | 5,729 | |
| Long-Term Gas Purchase Contracts | | | 31,864 | | | | (5,026 | ) | | | 26,838 | | | | 28,431 | |
| Intangible Assets Not Subject to Amortization: | | | | | | | | | | | | | | | | |
| Retirement Plan Intangible Asset (see Note G) | | | — | | | | — | | | | — | | | | 8,142 | |
| | | | | | | | | | | | | | | | | |
| | | $ | 40,444 | | | $ | (8,946 | ) | | $ | 31,498 | | | $ | 42,302 | |
| | | | | | | | | | | | | | | | | |
| Aggregate Amortization Expense | | | | | | | | | | | | | | | | |
For the Year Ended
September 30, 2006 | | $ | 2,663 | | | | | | | | | | | | | |
For the Year Ended
September 30, 2005 | | $ | 2,663 | | | | | | | | | | | | | |
For the Year Ended
September 30, 2004 | | $ | 2,567 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | At September 30,
| |
| | | At September 30, 2008 | | | 2007 | |
| | | Gross Carrying
| | | Accumulated
| | | Net Carrying
| | | Net Carrying
| |
| | | Amount | | | Amortization | | | Amount | | | Amount | |
| |
| Intangible Assets Subject to Amortization: | | | | | | | | | | | | | | | | |
| Long-Term Transportation Contracts | | $ | 8,580 | | | $ | (6,058 | ) | | $ | 2,522 | | | $ | 3,591 | |
| Long-Term Gas Purchase Contracts | | | 31,864 | | | | (8,212 | ) | | | 23,652 | | | | 25,245 | |
| | | | | | | | | | | | | | | | | |
| | | $ | 40,444 | | | $ | (14,270 | ) | | $ | 26,174 | | | $ | 28,836 | |
| | | | | | | | | | | | | | | | | |
| Aggregate Amortization Expense: | | | | | | | | | | | | | | | | |
| For the Year Ended September 30, 2008 | | $ | 2,662 | | | | | | | | | | | | | |
| For the Year Ended September 30, 2007 | | $ | 2,662 | | | | | | | | | | | | | |
| For the Year Ended September 30, 2006 | | $ | 2,662 | | | | | | | | | | | | | |
The gross carrying amount of intangible assets subject to amortization at September 30, 20062008 remained unchanged from September 30, 2005.2007. The only activity with regard to intangible assets subject to amortization was amortization expense as shown on the table above. Amortization expense for the long-term transportation contracts is estimated to be $1.1 million annually for 2007 and 2008. Amortization expense is estimated to be $0.5 million in 2009, and $0.4 million in 2010, 2011, 2012 and 2011.2013. Amortization expense for the long-term gas purchase contracts is estimated to be $1.6 million annually for 2007, 2008, 2009, 2010, 2011, 2012 and 2011.2013.
Note M — Quarterly Financial Data (unaudited)
| |
| Note M — | 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.
102105
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Net
| | | | | | | | | | | | | |
| | | | | | | | | | | | Income
| | | Income
| | | | | | | | | | | | | |
| | | | | | | | | Income
| | | (Loss)
| | | Available
| | | Earnings from
| | | | | | | |
| | | | | | | | | from
| | | from
| | | for
| | | Continuing Operations per
| | | | | | | |
Quarter
| | Operating
| | | Operating
| | | Continuing
| | | Discontinued
| | | Common
| | | Common Share | | | Earnings per Common Share | |
Ended | | Revenues | | | Income | | | Operations | | | Operations | | | Stock | | | Basic | | | Diluted | | | Basic | | | Diluted | |
| | | (Thousands, except per common share amounts) | |
| |
2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 9/30/2006 | | $ | 294,469 | | | $ | 18,444 | | | $ | 1,968 | | | $ | — | | | $ | 1,968 | (1) | | $ | 0.02 | | | $ | 0.02 | | | $ | 0.02 | | | $ | 0.02 | |
| 6/30/2006 | | $ | 415,452 | | | $ | 8,541 | | | $ | 111 | | | $ | — | | | $ | 111 | (2) | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| 3/31/2006 | | $ | 890,981 | | | $ | 138,967 | | | $ | 78,594 | | | $ | — | | | $ | 78,594 | (3) | | $ | 0.93 | | | $ | 0.91 | | | $ | 0.93 | | | $ | 0.91 | |
| 12/31/2005 | | $ | 710,757 | | | $ | 110,123 | | | $ | 57,418 | | | $ | — | | | $ | 57,418 | (4) | | $ | 0.68 | | | $ | 0.67 | | | $ | 0.68 | | | $ | 0.67 | |
2005 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 9/30/2005 | | $ | 287,064 | | | $ | 34,926 | | | $ | 18,311 | (5) | | $ | 30,900 | (6) | | $ | 49,211 | (5)(6) | | $ | 0.22 | | | $ | 0.21 | | | $ | 0.58 | | | $ | 0.57 | |
| 6/30/2005 | | $ | 400,359 | | | $ | 63,028 | | | $ | 26,393 | | | $ | (7,237 | )(7) | | $ | 19,156 | (7) | | $ | 0.32 | | | $ | 0.31 | | | $ | 0.23 | | | $ | 0.23 | |
| 3/31/2005 | | $ | 735,842 | | | $ | 120,667 | | | $ | 63,981 | (8) | | $ | 6,702 | | | $ | 70,683 | (8) | | $ | 0.77 | | | $ | 0.75 | | | $ | 0.85 | | | $ | 0.83 | |
| 12/31/2004 | | $ | 500,284 | | | $ | 91,741 | | | $ | 44,830 | | | $ | 5,608 | | | $ | 50,438 | | | $ | 0.54 | | | $ | 0.53 | | | $ | 0.61 | | | $ | 0.60 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Net
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Income
| | | | | | | | | | | | | |
| | | | | | | | | Income
| | | Income
| | | Available
| | | Earnings from
| | | | | | | |
| | | | | | | | | from
| | | from
| | | for
| | | Continuing Operations per
| | | | | | | |
Quarter
| | Operating
| | | Operating
| | | Continuing
| | | Discontinued
| | | Common
| | | Common Share | | | Earnings per Common Share | |
Ended | | Revenues | | | Income | | | Operations | | | Operations | | | Stock | | | Basic | | | Diluted | | | Basic | | | Diluted | |
| | | (Thousands, except per common share amounts) | |
| |
2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 9/30/2008 | | $ | 397,858 | | | $ | 79,149 | | | $ | 43,266 | | | $ | — | | | $ | 43,266 | | | $ | 0.54 | | | $ | 0.52 | | | $ | 0.54 | | | $ | 0.52 | |
| 6/30/2008 | | $ | 548,382 | | | $ | 110,947 | | | $ | 59,855 | | | $ | — | | | $ | 59,855 | | | $ | 0.74 | | | $ | 0.72 | | | $ | 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 | |
| 12/31/2007 | | $ | 568,268 | | | $ | 126,009 | | | $ | 70,604 | | | $ | — | | | $ | 70,604 | | | $ | 0.84 | | | $ | 0.82 | | | $ | 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 expensea $0.6 million gain on sale of $29.1 million related to the impairment of oil and gas producing properties.turbine. |
| |
| (2) | | Includes expensea $120.3 million gain on the sale of $39.5 million related to the impairment of oil and gas producing properties and income of $6.1 million related to income tax adjustments.SECI. |
| |
| (3) | | Includes $4.8 million of income associated with the reversal of $5.1 million related to income tax adjustments.reserve for preliminary project costs associated with the Empire Connector project. |
