The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.
performs a credit check, and then on an ongoinga quarterly basis monitors counterparty credit exposure. Management has obtained guarantees from manyThe majority of the parent companies of the respectiveCompany’s counterparties to its derivatives.are financial institutions and energy traders. The Company hasover-the-counter swap positions with ten counterparties. At September 30, 2008,2009, the Company had eleven counterparties for its over the counter derivative financial instruments and no individual counterparty represented greater than 42% of total credit risk (measured as volumes hedged by an individual counterparty as a percentagethat were in gain positions with eight of the Company’s total over the counter volumes hedged).counterparties. The Company recordedhad derivative financial instruments that were in loss positions with the other two counterparties. The Company had $26.6 million of credit exposure with one counterparty (which is rated A1 (Moody’s Investor Service), A (S&P), and A+ (Fitch Ratings Service) as of September 30, 2009). On average for those financial instruments that were in a $0.6gain position, the Company had $1.8 million reductionof credit exposure per counterparty with the other seven counterparties that were in a gain position. The Company had not received any collateral from the counterparties at September 30, 2009 since the Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
As of September 30, 2009, eight of the ten counterparties to the fair market valueCompany’s outstanding derivative instrument contracts (specifically theover-the-counter swaps) had a common credit-risk-related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (the lower of the S&P or Moody’s Debt Rating), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position and the Company’s credit rating declined, then additional hedging collateral deposits would be required. At September 30, 2009, these credit-risk related contingency features were not triggered since the Company had assets of $37.9 million related to derivative financial instruments with the eight counterparties.
For its exchange traded futures contracts, which are in an asset position, the Company had paid $0.8 million in hedging collateral as of September 30, 2009. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on its assessment of counterparty credit risk. This credit reserve was determined by applying default probabilities to the anticipated cash flowsopen positions (i.e. those positions that the Companyhave been settled for cash) and margin requirements. (This is expecting from its counterparties.discussed in Note A under Hedging Collateral Deposits.)
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Interest Rate Risk
The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt as well as the other long-term debt of certain of the Company’s subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2008:2009:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Principal Amounts by Expected Maturity Dates | | | Principal Amounts by Expected Maturity Dates | |
| | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | Thereafter | | Total | | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 | | Thereafter | | Total | |
| | (Dollars in millions) | | | | | (Dollars in millions) | |
|
Long-Term Fixed Rate Debt | | $ | 100.0 | (1) | | $ | — | | | $ | 200.0 | | | $ | 150.0 | | | $ | 250.0 | | | $ | 399.0 | | | $ | 1,099.0 | | | $ | — | | | $ | 200.0 | | | $ | 150.0 | | | $ | 250.0 | | | $ | — | | | $ | 649.0 | | | $ | 1,249.0 | |
Weighted Average Interest Rate Paid | | | 6.0 | % | | | — | | | | 7.5 | % | | | 6.7 | % | | | 5.3 | % | | | 6.7 | % | | | 6.5 | % | | | — | | | | 7.5 | % | | | 6.7 | % | | | 5.3 | % | | | — | | | | 7.5 | % | | | 7.0 | % |
Fair Value of Long-Term Fixed Rate Debt = $1,027.1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Long-Term Fixed Rate Debt = $1,347.4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
(1) | | These notes have been classified as Current Portion of Long-Term Debt on the Company’s Consolidated Balance Sheet. |
RATE AND REGULATORY MATTERS
Utility Operation
Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
New York Jurisdiction
On January 29, 2007,Customer delivery rates charged by Distribution Corporation commencedCorporation’s New York division were established in a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million. Following standard procedure, the NYPSC suspended the proposed tariff amendments to enable its staff and intervenors to conduct a routine investigation and hold hearings. Distribution Corporation explained in the filing that its request for rate relief was necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also included a proposal for an efficiency and conservation initiative with a revenue decoupling mechanism designed to render the Company indifferent to throughput reductions resulting from conservation. On September 20, 2007, the NYPSCorder issued an order approving, with modifications, Distribution Corporation’s conservation program for implementation on an accelerated basis. Associated ratemaking issues, however, were reserved for consideration in the rate.
On December 21, 2007 by the NYPSC issued aNYPSC. The rate order providing for an annual rateapproved a revenue increase of $1.8 million
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annually, together with a monthly bill surcharge that would collect up to $10.8 million to recover expenses for implementation of thean efficiency and conservation incentive program. The rate increase and bill surcharge became effective December 28, 2007. The rate order further provided for a return on equity of 9.1%. TheIn connection with the efficiency and conservation program, the rate order also adopted Distribution Corporation’s proposed revenue decoupling mechanism. The revenue decoupling mechanism, like others, “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. The Company surcharges or credits any difference from the average weather normalized usage per customer account. The surcharge or credit is calculated to recover total margin for the most recent twelve-month period ending December 31, and is applied to customer bills annually, beginning March 1st.
On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal contends that portions of the rate order should be invalidated because they fail to meet the applicable legal standard for agency decisions. Among the issues challenged by the Company are the reasonableness of the NYPSC’s disallowance of expense items including health care costs, and the
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methodology used for calculating rate of return, which the appeal contends understated the Company’s cost of equity. Briefs were filed and oral argument was held on October 14, 2009. The Company cannot predict the outcome of the appeal at this time.
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the current rate ofone-third of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge equal, as applied, to an additional one percent of the utility’s gross operating revenue. As a result of this amendment, Distribution Corporation’s New York Division paid a total assessment of $26.2 million during fiscal 2009, of which $22.9 million was labeled as the temporary surcharge. The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills.
Pennsylvania Jurisdiction
On June 1, 2006, Distribution Corporation filed proposed tariff amendments with PaPUC to increase annual revenues by $25.9 million to cover increases in the cost of service to be effective July 30, 2006. The rate request was filed to address increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and suspending the proposed tariff amendments until March 2, 2007. On October 2, 2006, the parties, including Distribution Corporation, Staff of the PaPUC and intervenors, executed an agreement (Settlement) proposing to settle all issues in the rate proceeding. The Settlement included an increase in annual revenues of $14.3 million to non-gas revenues, an agreementcurrently does not to filehave a rate case until January 28, 2008 aton file with the earliest and an early implementation date. The SettlementPaPUC. Distribution Corporation’s current tariff in its Pennsylvania jurisdiction was last approved by the PaPUC at its meeting on November 30, 2006 and the new ratesas part of a settlement agreement that became effective January 1, 2007.
Pipeline and Storage
Supply Corporation currently does not have a rate case on file with the FERC. The rate settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general rate filing before then, with some exceptions specified in the settlement.
Empire currently does not have a rate case on file with the NYPSC. Among the issues resolved in connection with Empire’s FERC application to build thenew facilities (the Empire Connector are the rates and terms of service that will become applicable to all of Empire’s business, effective upon Empire constructing and placing its new facilitiesproject) were placed into service (currently expected foron December 2008). At10, 2008. As of that time,date, Empire will becomebecame an interstate pipeline subject to FERC regulation.regulation, performing services under a FERC-approved tariff and at FERC-approved rates. The December 21, 2006 FERC order described in the following paragraphissuing Empire its Certificate of Public Convenience and Necessity requires Empire to makefile a filingcost and revenue study at the FERC, within three years after the in-service date, justifyingin conjunction with which Empire will either justify Empire’s existing recourse rates or proposingpropose alternative rates.
On December 21, 2006, the FERC issued an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. The Empire Certificate contains various environmental and other conditions. Empire accepted that Certificate and received additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies. Empire also received, from all six upstate New York counties in which it will build the Empire Connector project, final approval of sales tax exemptions and temporary partial property tax abatements. In June 2007, Empire signed a firm transportation service agreement with KeySpan Gas East Corporation, under which Empire is obligated to provide transportation service that required construction of this project. Construction began in September 2007 and is anticipated to be ready to commence service in December 2008, on or before the in-service date of the Millennium Pipeline to which it will connect.
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmentalclean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2008,2009, the Company has estimated its remainingclean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $19.4$18.7 million to $23.6$22.9 million. The
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minimum estimated liability of $19.4$18.7 million has been recorded on the Consolidated Balance Sheet at September 30, 2008.2009. The Company expects to recover its environmentalclean-up costs from a combination
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of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet. Other than discussed in Note HI (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
For further discussion refer to Item 8 at Note HI — Commitments and Contingencies under the heading “Environmental Matters.”
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussions. If enacted or adopted, legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Proposed measures could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
NEW AUTHORITATIVE ACCOUNTING PRONOUNCEMENTSAND FINANCIAL REPORTING GUIDANCE
In September 2006, the FASB issued SFAS 157. SFAS 157 providesauthoritative guidance for using fair value to measure assets and liabilities. The pronouncementThis guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157This guidance is to be applied whenever another standard requires or allows assets or liabilities are to be measured at fair value. In accordance with FASB Staff PositionFAS No. 157-2, SFAS 157 is effectiveOn October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The same FASB Staff Positionbasis. This guidance delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of the authoritative guidance for financial assets and financial liabilities, refer to Item 8 at Note F — Fair Value Measurements. The Company does not expectis currently evaluating the impact that SFAS 157the adoption of the authoritative guidance for nonfinancial assets and nonfinancial liabilities will have a significant impact on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of this guidance. The Company does not believe there are any nonfinancial liabilities that will be impacted by the adoption of this guidance.
In September 2006, the FASB also issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158authoritative guidance which requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncementThis guidance requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. This guidance also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158,this authoritative guidance, the Company has recognized the funded status of its benefit plans and implemented the related disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will bewas fully adopted by the Company by the endas of fiscalSeptember 30, 2009. Currently, theThe Company measureshas historically measured its plan assets and benefit obligations using a June 30th measurement date. AtAs a result of the change to a September 30, 2007, in order to recognize the funded status of its pension and post-retirement benefit plans in accordance with SFAS 158,30th measurement date, the Company recorded additional liabilities or reduced assetsfifteen months of pension and other post-retirement benefit costs during fiscal 2009. Such costs were calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to
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$5.1 million and were recorded by the Company during the quarter ended December 31, 2008 as a cumulative amount of $78.7$3.8 million ($71.1 million net of deferred tax benefits recognized for the portion recorded as an increase to Accumulated Other Comprehensive Loss). Of the $71.1 million recognized, $61.9 million was recorded as an increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments $12.5and a $1.3 million (net of deferred tax benefits of $7.6 million) was recorded as an increase($0.8 million after tax) adjustment to Accumulated Other Comprehensive Loss, and $3.3 million was recorded as an increase to Other Regulatory Liabilitiesearnings reinvested in the Company’s Utility segment. The Company has recorded amounts to Other Regulatory Assets or Other Regulatory Liabilities in the Utility and Pipeline and Storage segments in accordance with the provisions of SFAS 71. The Company, in those segments, has certain regulatory commission authorizations, which allow the Company to defer as a regulatory asset or liability the difference between pension and post-retirement benefit costs as calculated in accordance with SFAS 87 and SFAS 106 and what is collected in rates.business. Refer to Item 8 at Note GH — Retirement Plan and Other Post-Retirement Benefits for further disclosures regarding the impact of SFAS 158this authoritative guidance on the Company’s consolidated financial statements.
In February 2007, the FASB issued SFAS 159. SFAS 159 permits entities to choose to measure many financial instruments at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 is effective as of the Company’s first quarter of fiscal 2009. The Company does not plan to elect the fair value measurement option for any of its financial instruments other than those that are already being measured at fair value.
In December 2007, the FASB issued SFAS 141R. SFAS 141R willrevised authoritative guidance that significantly changechanges the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies,
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acquisition costs, in process research and development and restructuring costs. In addition, under SFAS 141R,this guidance, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. SFAS 141RThis guidance is effective as of the Company’s first quarter of fiscal 2010.
In December 2007, the FASB issued SFAS 160. SFAS 160 will changeauthoritative guidance that changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160This authoritative guidance is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
In March 2008, the FASB issued SFAS 161. SFAS 161authoritative guidance that requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133authoritative guidance for derivative instruments and its related interpretations,hedging activities, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161The Company adopted the disclosure provisions of this authoritative guidance during the Company’s second quarter of fiscal 2009. Refer to Item 8 at Note G — Financial Instruments for these disclosures.
In June 2008, the FASB issued authoritative guidance concerning whether certain instruments granted in share-based payment transactions are participating securities. This guidance specified that unvested share-based payment awards that contain nonforfeitable rights to dividends are participating securities and shall be included in the computation of earnings per share pursuant to the “two-class” method. The “two-class” method allocates undistributed earnings between common shares and participating securities. This authoritative guidance is effective as of the Company’s secondfirst quarter of fiscal 2009.2010. The Company does not believe this guidance will have a material impact on its earnings per share calculation.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements are effective for the Company’sForm 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that the adoption of SFAS 161these rules will have on its consolidated financial statements and MD&A disclosures.
In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements are required for the Company’sForm 10-K for the period ended
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September 30, 2010. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
Effective with the June 30, 2009Form 10-Q, the Company adopted the FASB authoritative guidance for subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Refer to Item 8 at Note R — Subsequent Events for disclosures made as a result of the adoption of this guidance.
In June 2009, the FASB issued authoritative guidance that establishes the FASB Accounting Standards Codificationtm (the Codification) as the source of authoritative GAAP recognized by the FASB to be applied by all nongovernmental entities in the notespreparation of financial statements in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities law are also sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. The Codification was effective for interim and annual periods ending after September 15, 2009. Effective with this September 30, 2009Form 10-K, the Company has updated its disclosures to conform to the Codification. There has been no impact on the Company’s consolidated financial statements.statements as the Codification does not change or alter existing GAAP.