| |
| (4) | | Includes $2.3 million of income associated with the reversal of $2.6 milliona purchased gas expense accrual related to the resolution of a regulatory adjustment.contingency. |
| |
| (5) | | Includes a $3.9$1.9 million gainpositive earnings impact associated with insurance proceeds received in prior years for which a contingency was resolved during the quarter, $3.3 milliondiscontinuance of expense related to certain derivative financial instruments that no longer qualified as effective hedges, $2.7 million of expense related to the impairment ofhedge accounting on an investment in a partnership, and $1.8 million of expense related to the impairment of a gas-powered turbine.interest rate collar. |
| |
|
(6)Note N — | | Includes a $25.8 million gain related to the sale of U.E.Market for Common Stock and income of $6.0 million due to the reversal of deferred income taxes related to U.E. |
|
(7) | | Includes $6.0 million of previously unrecorded deferred income tax expense related to U.E. |
|
(8) | | Includes a $2.6 million gain on a FERC approved sale of base gas.Related Shareholder Matters (unaudited) |
103
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note N — Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 2006,2008, there were 17,76716,544 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, 20062008 and 2005,2007, are shown below:
| | | | | | | | | | | | | |
| | | Price Range | | | | |
Quarter Ended | | High | | | Low | | | Dividends Declared | |
| |
2006 | | | | | | | | | | | | |
| 9/30/2006 | | $ | 39.16 | | | $ | 34.95 | | | $ | .30 | |
| 6/30/2006 | | $ | 36.75 | | | $ | 31.33 | | | $ | .30 | |
| 3/31/2006 | | $ | 35.43 | | | $ | 30.60 | | | $ | .29 | |
| 12/31/2005 | | $ | 35.27 | | | $ | 29.25 | | | $ | .29 | |
2005 | | | | | | | | | | | | |
| 9/30/2005 | | $ | 36.00 | | | $ | 27.74 | | | $ | .29 | |
| 6/30/2005 | | $ | 29.49 | | | $ | 26.20 | | | $ | .29 | |
| 3/31/2005 | | $ | 29.75 | | | $ | 26.66 | | | $ | .28 | |
| 12/31/2004 | | $ | 29.18 | | | $ | 27.01 | | | $ | .28 | |
| | | | | | | | | | | | | |
| | | 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
NATIONAL FUEL GAS COMPANY
Note ONOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Supplementary Information for Oil and Gas Producing Activities(Continued)
| |
| Note O — | Supplementary Information for Oil and Gas Producing Activities (unaudited) |
The following supplementary information is presented in accordance with SFAS 69, “Disclosures about Oil and 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 | |
| | | 2006 | | 2005 | | | 2008 | | 2007 | |
| | | (Thousands) | | | (Thousands) | |
| |
| Proved Properties(1) | | $ | 1,884,049 | | | $ | 1,650,788 | | | $ | 1,783,276 | | | $ | 1,583,956 | |
| Unproved Properties | | | 41,930 | | | | 39,084 | | | | 23,285 | | | | 20,005 | |
| | | | | | | | | | | |
| | | | 1,925,979 | | | | 1,689,872 | | | | 1,806,561 | | | | 1,603,961 | |
| Less — Accumulated Depreciation, Depletion and Amortization | | | 929,921 | | | | 721,397 | | | | 718,166 | | | | 627,073 | |
| | | | | | | | | | | |
| | | $ | 996,058 | | | $ | 968,475 | | | $ | 1,088,395 | | | $ | 976,888 | |
| | | | | | | | | | | |
| | |
| (1) | | Includes asset retirement costs of $42.2$60.9 million and $30.8$40.9 million at September 30, 20062008 and 2005,2007, respectively. |
104
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Costs related to unproved properties are excluded from amortization as they represent unevaluateduntil proved reserves are found or it is determined that the unproved properties that require additional drillingare 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 existencepool of oil and gas reserves.capitalized costs being amortized. Following is a summary of such costs excluded from amortization at September 30, 2006:2008:
| | | | | | | | | | | | | | | | | | | | | |
| | | Total
| | | | | | | | | | | | | |
| | | as
| | | | | | | | | | | | | |
| | | of
| | | | | | | | | | | | | |
| | | September
| | | | | | | | | | | | | |
| | | 30,
| | | Year Costs Incurred | |
| | | 2006 | | | 2006 | | | 2005 | | | 2004 | | | Prior | |
| | | (Thousands) | |
| |
| Acquisition Costs | | $ | 41,930 | | | $ | 27,497 | | | $ | 6,078 | | | $ | 981 | | | $ | 7,374 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | 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 | |
107
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended September 30 | | | Year Ended September 30 | |
| | | 2006 | | 2005 | | 2004 | | | 2008 | | 2007 | | 2006 | |
| | | (Thousands) | | | (Thousands) | |
| |
United States | | | | | | | | | | | | | | | | | | | | | | | | |
| Property Acquisition Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved | | $ | 5,339 | | | $ | 287 | | | $ | (8 | ) | | $ | 16,474 | | | $ | 2,621 | | | $ | 5,339 | |
| Unproved | | | 8,844 | | | | 1,215 | | | | 3,529 | | | | 8,449 | | | | 3,210 | | | | 8,844 | |
| Exploration Costs | | | 64,087 | | | | 32,456 | | | | 10,503 | | | | 56,274 | | | | 26,891 | | | | 64,087 | |
| Development Costs | | | 87,738 | | | | 49,016 | | | | 31,881 | | | | 106,975 | | | | 113,206 | | | | 87,738 | |
| Asset Retirement Costs | | | 10,965 | | | | 8,051 | | | | 2,292 | | | | 20,048 | | | | 2,139 | | | | 10,965 | |
| | | | | | | | | | | | | | | |
| | | | 176,973 | | | | 91,025 | | | | 48,197 | | | | 208,220 | | | | 148,067 | | | | 176,973 | |
| | | | | | | | | | | | | | | |
Canada | | | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | | |
| Property Acquisition Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved | | | (427 | ) | | | (1,551 | ) | | | 29 | | | | — | | | | (1,404 | ) | | | (427 | ) |
| Unproved | | | 6,492 | | | | 4,668 | | | | 3,167 | | | | — | | | | (1,142 | ) | | | 6,492 | |
| Exploration Costs | | | 20,778 | | | | 22,943 | | | | 22,624 | | | | — | | | | 20,134 | | | | 20,778 | |
| Development Costs | | | 14,385 | | | | 12,198 | | | | 5,500 | | | | — | | | | 11,414 | | | | 14,385 | |
| Asset Retirement Costs | | | 279 | | | | 292 | | | | 1,218 | | | | — | | | | 167 | | | | 279 | |
| | | | | | | | | | | | | | | |
| | | | 41,507 | | | | 38,550 | | | | 32,538 | | | | — | | | | 29,169 | | | | 41,507 | |
| | | | | | | | | | | | | | | |
Total | | | | | | | | | | | | | | | | | | | | | | | | |