EFFECTS OF INFLATION
Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The Company is including the following cautionary statement in thisForm 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to
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other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
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1. | Financial and economic conditions, including the availability of credit, and their effect on the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments; |
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2. | Occurrences affecting the Company’s ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; |
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3. | Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; |
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4. | The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; |
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5. | Economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters; |
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6. | Changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; |
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7. | Changes in demographic patterns and weather conditions; |
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8. | Changes in the availabilityand/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments or the valuation of the Company’s natural gas and oil reserves; |
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9. | Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; |
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10. | Uncertainty of oil and gas reserve estimates; |
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11. | AbilityFactors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations;operations, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations; |
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12. | Significant changes from expectations indifferences between the Company’s projected and actual production levels for natural gas or oil; |
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13. | Changes in the availabilityand/or price of derivative financial instruments; |
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14. | Changes in the price differentials between various types of oil;oil having different qualityand/or different geographic locations, or changes in the price differentials between natural gas having different heating valuesand/or different geographic locations; |
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15. | Inability to obtain new customers or retain existing ones; |
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16. | Significant changes in competitive factors affecting the Company; |
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17. | Changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations; |
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18. | Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; |
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19. | Unanticipated impacts of restructuring initiatives in the natural gas and electric industries; |
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20. | Significant changes from expectations indifferences between the Company’s projected and actual capital expenditures and operating expenses, and unanticipated project delays or changes in project costs or plans; |
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21. | The nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; |
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22. | Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; |
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23. | Changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company; |
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24. 23. | Significant changes in tax rates or policies or in rates of inflation or interest; |
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25. 24. | Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; |
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26. 25. | Changes in accounting principles or the application of such principles to the Company; |
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27. 26. | The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; |
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28. 27. | Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or |
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29. 28. | Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
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Item 7A | Quantitative and Qualitative Disclosures About Market Risk |
Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A.
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Item 8 | Financial Statements and Supplementary Data |
Index to Financial Statements
| | | | |
| | Page |
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Financial Statements: | | | | |
| | | | |
| | | 6064 | |
| | | 6165 | |
| | | 6266 | |
| | | 6367 | |
| | | 6468 | |
| | | 6569 | |
Financial Statement Schedules: | | | | |
For the three years ended September 30, 20082009 | | | | |
| | | 115124 | |
All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.
Supplementary Data
Supplementary data that is included in Note MO — Quarterly Financial Data (unaudited) and Note OQ — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of National Fuel Gas Company:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 20082009 and 2007,2008, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 20082009 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2008,2009, based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Buffalo, New York
November 26, 2008
60
NATIONAL FUEL GAS COMPANY
REINVESTED IN THE BUSINESS
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands of dollars, except per common
| |
| | share amounts) | |
|
INCOME | | | | | | | | | | | | |
Operating Revenues | | $ | 2,400,361 | | | $ | 2,039,566 | | | $ | 2,239,675 | |
| | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | |
Purchased Gas | | | 1,235,157 | | | | 1,018,081 | | | | 1,267,562 | |
Operation and Maintenance | | | 432,871 | | | | 396,408 | | | | 395,289 | |
Property, Franchise and Other Taxes | | | 75,585 | | | | 70,660 | | | | 69,202 | |
Depreciation, Depletion and Amortization | | | 170,623 | | | | 157,919 | | | | 151,999 | |
| | | | | | | | | | | | |
| | | 1,914,236 | | | | 1,643,068 | | | | 1,884,052 | |
| | | | | | | | | | | | |
Operating Income | | | 486,125 | | | | 396,498 | | | | 355,623 | |
Other Income (Expense): | | | | | | | | | | | | |
Income from Unconsolidated Subsidiaries | | | 6,303 | | | | 4,979 | | | | 3,583 | |
Other Income | | | 7,376 | | | | 4,936 | | | | 2,825 | |
Interest Income | | | 10,815 | | | | 1,550 | | | | 9,409 | |
Interest Expense on Long-Term Debt | | | (70,099 | ) | | | (68,446 | ) | | | (72,629 | ) |
Other Interest Expense | | | (3,870 | ) | | | (6,029 | ) | | | (5,952 | ) |
| | | | | | | | | | | | |