| Property Acquisition Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved | | | 4,912 | | | | (1,264 | ) | | | 21 | | | | 16,474 | | | | 1,217 | | | | 4,912 | |
| Unproved | | | 15,336 | | | | 5,883 | | | | 6,696 | | | | 8,449 | | | | 2,068 | | | | 15,336 | |
| Exploration Costs | | | 84,865 | | | | 55,399 | | | | 33,127 | | | | 56,274 | | | | 47,025 | | | | 84,865 | |
| Development Costs | | | 102,123 | | | | 61,214 | | | | 37,381 | | | | 106,975 | | | | 124,620 | | | | 102,123 | |
| Asset Retirement Costs | | | 11,244 | | | | 8,343 | | | | 3,510 | | | | 20,048 | | | | 2,306 | | | | 11,244 | |
| | | | | | | | | | | | | | | |
| | | $ | 218,480 | | | $ | 129,575 | | | $ | 80,735 | | | $ | 208,220 | | | $ | 177,236 | | | $ | 218,480 | |
| | | | | | | | | | | | | | | |
For the years ended September 30, 2006, 20052008, 2007 and 2004,2006, the Company spent $55.6$25.4 million, $19.2$30.3 million and $12.1$55.6 million, respectively, developing proved undeveloped reserves.
105108
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Results of Operations for Producing Activities
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands, except per Mcfe amounts) | |
| |
United States | | | | | | | | | | | | |
| Operating Revenues: | | | | | | | | | | | | |
| Natural Gas (includes revenues from sales to affiliates of $106, $77 and $72, respectively) | | $ | 152,451 | | | $ | 151,004 | | | $ | 151,570 | |
| Oil, Condensate and Other Liquids | | | 195,050 | | | | 160,145 | | | | 139,301 | |
| | | | | | | | | | | | | |
| Total Operating Revenues(1) | | | 347,501 | | | | 311,149 | | | | 290,871 | |
| Production/Lifting Costs | | | 41,354 | | | | 38,442 | | | | 39,677 | |
| Accretion Expense | | | 2,412 | | | | 2,220 | | | | 1,756 | |
| Depreciation, Depletion and Amortization ($1.74, $1.58 and $1.41 per Mcfe of production) | | | 66,488 | | | | 67,097 | | | | 73,396 | |
| Income Tax Expense | | | 88,104 | | | | 74,110 | | | | 65,337 | |
| | | | | | | | | | | | | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | | 149,143 | | | | 129,280 | | | | 110,705 | |
| | | | | | | | | | | | | |
Canada | | | | | | | | | | | | |
| Operating Revenues: | | | | | | | | | | | | |
| Natural Gas | | | 54,819 | | | | 49,275 | | | | 30,359 | |
| Oil, Condensate and Other Liquids | | | 13,985 | | | | 12,875 | | | | 10,018 | |
| | | | | | | | | | | | | |
| Total Operating Revenues(1) | | | 68,804 | | | | 62,150 | | | | 40,377 | |
| Production/Lifting Costs | | | 14,628 | | | | 12,683 | | | | 8,176 | |
| Accretion Expense | | | 258 | | | | 228 | | | | 177 | |
| Depreciation, Depletion and Amortization ($2.95, $2.36 and $1.83 per Mcfe of production) | | | 27,439 | | | | 23,108 | | | | 14,922 | |
| Impairment of Oil and Gas Producing Properties(2) | | | 104,739 | | | | — | | | | — | |
| Income Tax Expense (Benefit) | | | (31,987 | ) | | | 8,577 | | | | 5,235 | |
| | | | | | | | | | | | | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | | (46,273 | ) | | | 17,554 | | | | 11,867 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (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 | |
| Oil, Condensate and Other Liquids | | | 305,887 | | | | 189,539 | | | | 195,050 | |
| | | | | | | | | | | | | |
| Total Operating Revenues(1) | | | 522,510 | | | | 324,938 | | | | 347,501 | |
| Production/Lifting Costs | | | 66,685 | | | | 48,410 | | | | 41,354 | |
| Accretion Expense | | | 4,056 | | | | 3,704 | | | | 2,412 | |
| 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 | |
| | | | | | | | | | | | | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | | 215,754 | | | | 116,444 | | | | 149,143 | |
| | | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | |
| Operating Revenues: | | | | | | | | | | | | |
| Natural Gas | | | — | | | | 39,114 | | | | 54,819 | |
| Oil, Condensate and Other Liquids | | | — | | | | 10,313 | | | | 13,985 | |
| | | | | | | | | | | | | |
| Total Operating Revenues(1) | | | — | | | | 49,427 | | | | 68,804 | |
| Production/Lifting Costs | | | — | | | | 14,846 | | | | 14,628 | |
| Accretion Expense | | | — | | | | 249 | | | | 258 | |
| 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 | ) |
| | | | | | | | | | | | | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | | — | | | | 17,842 | | | | (46,273 | ) |
| | | | | | | | | | | | | |
106109
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands, except per Mcfe amounts) | |
| |
Total | | | | | | | | | | | | |
| Operating Revenues: | | | | | | | | | | | | |
| Natural Gas (includes revenues from sales to affiliates of $106, $77 and $72, respectively) | | | 207,270 | | | | 200,279 | | | | 181,929 | |
| Oil, Condensate and Other Liquids | | | 209,035 | | | | 173,020 | | | | 149,319 | |
| | | | | | | | | | | | | |
| Total Operating Revenues(1) | | | 416,305 | | | | 373,299 | | | | 331,248 | |
| Production/Lifting Costs | | | 55,982 | | | | 51,125 | | | | 47,853 | |
| Accretion Expense | | | 2,670 | | | | 2,448 | | | | 1,933 | |
| Depreciation, Depletion and Amortization ($1.98, $1.72 and $1.47 per Mcfe of production) | | | 93,927 | | | | 90,205 | | | | 88,318 | |
| Impairment of Oil and Gas Producing Properties(2) | | | 104,739 | | | | — | | | | — | |
| Income Tax Expense | | | 56,117 | | | | 82,687 | | | | 70,572 | |
| | | | | | | | | | | | | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | $ | 102,870 | | | $ | 146,834 | | | $ | 122,572 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | (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 | |
| Oil, Condensate and Other Liquids | | | 305,887 | | | | 199,852 | | | | 209,035 | |
| | | | | | | | | | | | | |
| Total Operating Revenues(1) | | | 522,510 | | | | 374,365 | | | | 416,305 | |
| Production/Lifting Costs | | | 66,685 | | | | 63,256 | | | | 55,982 | |
| Accretion Expense | | | 4,056 | | | | 3,953 | | | | 2,670 | |
| Depreciation, Depletion and Amortization ($2.23, $1.92 and $1.98 per Mcfe of production) | | | 91,093 | | | | 90,239 | | | | 93,927 | |
| Impairment of Oil and Gas Producing Properties(2) | | | — | | | | — | | | | 104,739 | |
| Income Tax Expense | | | 144,922 | | | | 82,631 | | | | 56,117 | |
| | | | | | | | | | | | | |
| Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | $ | 215,754 | | | $ | 134,286 | | | $ | 102,870 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Exclusive of hedging gains and losses. See further discussion in Note F — Financial Instruments. |
| |
| (2) | | See discussion of impairment in Note A — Summary of Significant Accounting Policies. |
110
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Reserve Quantity Information (unaudited)
The Company’s proved oil and gas reserves are located in the United States and Canada.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 | |
| | | U. S. | | | | | | | |
| | | Gulf
| | | West
| | | | | | | | | | | | | |
| | | Coast
| | | Coast
| | | Appalachian
| | | Total
| | | | | | Total
| |
| | | Region | | | Region | | | Region | | | U.S. | | | Canada | | | Company | |
| |
| Proved Developed and Undeveloped Reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2003 | | | 47,683 | | | | 70,062 | | | | 81,219 | | | | 198,964 | | | | 52,153 | | | | 251,117 | |
| Extensions and Discoveries | | | 2,632 | | | | — | | | | 3,784 | | | | 6,416 | | | | 15,925 | | | | 22,341 | |
| Revisions of Previous Estimates | | | (4,984 | ) | | | 1,831 | | | | (1,111 | ) | | | (4,264 | ) | | | (11,004 | ) | | | (15,268 | ) |
| Production | | | (17,596 | ) | | | (4,057 | ) | | | (5,132 | ) | | | (26,785 | ) | | | (6,228 | ) | | | (33,013 | ) |
| Sales of Minerals in Place | | | (1 | ) | | | (392 | ) | | | — | | | | (393 | ) | | | — | | | | (393 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Gas MMcf | |
| | | 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 | | | 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 | |
| Extensions and Discoveries | | | 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 | |
| Production | | | (10,356 | ) | | | (3,929 | ) | | | (5,555 | ) | | | (19,840 | ) | | | (6,426 | ) | | | (26,266 | ) |
| Sales of Minerals in Place | | | (36 | ) | | | — | | | | (34 | ) | | | (70 | ) | | | (40,075 | ) | | | (40,145 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2007 | | | 25,136 | | | | 73,175 | | | | 107,078 | | | | 205,389 | | | | — | | | | 205,389 | |
| Extensions and Discoveries | | | 8,759 | | | | — | | | | 31,322 | | | | 40,081 | | | | — | | | | 40,081 | |
| Revisions of Previous Estimates | | | 2,156 | | | | 566 | | | | (3,460 | ) | | | (738 | ) | | | — | | | | (738 | ) |
| Production | | | (11,033 | ) | | | (4,039 | ) | | | (7,269 | ) | | | (22,341 | ) | | | — | | | | (22,341 | ) |
| Purchases of Minerals in Place | | | — | | | | 4,539 | | | | 727 | | | | 5,266 | | | | — | | | | 5,266 | |
| Sales of Minerals in Place | | | (377 | ) | | | (1,381 | ) | | | — | | | | (1,758 | ) | | | — | | | | (1,758 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2008 | | | 24,641 | | | | 72,860 | | | | 128,398 | | | | 225,899 | | | | — | | | | 225,899 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| September 30, 2007 | | | 25,136 | | | | 66,017 | | | | 96,674 | | | | 187,827 | | | | — | | | | 187,827 | |
| September 30, 2008 | | | 18,242 | | | | 68,453 | | | | 115,824 | | | | 202,519 | | | | — | | | | 202,519 | |
107
111
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Gas MMcf | |
| | | U. S. | | | | | | | |
| | | Gulf
| | | West
| | | | | | | | | | | | | |
| | | Coast
| | | Coast
| | | Appalachian
| | | Total
| | | | | | Total
| |
| | | Region | | | Region | | | Region | | | U.S. | | | Canada | | | Company | |
| |
| September 30, 2004 | | | 27,734 | | | | 67,444 | | | | 78,760 | | | | 173,938 | | | | 50,846 | | | | 224,784 | |
| Extensions and Discoveries | | | 17,165 | | | | — | | | | 5,461 | | | | 22,626 | | | | 4,849 | | | | 27,475 | |
| Revisions of Previous Estimates | | | 6,039 | | | | 7,067 | | | | 3,733 | | | | 16,839 | | | | (1,600 | ) | | | 15,239 | |
| Production | | | (12,468 | ) | | | (4,052 | ) | | | (4,650 | ) | | | (21,170 | ) | | | (8,009 | ) | | | (29,179 | ) |
| Sales of Minerals in Place | | | — | | | | — | | | | (179 | ) | | | (179 | ) | | | — | | | | (179 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved Developed Reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2003 | | | 45,402 | | | | 54,180 | | | | 81,218 | | | | 180,800 | | | | 42,745 | | | | 223,545 | |
| September 30, 2004 | | | 25,827 | | | | 53,035 | | | | 78,760 | | | | 157,622 | | | | 46,223 | | | | 203,845 | |
| 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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Oil Mbbl | |
| | | U.S. | | | | | | | |
| | | | | | West
| | | | | | | | | | | | | |
| | | Gulf Coast
| | | Coast
| | | Appalachian
| | | Total
| | | | | | Total
| |
| | | Region | | | Region | | | Region | | | U.S. | | | Canada | | | Company | |
| |
| Proved Developed and Undeveloped Reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2003 | | | 3,383 | | | | 63,852 | | | | 138 | | | | 67,373 | | | | 2,391 | | | | 69,764 | |
| Extensions and Discoveries | | | 19 | | | | — | | | | 18 | | | | 37 | | | | 181 | | | | 218 | |
| Revisions of Previous Estimates | | | 213 | | | | (17 | ) | | | 11 | | | | 207 | | | | (144 | ) | | | 63 | |
| Production | | | (1,534 | ) | | | (2,650 | ) | | | (20 | ) | | | (4,204 | ) | | | (324 | ) | | | (4,528 | ) |
| Sales of Minerals in Place | | | (1 | ) | | | (303 | ) | | | — | | | | (304 | ) | | | — | | | | (304 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2004 | | | 2,080 | | | | 60,882 | | | | 147 | | | | 63,109 | | | | 2,104 | | | | 65,213 | |
| Extensions and Discoveries | | | 99 | | | | — | | | | 63 | | | | 162 | | | | 204 | | | | 366 | |
| Revisions of Previous Estimates | | | 105 | | | | (1,253 | ) | | | 3 | | | | (1,145 | ) | | | (186 | ) | | | (1,331 | ) |
| Production | | | (989 | ) | | | (2,544 | ) | | | (36 | ) | | | (3,569 | ) | | | (300 | ) | | | (3,869 | ) |
| Sales of Minerals in Place | | | — | | | | — | | | | — | | | | — | | | | (122 | ) | | | (122 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
108
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Oil Mbbl | | | Oil Mbbl | |
| | | U.S. | | | | | | | U. S. | | | | | |
| | | | | West
| | | | | | | | | | | Gulf
| | West
| | | | | | Canada
| | | |
| | | Gulf Coast
| | Coast
| | Appalachian
| | Total
| | | | Total
| | | Coast
| | Coast
| | Appalachian
| | Total
| | (Discontinued
| | Total
| |
| | | Region | | Region | | Region | | U.S. | | Canada | | Company | | | 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 | | | | 1,295 | | | | 57,085 | | | | 177 | | | | 58,557 | | | | 1,700 | | | | 60,257 | |
| Extensions and Discoveries | | | 39 | | | | 172 | | | | 108 | | | | 319 | | | | 128 | | | | 447 | | | | 39 | | | | 172 | | | | 108 | | | | 319 | | | | 128 | | | | 447 | |