Income from Continuing Operations Before Income Taxes | | | 436,650 | | | | 333,488 | | | | 292,859 | |
Income Tax Expense | | | 167,922 | | | | 131,813 | | | | 108,245 | |
| | | | | | | | | | | | |
Income from Continuing Operations | | | 268,728 | | | | 201,675 | | | | 184,614 | |
Discontinued Operations: | | | | | | | | | | | | |
Income (Loss) from Operations, Net of Tax | | | — | | | | 15,479 | | | | (46,523 | ) |
Gain on Disposal, Net of Tax | | | — | | | | 120,301 | | | | — | |
| | | | | | | | | | | | |
Income (Loss) from Discontinued Operations, Net of Tax | | | — | | | | 135,780 | | | | (46,523 | ) |
| | | | | | | | | | | | |
Net Income Available for Common Stock | | | 268,728 | | | | 337,455 | | | | 138,091 | |
| | | | | | | | | | | | |
EARNINGS REINVESTED IN THE BUSINESS | | | | | | | | | | | | |
Balance at Beginning of Year | | | 983,776 | | | | 786,013 | | | | 813,020 | |
| | | | | | | | | | | | |
| | | 1,252,504 | | | | 1,123,468 | | | | 951,111 | |
Share Repurchases | | | (194,776 | ) | | | (38,196 | ) | | | (66,269 | ) |
Cumulative Effect of Adoption of FIN 48 | | | (406 | ) | | | — | | | | — | |
Dividends on Common Stock | | | (103,523 | ) | | | (101,496 | ) | | | (98,829 | ) |
| | | | | | | | | | | | |
Balance at End of Year | | $ | 953,799 | | | $ | 983,776 | | | $ | 786,013 | |
| | | | | | | | | | | | |
Earnings Per Common Share: | | | | | | | | | | | | |
Basic: | | | | | | | | | | | | |
Income from Continuing Operations | | $ | 3.27 | | | $ | 2.43 | | | $ | 2.20 | |
Income (Loss) from Discontinued Operations | | | — | | | | 1.63 | | | | (0.56 | ) |
| | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 3.27 | | | $ | 4.06 | | | $ | 1.64 | |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
Income from Continuing Operations | | $ | 3.18 | | | $ | 2.37 | | | $ | 2.15 | |
Income (Loss) from Discontinued Operations | | | — | | | | 1.59 | | | | (0.54 | ) |
| | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 3.18 | | | $ | 3.96 | | | $ | 1.61 | |
| | | | | | | | | | | | |
Weighted Average Common Shares Outstanding: | | | | | | | | | | | | |
Used in Basic Calculation | | | 82,304,335 | | | | 83,141,640 | | | | 84,030,118 | |
| | | | | | | | | | | | |
Used in Diluted Calculation | | | 84,474,839 | | | | 85,301,361 | | | | 86,028,466 | |
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
61
NATIONAL FUEL GAS COMPANY
| | | | | | | | |
| | At September 30 | |
| | 2008 | | | 2007 | |
| | (Thousands of dollars) | |
|
ASSETS |
Property, Plant and Equipment | | $ | 4,873,969 | | | $ | 4,461,586 | |
Less — Accumulated Depreciation, Depletion and Amortization | | | 1,719,869 | | | | 1,583,181 | |
| | | | | | | | |
| | | 3,154,100 | | | | 2,878,405 | |
| | | | | | | | |
Current Assets | | | | | | | | |
Cash and Temporary Cash Investments | | | 68,239 | | | | 124,806 | |
Cash Held in Escrow | | | — | | | | 61,964 | |
Hedging Collateral Deposits | | | 1 | | | | 4,066 | |
Receivables — Net of Allowance for Uncollectible Accounts of $33,117 and $28,654, Respectively | | | 185,397 | | | | 172,380 | |
Unbilled Utility Revenue | | | 24,364 | | | | 20,682 | |
Gas Stored Underground | | | 87,294 | | | | 66,195 | |
Materials and Supplies — at average cost | | | 31,317 | | | | 35,669 | |
Unrecovered Purchased Gas Costs | | | 37,708 | | | | 14,769 | |
Other Current Assets | | | 65,158 | | | | 45,057 | |
Deferred Income Taxes | | | — | | | | 8,550 | |
| | | | | | | | |
| | | 499,478 | | | | 554,138 | |
| | | | | | | | |
Other Assets | | | | | | | | |
Recoverable Future Taxes | | | 82,506 | | | | 83,954 | |
Unamortized Debt Expense | | | 13,978 | | | | 12,070 | |
Other Regulatory Assets | | | 189,587 | | | | 137,577 | |
Deferred Charges | | | 4,417 | | | | 5,545 | |
Other Investments | | | 80,640 | | | | 85,902 | |
Investments in Unconsolidated Subsidiaries | | | 16,279 | | | | 18,256 | |
Goodwill | | | 5,476 | | | | 5,476 | |
Intangible Assets | | | 26,174 | | | | 28,836 | |
Prepaid Pension and Other Post-Retirement Benefit Costs | | | 21,034 | | | | 61,006 | |
Fair Value of Derivative Financial Instruments | | | 28,786 | | | | 9,188 | |
Other | | | 7,732 | | | | 8,059 | |
| | | | | | | | |
| | | 476,609 | | | | 455,869 | |
| | | | | | | | |
Total Assets | | $ | 4,130,187 | | | $ | 3,888,412 | |
| | | | | | | | |
|
CAPITALIZATION AND LIABILITIES |
Capitalization: | | | | | | | | |
Comprehensive Shareholders’ Equity | | | | | | | | |
Common Stock, $1 Par Value | | | | | | | | |
Authorized — 200,000,000 Shares; Issued and Outstanding — 79,120,544 Shares and 83,461,308 Shares, Respectively | | $ | 79,121 | | | $ | 83,461 | |
Paid In Capital | | | 567,716 | | | | 569,085 | |
Earnings Reinvested in the Business | | | 953,799 | | | | 983,776 | |
| | | | | | | | |
Total Common Shareholders’ Equity Before Items Of Other Comprehensive Income (Loss) | | | 1,600,636 | | | | 1,636,322 | |
Accumulated Other Comprehensive Income (Loss) | | | 2,963 | | | | (6,203 | ) |
| | | | | | | | |
Total Comprehensive Shareholders’ Equity | | | 1,603,599 | | | | 1,630,119 | |
Long-Term Debt, Net of Current Portion | | | 999,000 | | | | 799,000 | |
| | | | | | | | |
Total Capitalization | | | 2,602,599 | | | | 2,429,119 | |
| | | | | | | | |
Current and Accrued Liabilities | | | | | | | | |
Notes Payable to Banks and Commercial Paper | | | — | | | | — | |
Current Portion of Long-Term Debt | | | 100,000 | | | | 200,024 | |
Accounts Payable | | | 142,520 | | | | 109,757 | |
Amounts Payable to Customers | | | 2,753 | | | | 10,409 | |
Dividends Payable | | | 25,714 | | | | 25,873 | |
Interest Payable on Long-Term Debt | | | 22,114 | | | | 18,158 | |
Customer Advances | | | 33,017 | | | | 22,863 | |
Other Accruals and Current Liabilities | | | 45,220 | | | | 36,062 | |
Deferred Income Taxes | | | 1,871 | | | | — | |
Fair Value of Derivative Financial Instruments | | | 1,362 | | | | 16,200 | |
| | | | | | | | |
| | | 374,571 | | | | 439,346 | |
| | | | | | | | |
Deferred Credits | | | | | | | | |
Deferred Income Taxes | | | 634,372 | | | | 575,356 | |
Taxes Refundable to Customers | | | 18,449 | | | | 14,026 | |
Unamortized Investment Tax Credit | | | 4,691 | | | | 5,392 | |
Cost of Removal Regulatory Liability | | | 103,100 | | | | 91,226 | |
Other Regulatory Liabilities | | | 91,933 | | | | 76,659 | |
Pension and Other Post-Retirement Liabilities | | | 78,909 | | | | 70,555 | |
Asset Retirement Obligations | | | 93,247 | | | | 75,939 | |
Other Deferred Credits | | | 128,316 | | | | 110,794 | |
| | | | | | | | |
| | | 1,153,017 | | | | 1,019,947 | |
| | | | | | | | |
Commitments and Contingencies | | | — | | | | — | |
| | | | | | | | |
Total Capitalization and Liabilities | | $ | 4,130,187 | | | $ | 3,888,412 | |
| | | | | | | | |
See Notes to Consolidated Financial Statements
62
NATIONAL FUEL GAS COMPANY
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands of dollars) | |
|
Operating Activities | | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 268,728 | | | $ | 337,455 | | | $ | 138,091 | |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | | | | | | | | | | | | |
Gain on Sale of Discontinued Operations | | | — | | | | (159,873 | ) | | | — | |
Impairment of Oil and Gas Producing Properties | | | — | | | | — | | | | 104,739 | |
Depreciation, Depletion and Amortization | | | 170,623 | | | | 170,803 | | | | 179,615 | |
Deferred Income Taxes | | | 72,496 | | | | 52,847 | | | | (5,230 | ) |
Income from Unconsolidated Subsidiaries, Net of Cash Distributions | | | 1,977 | | | | (3,366 | ) | | | 1,067 | |
Excess Tax Benefits Associated with Stock-Based Compensation Awards | | | (16,275 | ) | | | (13,689 | ) | | | (6,515 | ) |
Other | | | 4,858 | | | | 16,399 | | | | 4,829 | |
Change in: | | | | | | | | | | | | |
Hedging Collateral Deposits | | | 4,065 | | | | 15,610 | | | | 58,108 | |
Receivables and Unbilled Utility Revenue | | | (16,815 | ) | | | 5,669 | | | | (12,343 | ) |
Gas Stored Underground and Materials and Supplies | | | (22,116 | ) | | | (5,714 | ) | | | 1,679 | |
Unrecovered Purchased Gas Costs | | | (22,939 | ) | | | (1,799 | ) | | | 1,847 | |
Prepayments and Other Current Assets | | | (36,376 | ) | | | 18,800 | | | | (39,572 | ) |
Accounts Payable | | | 32,763 | | | | (26,002 | ) | | | (23,144 | ) |
Amounts Payable to Customers | | | (7,656 | ) | | | (13,526 | ) | | | 22,777 | |
Customer Advances | | | 10,154 | | | | (6,554 | ) | | | 4,946 | |
Other Accruals and Current Liabilities | | | (3,641 | ) | | | 8,950 | | | | (17,754 | ) |
Other Assets | | | (11,887 | ) | | | 4,109 | | | | (22,700 | ) |
Other Liabilities | | | 54,817 | | | | (5,922 | ) | | | 80,960 | |
| | | | | | | | | | | | |
Net Cash Provided by Operating Activities | | | 482,776 | | | | 394,197 | | | | 471,400 | |
| | | | | | | | | | | | |
Investing Activities | | | | | | | | | | | | |
Capital Expenditures | | | (397,734 | ) | | | (276,728 | ) | | | (294,159 | ) |
Investment in Partnership | | | — | | | | (3,300 | ) | | | — | |
Net Proceeds from Sale of Foreign Subsidiaries | | | — | | | | 232,092 | | | | — | |
Cash Held in Escrow | | | 58,397 | | | | (58,248 | ) | | | — | |
Net Proceeds from Sale of Oil and Gas Producing Properties | | | 5,969 | | | | 5,137 | | | | 13 | |
Other | | | 4,376 | | | | (725 | ) | | | (3,230 | ) |
| | | | | | | | | | | | |
Net Cash Used in Investing Activities | | | (328,992 | ) | | | (101,772 | ) | | | (297,376 | ) |
| | | | | | | | | | | | |
Financing Activities | | | | | | | | | | | | |
Excess Tax Benefits Associated with Stock-Based Compensation Awards | | | 16,275 | | | | 13,689 | | | | 6,515 | |
Shares Repurchased under Repurchase Plan | | | (237,006 | ) | | | (48,070 | ) | | | (85,168 | ) |
Net Proceeds from Issuance of Long-Term Debt | | | 296,655 | | | | — | | | | — | |
Reduction of Long-Term Debt | | | (200,024 | ) | | | (119,576 | ) | | | (9,805 | ) |
Net Proceeds from Issuance of Common Stock | | | 17,432 | | | | 17,498 | | | | 23,339 | |
Dividends Paid on Common Stock | | | (103,683 | ) | | | (100,632 | ) | | | (98,266 | ) |
| | | | | | | | | | | | |
Net Cash Used in Financing Activities | | | (210,351 | ) | | | (237,091 | ) | | | (163,385 | ) |
| | | | | | | | | | | | |
Effect of Exchange Rates on Cash | | | — | | | | (139 | ) | | | 1,365 | |
| | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Temporary Cash Investments | | | (56,567 | ) | | | 55,195 | | | | 12,004 | |
Cash and Temporary Cash Investments At Beginning of Year | | | 124,806 | | | | 69,611 | | | | 57,607 | |
| | | | | | | | | | | | |
Cash and Temporary Cash Investments At End of Year | | $ | 68,239 | | | $ | 124,806 | | | $ | 69,611 | |
| | | | | | | | | | | | |
Supplemental Disclosure of Cash Flow Information | | | | | | | | | | | | |
Cash Paid For: | | | | | | | | | | | | |
Interest | | $ | 69,841 | | | $ | 75,987 | | | $ | 78,003 | |
| | | | | | | | | | | | |
Income Taxes | | $ | 103,154 | | | $ | 97,961 | | | $ | 54,359 | |
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
63
NATIONAL FUEL GAS COMPANY
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands of dollars) | |
|
Net Income Available for Common Stock | | $ | 268,728 | | | $ | 337,455 | | | $ | 138,091 | |
| | | | | | | | | | | | |
Other Comprehensive Income (Loss), Before Tax: | | | | | | | | | | | | |
Minimum Pension Liability Adjustment | | | — | | | | — | | | | 165,914 | |
Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | (13,584 | ) | | | — | | | | — | |
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | 1,924 | | | | — | | | | — | |
Foreign Currency Translation Adjustment | | | 12 | | | | 7,874 | | | | 7,408 | |
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income | | | — | | | | (42,658 | ) | | | (716 | ) |
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period | | | (4,856 | ) | | | 4,747 | | | | 2,573 | |
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | | | (31,490 | ) | | | 8,495 | | | | 90,196 | |
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income | | | 64,645 | | | | 5,106 | | | | 91,743 | |
| | | | | | | | | | | | |
Other Comprehensive Income (Loss), Before Tax | | | 16,651 | | | | (16,436 | ) | | | 357,118 | |
| | | | | | | | | | | | |
Income Tax Expense Related to Minimum Pension Liability Adjustment | | | — | | | | — | | | | 58,070 | |
Income Tax Benefit Related to the Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | (5,127 | ) | | | — | | | | — | |
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | 726 | | | | — | | | | — | |
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period | | | (1,434 | ) | | | 1,724 | | | | 894 | |
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | | | (13,228 | ) | | | 3,153 | | | | 34,772 | |
Reclassification Adjustment for Income Tax Benefit on Realized Losses on Derivative Financial Instruments In Net Income | | | 26,548 | | | | 2,824 | | | | 35,338 | |
| | | | | | | | | | | | |
Income Taxes — Net | | | 7,485 | | | | 7,701 | | | | 129,074 | |
| | | | | | | | | | | | |
Other Comprehensive Income (Loss) | | | 9,166 | | | | (24,137 | ) | | | 228,044 | |
| | | | | | | | | | | | |
Comprehensive Income | | $ | 277,894 | | | $ | 313,318 | | | $ | 366,135 | |
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements25, 2009
64
NATIONAL FUEL GAS COMPANY
REINVESTED IN THE BUSINESS
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
| | (Thousands of dollars, except per common | |
| | | | | share amounts) | | | | |
|
INCOME | | | | | | | | | | | | |
Operating Revenues | | $ | 2,057,852 | | | $ | 2,400,361 | | | $ | 2,039,566 | |
| | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | |
Purchased Gas | | | 1,001,782 | | | | 1,235,157 | | | | 1,018,081 | |
Operation and Maintenance | | | 402,856 | | | | 432,871 | | | | 396,408 | |
Property, Franchise and Other Taxes | | | 72,163 | | | | 75,585 | | | | 70,660 | |
Depreciation, Depletion and Amortization | | | 173,410 | | | | 170,623 | | | | 157,919 | |
Impairment of Oil and Gas Producing Properties | | | 182,811 | | | | — | | | | — | |
| | | | | | | | | | | | |
| | | 1,833,022 | | | | 1,914,236 | | | | 1,643,068 | |
| | | | | | | | | | | | |
Operating Income | | | 224,830 | | | | 486,125 | | | | 396,498 | |
Other Income (Expense): | | | | | | | | | | | | |
Income from Unconsolidated Subsidiaries | | | 3,366 | | | | 6,303 | | | | 4,979 | |