| Revisions of Previous Estimates | | | 595 | | | | (80 | ) | | | 57 | | | | 572 | | | | 101 | | | | 673 | | | | 595 | | | | (80 | ) | | | 57 | | | | 572 | | | | 101 | | | | 673 | |
| Production | | | (685 | ) | | | (2,582 | ) | | | (69 | ) | | | (3,336 | ) | | | (272 | ) | | | (3,608 | ) | | | (685 | ) | | | (2,582 | ) | | | (69 | ) | | | (3,336 | ) | | | (272 | ) | | | (3,608 | ) |
| Purchases of Minerals in Place | | | — | | | | 274 | | | | — | | | | 274 | | | | — | | | | 274 | | | | — | | | | 274 | | | | — | | | | 274 | | | | — | | | | 274 | |
| Sales of Minerals in Place | | | — | | | | — | | | | — | | | | — | | | | (25 | ) | | | (25 | ) | | | — | | | | — | | | | — | | | | — | | | | (25 | ) | | | (25 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2006 | | | 1,244 | | | | 54,869 | | | | 273 | | | | 56,386 | | | | 1,632 | | | | 58,018 | | | | 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, 2003 | | | 2,533 | | | | 40,079 | | | | 139 | | | | 42,751 | | | | 2,391 | | | | 45,142 | | |
| September 30, 2004 | | | 2,061 | | | | 38,631 | | | | 148 | | | | 40,840 | | | | 2,104 | | | | 42,944 | | |
| September 30, 2005 | | | 1,229 | | | | 41,701 | | | | 177 | | | | 43,107 | | | | 1,700 | | | | 44,807 | | | | 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 | | | | 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 | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited)
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
109
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 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
United States | | | | | | | | | | | | |
| Future Cash Inflows | | $ | 3,911,059 | | | $ | 6,138,522 | | | $ | 3,728,168 | |
| Less: | | | | | | | | | | | | |
| Future Production Costs | | | 758,258 | | | | 777,417 | | | | 676,361 | |
| Future Development Costs | | | 205,497 | | | | 188,795 | | | | 124,298 | |
| Future Income Tax Expense at Applicable Statutory Rate | | | 1,019,307 | | | | 1,868,548 | | | | 995,327 | |
| | | | | | | | | | | | | |
| Future Net Cash Flows | | | 1,927,997 | | | | 3,303,762 | | | | 1,932,182 | |
| Less: | | | | | | | | | | | | |
| 10% Annual Discount for Estimated Timing of Cash Flows | | | 1,066,338 | | | | 1,812,230 | | | | 996,813 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows | | | 861,659 | | | | 1,491,532 | | | | 935,369 | |
| | | | | | | | | | | | | |
110112
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
Canada | | | | | | | | | | | | |
| Future Cash Inflows | | | 197,227 | | | | 601,210 | | | | 343,026 | |
| Less: | | | | | | | | | | | | |
| Future Production Costs | | | 92,234 | | | | 136,338 | | | | 111,519 | |
| Future Development Costs | | | 11,520 | | | | 12,197 | | | | 13,222 | |
| Future Income Tax Expense at Applicable Statutory Rate | | | (151 | ) | | | 137,524 | | | | 60,610 | |
| | | | | | | | | | | | | |
| Future Net Cash Flows | | | 93,624 | | | | 315,151 | | | | 157,675 | |
| Less: | | | | | | | | | | | | |
| 10% Annual Discount for Estimated Timing of Cash Flows | | | 19,375 | | | | 108,508 | | | | 46,945 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows | | | 74,249 | | | | 206,643 | | | | 110,730 | |
| | | | | | | | | | | | | |
Total | | | | | | | | | | | | |
| Future Cash Inflows | | | 4,108,286 | | | | 6,739,732 | | | | 4,071,194 | |
| Less: | | | | | | | | | | | | |
| Future Production Costs | | | 850,492 | | | | 913,755 | | | | 787,880 | |
| Future Development Costs | | | 217,017 | | | | 200,992 | | | | 137,520 | |
| Future Income Tax Expense at Applicable Statutory Rate | | | 1,019,156 | | | | 2,006,072 | | | | 1,055,937 | |
| | | | | | | | | | | | | |
| Future Net Cash Flows | | | 2,021,621 | | | | 3,618,913 | | | | 2,089,857 | |
| Less: | | | | | | | | | | | | |
| 10% Annual Discount for Estimated Timing of Cash Flows | | | 1,085,713 | | | | 1,920,738 | | | | 1,043,758 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 935,908 | | | $ | 1,698,175 | | | $ | 1,046,099 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | |
111113
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
United States | | | | | | | | | | | | |
| Standardized Measure of Discounted Future | | | | | | | | | | | | |
| Net Cash Flows at Beginning of Year | | $ | 1,491,532 | | | $ | 935,369 | | | $ | 733,248 | |
| Sales, Net of Production Costs | | | (306,147 | ) | | | (272,707 | ) | | | (251,194 | ) |
| Net Changes in Prices, Net of Production Costs | | | (941,545 | ) | | | 1,093,353 | | | | 592,326 | |
| Purchases of Minerals in Place | | | 7,607 | | | | — | | | | — | |
| Sales of Minerals in Place | | | — | | | | (762 | ) | | | (5,554 | ) |
| Extensions and Discoveries | | | 66,975 | | | | 100,102 | | | | 16,638 | |
| Changes in Estimated Future Development Costs | | | (83,750 | ) | | | (89,805 | ) | | | (40,042 | ) |
| Previously Estimated Development Costs Incurred | | | 67,048 | | | | 25,038 | | | | 32,653 | |
| Net Change in Income Taxes at Applicable Statutory Rate | | | 404,176 | | | | (362,956 | ) | | | (166,055 | ) |
| Revisions of Previous Quantity Estimates | | | 4,850 | | | | 25,055 | | | | (5,107 | ) |
| Accretion of Discount and Other | | | 150,913 | | | | 38,845 | | | | 28,456 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows at End of Year | | | 861,659 | | | | 1,491,532 | | | | 935,369 | |
| | | | | | | | | | | | | |
Canada | | | | | | | | | | | | |
| Standardized Measure of Discounted Future | | | | | | | | | | | | |
| Net Cash Flows at Beginning of Year | | | 206,643 | | | | 110,730 | | | | 85,157 | |
| Sales, Net of Production Costs | | | (54,176 | ) | | | (49,467 | ) | | | (32,201 | ) |
| Net Changes in Prices, Net of Production Costs | | | (180,216 | ) | | | 174,985 | | | | 29,230 | |
| Purchases of Minerals in Place | | | — | | | | — | | | | — | |
| Sales of Minerals in Place | | | (238 | ) | | | (3,751 | ) | | | — | |
| Extensions and Discoveries | | | 10,369 | | | | 31,028 | | | | 36,986 | |
| Changes in Estimated Future Development Costs | | | (3,282 | ) | | | (11,007 | ) | | | (8,491 | ) |
| Previously Estimated Development Costs Incurred | | | 4,450 | | | | 12,032 | | | | 5,055 | |
| Net Change in Income Taxes at Applicable Statutory Rate | | | 82,966 | | | | (51,541 | ) | | | (2,640 | ) |
| Revisions of Previous Quantity Estimates | | | (15,478 | ) | | | (5,990 | ) | | | (19,369 | ) |
| Accretion of Discount and Other | | | 23,211 | | | | (376 | ) | | | 17,003 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows at End of Year | | | 74,249 | | | | 206,643 | | | | 110,730 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | 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 | |
| | | | | | | | | | | | | |
112114
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | |
| | | Year Ended September 30 | |
| | | 2006 | | | 2005 | | | 2004 | |
| | | (Thousands) | |
| |
Total | | | | | | | | | | | | |
| Standardized Measure of Discounted Future | | | | | | | | | | | | |
| Net Cash Flows at Beginning of Year | | | 1,698,175 | | | | 1,046,099 | | | | 818,405 | |
| Sales, Net of Production Costs | | | (360,323 | ) | | | (322,174 | ) | | | (283,395 | ) |
| Net Changes in Prices, Net of Production Costs | | | (1,121,761 | ) | | | 1,268,338 | | | | 621,556 | |
| Purchases of Minerals in Place | | | 7,607 | | | | — | | | | — | |
| Sales of Minerals in Place | | | (238 | ) | | | (4,513 | ) | | | (5,554 | ) |
| Extensions and Discoveries | | | 77,344 | | | | 131,130 | | | | 53,624 | |
| Changes in Estimated Future Development Costs | | | (87,032 | ) | | | (100,812 | ) | | | (48,533 | ) |
| Previously Estimated Development Costs Incurred | | | 71,498 | | | | 37,070 | | | | 37,708 | |
| Net Change in Income Taxes at Applicable Statutory Rate | | | 487,142 | | | | (414,497 | ) | | | (168,695 | ) |
| Revisions of Previous Quantity Estimates | | | (10,628 | ) | | | 19,065 | | | | (24,476 | ) |
| Accretion of Discount and Other | | | 174,124 | | | | 38,469 | | | | 45,459 | |
| | | | | | | | | | | | | |
| Standardized Measure of Discounted Future Net Cash Flows at End of Year | | $ | 935,908 | | | $ | 1,698,175 | | | $ | 1,046,099 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | 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 | | Deductions(3) | | Period | | | Period | | Expenses | | Accounts(1) | | Deductions(2) | | Period | |
| | | (Thousands) | | | (Thousands) | |
| |
Year Ended September 30, 2008 | | | | | | | | | | | | | | | | | | | | | |
| Allowance for Uncollectible Accounts | | | $ | 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 | |
| | | | | | | | | | | | | |
Year Ended September 30, 2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Allowance for Uncollectible Accounts | | $ | 26,940 | | | $ | 29,088 | | | $ | 907 | (1) | | $ | 25,508 | | | $ | 31,427 | | | $ | 26,940 | | | $ | 29,088 | | | $ | 907 | | | $ | 25,508 | | | $ | 31,427 | |
| Deferred Tax Valuation Allowance | | $ | 2,877 | | | $ | (2,877 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | 2,877 | | | $ | (2,877 | ) | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
Year Ended September 30, 2005 | | | | | | | | | | | | | | | | | | | | | |
| Allowance for Uncollectible Accounts | | $ | 17,440 | | | $ | 31,113 | | | $ | 2,480 | (2) | | $ | 24,093 | | | $ | 26,940 | | |
| Deferred Tax Valuation Allowance | | $ | 2,877 | | | $ | — | | | $ | — | | | $ | — | | | $ | 2,877 | | |
| | | | | | | | | | | | | |
Year Ended September 30, 2004 | | | | | | | | | | | | | | | | | | | | | |
| Allowance for Uncollectible Accounts | | $ | 17,943 | | | $ | 20,328 | | | $ | — | | | $ | 20,831 | | | $ | 17,440 | | |
| Deferred Tax Valuation Allowance | | $ | 6,357 | | | $ | (3,480 | ) | | $ | — | | | $ | — | | | $ | 2,877 | | |
| | | | | | | | | | | | | |
| | |
| (1) | | Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate settlement.agreement. |
| |
| (2) | | Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate settlements ($4.5 million). Also includes amounts removed with the sale of U.E. (-$2.02 million). |
|
(3) | | Amounts represent net accounts receivable written-off. |
113115
| |
| 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 requiredthe time periods.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, 2006.2008.
Management’s 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, 2006.2008. 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, 2006.2008.
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 a report on management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2006.2008. 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, 20062008 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, and Executive Officers of the Registrantand 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 February 15, 2007 Annual2009
114116
Annual Meeting of ShareholdersStockholders will be filed with the SEC not later than 120 days after September 30, 2006.2008. The information concerning directors is set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2010,2012,” “Directors Whose Terms Expire in 2009,2011,” “Directors Whose Terms Expire in 2008,2010,” and “Compliance with Section“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 Securities Exchange ActBoard of 1934”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 February 15, 20072009 Annual Meeting of ShareholdersStockholders will be filed with the SEC not later than 120 days after September 30, 2006.2008. The information concerning executive compensation is 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” and the “Corporate Performance Graph,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 February 15, 20072009 Annual Meeting of ShareholdersStockholders will be filed with the SEC not later than 120 days after September 30, 2006.2008. The equity compensation plan information is 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 February 15, 20072009 Annual Meeting of ShareholdersStockholders will be filed with the SEC not later than 120 days after September 30, 2006.2008. The information concerning security ownership of certain beneficial owners is 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 February 15, 20072009 Annual Meeting of ShareholdersStockholders will be filed with the SEC not later than 120 days after September 30, 2006.2008. The information concerning security ownership of
117
management is set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
115