Impairment of Investment in Partnership | | | (1,804 | ) | | | — | | | | — | |
Other Income | | | 6,576 | | | | 7,376 | | | | 4,936 | |
Interest Income | | | 5,776 | | | | 10,815 | | | | 1,550 | |
Interest Expense on Long-Term Debt | | | (79,419 | ) | | | (70,099 | ) | | | (68,446 | ) |
Other Interest Expense | | | (7,497 | ) | | | (3,870 | ) | | | (6,029 | ) |
| | | | | | | | | | | | |
Income from Continuing Operations Before Income Taxes | | | 151,828 | | | | 436,650 | | | | 333,488 | |
Income Tax Expense | | | 51,120 | | | | 167,922 | | | | 131,813 | |
| | | | | | | | | | | | |
Income from Continuing Operations | | | 100,708 | | | | 268,728 | | | | 201,675 | |
Discontinued Operations: | | | | | | | | | | | | |
Income from Operations, Net of Tax | | | — | | | | — | | | | 15,479 | |
Gain on Disposal, Net of Tax | | | — | | | | — | | | | 120,301 | |
| | | | | | | | | | | | |
Income from Discontinued Operations, Net of Tax | | | — | | | | — | | | | 135,780 | |
| | | | | | | | | | | | |
Net Income Available for Common Stock | | | 100,708 | | | | 268,728 | | | | 337,455 | |
| | | | | | | | | | | | |
EARNINGS REINVESTED IN THE BUSINESS | | | | | | | | | | | | |
Balance at Beginning of Year | | | 953,799 | | | | 983,776 | | | | 786,013 | |
| | | | | | | | | | | | |
| | | 1,054,507 | | | | 1,252,504 | | | | 1,123,468 | |
Share Repurchases | | | — | | | | (194,776 | ) | | | (38,196 | ) |
Cumulative Effect of Adoption of Authoritative Guidance for Income Taxes | | | — | | | | (406 | ) | | | — | |
Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans | | | (804 | ) | | | — | | | | — | |
Dividends on Common Stock | | | (105,410 | ) | | | (103,523 | ) | | | (101,496 | ) |
| | | | | | | | | | | | |
Balance at End of Year | | $ | 948,293 | | | $ | 953,799 | | | $ | 983,776 | |
| | | | | | | | | | | | |
Earnings Per Common Share: | | | | | | | | | | | | |
Basic: | | | | | | | | | | | | |
Income from Continuing Operations | | $ | 1.26 | | | $ | 3.27 | | | $ | 2.43 | |
Income from Discontinued Operations | | | — | | | | — | | | | 1.63 | |
| | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 1.26 | | | $ | 3.27 | | | $ | 4.06 | |
| | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | |
Income from Continuing Operations | | $ | 1.25 | | | $ | 3.18 | | | $ | 2.37 | |
Income from Discontinued Operations | | | — | | | | — | | | | 1.59 | |
| | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 1.25 | | | $ | 3.18 | | | $ | 3.96 | |
| | | | | | | | | | | | |
Weighted Average Common Shares Outstanding: | | | | | | | | | | | | |
Used in Basic Calculation | | | 79,649,965 | | | | 82,304,335 | | | | 83,141,640 | |
| | | | | | | | | | | | |
Used in Diluted Calculation | | | 80,628,685 | | | | 84,474,839 | | | | 85,301,361 | |
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
65
NATIONAL FUEL GAS COMPANY
| | | | | | | | |
| | At September 30 | |
| | 2009 | | | 2008 | |
| | (Thousands of dollars) | |
|
ASSETS |
Property, Plant and Equipment | | $ | 5,183,527 | | | $ | 4,873,969 | |
Less — Accumulated Depreciation, Depletion and Amortization | | | 2,051,482 | | | | 1,719,869 | |
| | | | | | | | |
| | | 3,132,045 | | | | 3,154,100 | |
| | | | | | | | |
Current Assets | | | | | | | | |
Cash and Temporary Cash Investments | | | 408,053 | | | | 68,239 | |
Cash Held in Escrow | | | 2,000 | | | | — | |
Hedging Collateral Deposits | | | 848 | | | | 1 | |
Receivables — Net of Allowance for Uncollectible Accounts of $38,334 and $33,117, Respectively | | | 144,466 | | | | 185,397 | |
Unbilled Utility Revenue | | | 18,884 | | | | 24,364 | |
Gas Stored Underground | | | 55,862 | | | | 87,294 | |
Materials and Supplies — at average cost | | | 24,520 | | | | 31,317 | |
Unrecovered Purchased Gas Costs | | | — | | | | 37,708 | |
Other Current Assets | | | 68,474 | | | | 65,158 | |
Deferred Income Taxes | | | 53,863 | | | | — | |
| | | | | | | | |
| | | 776,970 | | | | 499,478 | |
| | | | | | | | |
Other Assets | | | | | | | | |
Recoverable Future Taxes | | | 138,435 | | | | 82,506 | |
Unamortized Debt Expense | | | 14,815 | | | | 13,978 | |
Other Regulatory Assets | | | 530,913 | | | | 189,587 | |
Deferred Charges | | | 2,737 | | | | 4,417 | |
Other Investments | | | 78,503 | | | | 80,640 | |
Investments in Unconsolidated Subsidiaries | | | 16,257 | | | | 16,279 | |
Goodwill | | | 5,476 | | | | 5,476 | |
Intangible Assets | | | 21,536 | | | | 26,174 | |
Prepaid Post-Retirement Benefit Costs | | | — | | | | 21,034 | |
Fair Value of Derivative Financial Instruments | | | 44,817 | | | | 28,786 | |
Other | | | 6,625 | | | | 7,732 | |
| | | | | | | | |
| | | 860,114 | | | | 476,609 | |
| | | | | | | | |
Total Assets | | $ | 4,769,129 | | | $ | 4,130,187 | |
| | | | | | | | |
|
CAPITALIZATION AND LIABILITIES |
Capitalization: | | | | | | | | |
Comprehensive Shareholders’ Equity | | | | | | | | |
Common Stock, $1 Par Value | | | | | | | | |
Authorized — 200,000,000 Shares; Issued and Outstanding — 80,499,915 Shares and 79,120,544 Shares, Respectively | | $ | 80,500 | | | $ | 79,121 | |
Paid In Capital | | | 602,839 | | | | 567,716 | |
Earnings Reinvested in the Business | | | 948,293 | | | | 953,799 | |
| | | | | | | | |
Total Common Shareholders’ Equity Before Items Of Other Comprehensive Income (Loss) | | | 1,631,632 | | | | 1,600,636 | |
Accumulated Other Comprehensive Income (Loss) | | | (42,396 | ) | | | 2,963 | |
| | | | | | | | |
Total Comprehensive Shareholders’ Equity | | | 1,589,236 | | | | 1,603,599 | |
Long-Term Debt, Net of Current Portion | | | 1,249,000 | | | | 999,000 | |
| | | | | | | | |
Total Capitalization | | | 2,838,236 | | | | 2,602,599 | |
| | | | | | | | |
Current and Accrued Liabilities | | | | | | | | |
Notes Payable to Banks and Commercial Paper | | | — | | | | — | |
Current Portion of Long-Term Debt | | | — | | | | 100,000 | |
Accounts Payable | | | 90,723 | | | | 142,520 | |
Amounts Payable to Customers | | | 105,778 | | | | 2,753 | |
Dividends Payable | | | 26,967 | | | | 25,714 | |
Interest Payable on Long-Term Debt | | | 32,031 | | | | 22,114 | |
Customer Advances | | | 24,555 | | | | 33,017 | |
Customer Security Deposits | | | 17,430 | | | | 14,047 | |
Other Accruals and Current Liabilities | | | 18,875 | | | | 31,173 | |
Deferred Income Taxes | | | — | | | | 1,871 | |
Fair Value of Derivative Financial Instruments | | | 2,148 | | | | 1,362 | |
| | | | | | | | |
| | | 318,507 | | | | 374,571 | |
| | | | | | | | |
Deferred Credits | | | | | | | | |
Deferred Income Taxes | | | 663,876 | | | | 634,372 | |
Taxes Refundable to Customers | | | 67,046 | | | | 18,449 | |
Unamortized Investment Tax Credit | | | 3,989 | | | | 4,691 | |
Cost of Removal Regulatory Liability | | | 105,546 | | | | 103,100 | |
Other Regulatory Liabilities | | | 120,229 | | | | 91,933 | |
Pension and Other Post-Retirement Liabilities | | | 415,888 | | | | 78,909 | |
Asset Retirement Obligations | | | 91,373 | | | | 93,247 | |
Other Deferred Credits | | | 144,439 | | | | 128,316 | |
| | | | | | | | |
| | | 1,612,386 | | | | 1,153,017 | |
| | | | | | | | |
Commitments and Contingencies | | | — | | | | — | |