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 February 15, 20072009 Annual Meeting of ShareholdersStockholders will be filed with the SEC not later than 120 days after September 30, 2006.2008. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the headingheadings “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 February 15, 20072009 Annual Meeting of ShareholdersStockholders will be filed with the SEC not later than 120 days after September 30, 2006.2008. The information concerning principal accountant fees and services is 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 on December 9, 2004June 11, 2008 (Exhibit 3(ii),3.1,Form 8-K dated December 9, 2004June 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) |
| • | | | Third Supplemental Indenture, dated as of December 1, 1982,to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No.33-49401) |
| • | | | Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b),Form 8-K dated February 14, 1992 in File No. 1-3880) |
116118
| | | | | |
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) |
120
| | | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
| |
| | • | | | Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c),Form 8-K dated June 18, 1992 in File No. 1-3880) |
| • | | | Thirteenth Supplemental Indenture, dated as of March 1,1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No.33-49401) |
| • | | | Fourteenth Supplemental Indenture, dated as of July 1, 1993,to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) |
| • | | | Fifteenth Supplemental Indenture, dated as of September 1,1996, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) |
| • | | | 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 File No. 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 File No. 1-3880) |
| • | | | Amended and Restated Rights Agreement, dated as of April 30,1999, between the Company and HSBC Bank USA(Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880) |
| • | | | Certificate of Adjustment, dated September 7, 2001, to the Amended and Restated Rights Agreement dated as of April 30,1999, between the Company and HSBC Bank USA (Exhibit 4, Form8-K dated September 7, 2001 in File No. 1-3880) |
| • | | | Officers Certificate establishing 6.50% Notes due 2022, dated September 18, 2002 (Exhibit 4,Form 8-K dated October 3, 2002 in File No. 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 File No. 1-3880) |
| 10 | | | Material Contracts: |
| | | | Contracts other than compensatory plans, contracts or arrangements: |
| • | | | Form of Indemnification Agreement, dated September 2006, between the Company and each Director (Exhibit 10.1,Form 8-K dated September 18, 2006 in File No. 1-3880) |
| • | | | 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 File No. 1-3880) |
| | | | Compensatory plans, contracts or arrangements: |
| • | | | Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Distribution Corporation and each of Philip C. Ackerman, Anna Marie Cellino, Paula M, Ciprich, Donna L. DeCarolis, James D. Ramsdell, David F. Smith and Ronald J. Tanski (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880) |
| • | | | Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Supply Corporation and John R. Pustulka (Exhibit 10.2,Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880) |
| • | | | National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) |
| • | | | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) |
| • | | | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) |
| • | | | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 1996 in File No. 1-3880) |
117
| | | | |
Exhibit
| | Description of
|
Number
| | Exhibits
|
|
| • | | | 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 File No. 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 File No. 1-3880) |
| • | | | Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) |
| • | | | National Fuel Gas Company 1997 Award and Option Plan, amended through September 8, 2005 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 2005 in File No. 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 File No. 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 File 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 File No. 1-3880) |
| • | | | Description of performance goals for Chief Executive Officer under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 2004 in File No. 1-3880) |
| • | | | Description of performance goals for Chief Executive Officer under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2005 in File No. 1-3880) |
| • | | | Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective March 9, 2005 (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2005 in File No. 1-3880) |
| • | | | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7,Form10-K for fiscal year ended September 30, 1994 in File No. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) |
| • | | | 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 File No. 1-3880) |
| • | | | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3,(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,Form10-KForm 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 10.1,10.1,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 inFile 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) |
118
| | | | |
Exhibit
| | Description of
|
Number
| | Exhibits
|
|
| | • | | | 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) |
| | • | | | Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Dennis J. Seeley (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) |
| • | | | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) |
| • | | | Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997, between the Company and Bruce H. Hale (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) |
| • | | | Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12,Form 10-K for fiscal year ended September 30, 1999 in File No. 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) |
| | • | | | 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) |
| | • | | | 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 File No. 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 File No. 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 File No. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) |
119121
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Exhibit
| Exhibit
| | Description of
| Exhibit
| | Description of
|
Number | Number | | Exhibits | Number | | Exhibits |
| |
| | • | | | 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 File No. 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) |