| | | | | | | | |
Total Capitalization and Liabilities | | $ | 4,769,129 | | | $ | 4,130,187 | |
| | | | | | | | |
See Notes to Consolidated Financial Statements
66
NATIONAL FUEL GAS COMPANY
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
| | (Thousands of dollars) | |
|
Operating Activities | | | | | | | | | | | | |
Net Income Available for Common Stock | | $ | 100,708 | | | $ | 268,728 | | | $ | 337,455 | |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | | | | | | | | | | | | |
Gain on Sale of Discontinued Operations | | | — | | | | — | | | | (159,873 | ) |
Impairment of Oil and Gas Producing Properties | | | 182,811 | | | | — | | | | — | |
Depreciation, Depletion and Amortization | | | 173,410 | | | | 170,623 | | | | 170,803 | |
Deferred Income Taxes | | | (2,521 | ) | | | 72,496 | | | | 52,847 | |
Income from Unconsolidated Subsidiaries, Net of Cash Distributions | | | (466 | ) | | | 1,977 | | | | (3,366 | ) |
Impairment of Investment in Partnership | | | 1,804 | | | | — | | | | — | |
Excess Tax Benefits Associated with Stock-Based Compensation Awards | | | (5,927 | ) | | | (16,275 | ) | | | (13,689 | ) |
Other | | | 17,443 | | | | 4,858 | | | | 16,399 | |
Change in: | | | | | | | | | | | | |
Hedging Collateral Deposits | | | (847 | ) | | | 4,065 | | | | 15,610 | |
Receivables and Unbilled Utility Revenue | | | 47,658 | | | | (16,815 | ) | | | 5,669 | |
Gas Stored Underground and Materials and Supplies | | | 43,598 | | | | (22,116 | ) | | | (5,714 | ) |
Unrecovered Purchased Gas Costs | | | 37,708 | | | | (22,939 | ) | | | (1,799 | ) |
Prepayments and Other Current Assets | | | 2,921 | | | | (36,376 | ) | | | 18,800 | |
Accounts Payable | | | (61,149 | ) | | | 32,763 | | | | (26,002 | ) |
Amounts Payable to Customers | | | 103,025 | | | | (7,656 | ) | | | (13,526 | ) |
Customer Advances | | | (8,462 | ) | | | 10,154 | | | | (6,554 | ) |
Customer Security Deposits | | | 3,383 | | | | 609 | | | | 1,907 | |
Other Accruals and Current Liabilities | | | 13,676 | | | | (4,250 | ) | | | 7,043 | |
Other Assets | | | (35,140 | ) | | | (11,887 | ) | | | 4,109 | |
Other Liabilities | | | (4,201 | ) | | | 54,817 | | | | (5,922 | ) |
| | | | | | | | | | | | |
Net Cash Provided by Operating Activities | | | 609,432 | | | | 482,776 | | | | 394,197 | |
| | | | | | | | | | | | |
Investing Activities | | | | | | | | | | | | |
Capital Expenditures | | | (309,930 | ) | | | (397,734 | ) | | | (276,728 | ) |
Investment in Subsidiary, Net of Cash Acquired | | | (34,933 | ) | | | — | | | | — | |
Investment in Partnerships | | | (1,317 | ) | | | — | | | | (3,300 | ) |
Net Proceeds from Sale of Foreign Subsidiaries | | | — | | | | — | | | | 232,092 | |
Cash Held in Escrow | | | (2,000 | ) | | | 58,397 | | | | (58,248 | ) |
Net Proceeds from Sale of Oil and Gas Producing Properties | | | 3,643 | | | | 5,969 | | | | 5,137 | |
Other | | | (2,806 | ) | | | 4,376 | | | | (725 | ) |
| | | | | | | | | | | | |
Net Cash Used in Investing Activities | | | (347,343 | ) | | | (328,992 | ) | | | (101,772 | ) |
| | | | | | | | | | | | |
Financing Activities | | | | | | | | | | | | |
Excess Tax Benefits Associated with Stock-Based Compensation Awards | | | 5,927 | | | | 16,275 | | | | 13,689 | |
Shares Repurchased under Repurchase Plan | | | — | | | | (237,006 | ) | | | (48,070 | ) |
Net Proceeds from Issuance of Long-Term Debt | | | 247,780 | | | | 296,655 | | | | — | |
Reduction of Long-Term Debt | | | (100,000 | ) | | | (200,024 | ) | | | (119,576 | ) |
Net Proceeds from Issuance of Common Stock | | | 28,176 | | | | 17,432 | | | | 17,498 | |
Dividends Paid on Common Stock | | | (104,158 | ) | | | (103,683 | ) | | | (100,632 | ) |
| | | | | | | | | | | | |
Net Cash Provided By (Used in) Financing Activities | | | 77,725 | | | | (210,351 | ) | | | (237,091 | ) |
| | | | | | | | | | | | |
Effect of Exchange Rates on Cash | | | — | | | | — | | | | (139 | ) |
| | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Temporary Cash Investments | | | 339,814 | | | | (56,567 | ) | | | 55,195 | |
Cash and Temporary Cash Investments At Beginning of Year | | | 68,239 | | | | 124,806 | | | | 69,611 | |
| | | | | | | | | | | | |
Cash and Temporary Cash Investments At End of Year | | $ | 408,053 | | | $ | 68,239 | | | $ | 124,806 | |
| | | | | | | | | | | | |
Supplemental Disclosure of Cash Flow Information | | | | | | | | | | | | |
Cash Paid For: | | | | | | | | | | | | |
Interest | | $ | 75,640 | | | $ | 69,841 | | | $ | 75,987 | |
| | | | | | | | | | | | |
Income Taxes | | $ | 40,638 | | | $ | 103,154 | | | $ | 97,961 | |
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
67
NATIONAL FUEL GAS COMPANY
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
| | (Thousands of dollars) | |
|
Net Income Available for Common Stock | | $ | 100,708 | | | $ | 268,728 | | | $ | 337,455 | |
| | | | | | | | | | | | |
Other Comprehensive Income (Loss), Before Tax: | | | | | | | | | | | | |
Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | (71,771 | ) | | | (13,584 | ) | | | — | |
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | 1,008 | | | | 1,924 | | | | — | |
Foreign Currency Translation Adjustment | | | (33 | ) | | | 12 | | | | 7,874 | |
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income | | | — | | | | — | | | | (42,658 | ) |
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period | | | (6,118 | ) | | | (4,856 | ) | | | 4,747 | |
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | | | 119,210 | | | | (31,490 | ) | | | 8,495 | |
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income | | | (114,380 | ) | | | 64,645 | | | | 5,106 | |
| | | | | | | | | | | | |
Other Comprehensive Income (Loss), Before Tax | | | (72,084 | ) | | | 16,651 | | | | (16,436 | ) |
| | | | | | | | | | | | |
Income Tax Benefit Related to the Decrease in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | (27,082 | ) | | | (5,127 | ) | | | — | |
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | | | 380 | | | | 726 | | | | — | |
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period | | | (2,311 | ) | | | (1,434 | ) | | | 1,724 | |
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | | | 48,293 | | | | (13,228 | ) | | | 3,153 | |
Reclassification Adjustment for Income Tax (Expense) Benefit on Realized (Gains) Losses on Derivative Financial Instruments In Net Income | | | (46,005 | ) | | | 26,548 | | | | 2,824 | |
| | | | | | | | | | | | |
Income Taxes — Net | | | (26,725 | ) | | | 7,485 | | | | 7,701 | |
| | | | | | | | | | | | |
Other Comprehensive Income (Loss) | | | (45,359 | ) | | | 9,166 | | | | (24,137 | ) |
| | | | | | | | | | | | |
Comprehensive Income | | $ | 55,349 | | | $ | 277,894 | | | $ | 313,318 | |
| | | | | | | | | | | | |
See Notes to Consolidated Financial Statements
68
NATIONAL FUEL GAS COMPANY
Note A — Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
Revenue Recognition
The Company’s Utility segment records revenue as bills are rendered, except that service supplied but not billed is reported as unbilled utility revenue and is included in operating revenues for the year in which service is furnished.