| | • | | | National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in File No. 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) |
| | • | | | Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | • | | | 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) |
| | • | | | Retirement Benefit Agreement for David F. Smith, dated September 22, 2003,between the Company and David F. Smith (Exhibit 10.2,Form10-K for fiscal year ended September 30, 2003 in File No. 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) |
| | • | | | Amendment No. 1 to the Retirement Benefit Agreement for David F. Smith, dated September 8, 2005, between the Company and David F. Smith (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | 10 | .5 | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008 |
| | • | | | Description of performance goals for certain executive officers (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2005 in File No. 1-3880) | • | | | National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| | • | | | Retirement Agreement, dated August 1, 2005, between the Company and Bruce H. Hale (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 2005 in File No. 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) |
| | • | | | Commission Agreement, dated August 1, 2005, between the Company and Bruce H. Hale (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | • | | | National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in FileNo. 1-3880) |
| | • | | | Description of bonuses awarded to executive officer (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880) | • | | | Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| | • | | | Description of performance goals for certain executive officers (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 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) |
| | • | | | Noncompete and Restrictive Covenant Agreement, dated February 1, 2006, between the Company and Dennis J. Seeley (Exhibit 10.3,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 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 salaries of certain executive officers (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 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 assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in File 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 long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.2,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 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) |
| | • | | | 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 File No. 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) |
| | 10 | .1 | | Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit | 12 | | | Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2004 through 2008 |
| | • | | | Retirement Agreement, dated July 1, 2006, between the Company and James A. Beck (Exhibit 10.4,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880) | 21 | | | Subsidiaries of the Registrant |
| | • | | | Contract for Consulting Services, dated July 1, 2006, between the Company and James A. Beck (Exhibit 10.5,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880) | 23 | | | Consents of Experts: |
| | 12 | | | Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2002 through 2006 | 23 | .1 | | Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation |
| | 21 | | | Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report onForm 10-K | 23 | .2 | | Consent of Independent Registered Public Accounting Firm |
| | 23 | | | Consents of Experts: | 31 | | | Rule 13a-14(a)/15d-14(a) Certifications: |
| | 23 | .1 | | Consent of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation | 31 | .1 | | Written statements of Chief Executive Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act |
| | 23 | .2 | | Consent of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc. | |
| | 23 | .3 | | Consent of Independent Registered Public Accounting Firm | |
| | 31 | | | Rule 13a-15(e)/15d-15(e) Certifications | |
120122
| | | | | | | | | |
Exhibit
| Exhibit
| | Description of
| Exhibit
| | Description of
|
Number | Number | | Exhibits | Number | | Exhibits |
| |
| | 31 | .1 | | Written statements of Chief Executive Officer pursuant toRule 13a-15(e)/15d-15(e) of the Exchange Act. | 31 | .2 | | Written statements of Principal Financial Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act |
| | 31 | .2 | | Written statements of Principal Financial Officer pursuant toRule 13a-15(e)/15d-15(e) of the Exchange Act. | 32 | | | Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
| | 32•• | | | Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | 99 | | | Additional Exhibits: |
| | 99 | | | Additional Exhibits: | 99 | .1 | | Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation |
| | 99 | .1 | | Report of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation | 99 | .2 | | Company Maps |
| | 99 | .2 | | Report of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc. | • | | | Incorporated herein by reference as indicated. |
| | 99 | .3 | | Company Maps | | | | All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report onForm 10-K |
| | • | | | The Company agrees to furnish to the SEC upon request the following instruments with respect to long-term debt that the Company has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A): | •• | | | 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 |
| | | | | Secured Credit Agreement, dated as of June 5, 1997, among the Empire State Pipeline, as borrower, Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank), as administrative agent, and Chase Securities, as arranger. | |
| | | | | First Amendment to Secured Credit Agreement, dated as of May 28, 2002, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, and JPMorgan Chase Bank, as administrative agent. | |
| | | | | Second Amendment to Secured Credit Agreement, dated as of February 6, 2003, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, as amended, and JPMorgan Chase Bank, as administrative agent. | |
| | • | | | 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 and 34-47986, 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. | |
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