The Company’s Energy Marketing segment records revenue as bills are rendered for service supplied on a calendar month basis.
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services.
The Company’s Timber segment records revenue on lumber and log sales as products are shipped, which is the point at which ownership and risk of loss transfers to the buyer of lumber products or logs.
The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age and other specific information about customer accounts. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.
6569
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note C — Regulatory Matters for further discussion.
The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending December 31st, and applied to customer bills annually, beginning March 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation bills its customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, in fixed monthly reservation charges. The allowed rates that Empire bills its customers are based on a modified fixed-variable rate design, which allows recovery of most fixed costs in fixed monthly reservation charges. To distinguish between the two rate designs, the modified fixed-variable rate design recovers return on equity and income taxes through variable charges whereas straight fixed-variable recovers all fixed costs, including return on equity and income taxes, through itsfixed monthly reservation charge.charges. Because of the difference inthis rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation’s revenues but mayCorporation.
Prior to December 10, 2008, the allowed rates that Empire billed its customers were based on a modified fixed-variable rate design, which recovered return on equity and income taxes through variable charges. Because of this rate design, changes in throughput due to weather variations could have had a significant impact on Empire’s revenues. On December 10, 2008, Empire became FERC regulated. As a result, Empire now bills its customers based on a straight fixed-variable rate design. Changes in throughput due to weather variations no longer have a significant impact on Empire’s revenues.revenue.
Property, Plant and Equipment
The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities.
In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the
70
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net
66
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying current market prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2009, 2008, 2007, and 2006,2007, estimated future net cash flows were increased by $143.3 million, $34.5 million $2.2 million and $4.7$2.2 million, respectively. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s Canadianoil and gas properties at June 30, 2006 and September 30, 2006.December 31, 2008. As such, the Company recognized a pre-tax impairmentsimpairment of $62.4$182.8 million at June 30, 2006 and $42.3December 31, 2008. Deferred income taxes of $74.6 million at September 30, 2006. These impairment charges are included in loss from discontinued operations for 2006 due to the sale of SECI during 2007.were recorded associated with this impairment.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion and Amortization
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. ForIn the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. For all other property, plant and equipment, depreciation, depletion and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:
| | | | | | | | |
| | As of September 30 | |
| | 2008 | | | 2007 | |
| | (Thousands) | |
|
Utility | | $ | 1,580,366 | | | $ | 1,539,808 | |
Pipeline and Storage | | | 996,743 | | | | 976,316 | |
Exploration and Production | | | 1,800,422 | | | | 1,577,745 | |
Energy Marketing | | | 1,232 | | | | 1,199 | |
Timber | | | 120,021 | | | | 119,237 | |
All Other and Corporate | | | 25,984 | | | | 32,806 | |
| | | | | | | | |
| | $ | 4,524,768 | | | $ | 4,247,111 | |
| | | | | | | | |
Average depreciation, depletion and amortization rates are as follows:
| | | | | | | | | |
| | | | | | | | | | | | | | As of September 30 | |
| | Year Ended September 30 | | | 2009 | | 2008 | |
| | 2008 | | 2007 | | 2006 | | | (Thousands) | |
|
Utility | | | 2.6 | % | | | 2.8 | % | | | 2.8 | % | | $ | 1,616,908 | | | $ | 1,580,366 | |
Pipeline and Storage | | | 3.2 | % | | | 3.5 | % | | | 4.0 | % | | | 1,196,937 | | | | 996,743 | |
Exploration and Production, per Mcfe(1) | | $ | 2.26 | | | $ | 1.94 | | | $ | 2.00 | | |
Exploration and Production | | | | 1,972,353 | | | | 1,800,422 | |
Energy Marketing | | | 3.5 | % | | | 2.8 | % | | | 4.8 | % | | | 1,241 | | | | 1,232 | |
Timber | | | 4.1 | % | | | 4.0 | % | | | 5.6 | % | |
All Other and Corporate | | | 5.0 | % | | | 4.6 | % | | | 4.1 | % | | | 154,512 | | | | 146,005 | |
| | | | | | |
| | | $ | 4,941,951 | | | $ | 4,524,768 | |
| | | | | | |
6771
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Average depreciation, depletion and amortization rates are as follows:
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
|
Utility | | | 2.6 | % | | | 2.6 | % | | | 2.8 | % |
Pipeline and Storage | | | 3.0 | % | | | 3.2 | % | | | 3.5 | % |
Exploration and Production, per Mcfe(1) | | $ | 2.14 | | | $ | 2.26 | | | $ | 1.94 | |
Energy Marketing | | | 3.4 | % | | | 3.5 | % | | | 2.8 | % |
All Other and Corporate | | | 5.2 | % | | | 4.3 | % | | | 4.1 | % |
| | |
(1) | | Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note OQ — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $2.10, $2.23 $1.92 and $1.98$1.92 per Mcfe of production in 2009, 2008 2007 and 2006,2007, respectively. Depletion of oil and gas producing properties in the United States amounted to $2.10, $2.23 $1.97 and $1.74$1.97 per Mcfe of production in 2009, 2008 2007 and 2006,2007, respectively. Depletion of oil and gas producing properties in Canada amounted to $1.67 and $2.95 per Mcfe of production in 2007 and 2006, respectively.2007. |
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 20082009 and 20072008 on its consolidated balance sheetConsolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with SFAS 142,the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 20082009 and 2007,2008, the fair value of Empire was greater than its book value. As such, the goodwill was considered not impaired.
Financial Instruments
Unrealized gains or losses from the Company’s investments in an equity mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note FG — Financial Instruments for further discussion.
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments include price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled fair value of derivative financial instruments. Reference is made to Note F — Fair Value Measurements for further discussion concerning the fair value represents the amount the Company would receive or pay to terminate theseof derivative financial instruments.
For effective cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues, purchased gas expense or interest expense on the Consolidated Statements of Income. Any ineffectiveness associated with the cash flow hedges is recorded in the Consolidated Statements of Income. In December 2006, the Company repaid $22.8 million of Empire’s secured debt. The interest costs of this secured debt were hedged by an interest rate collar. Since the hedged transaction was settled and there will be no future cash flows associated with the secured debt, hedge accounting for the interest rate collar was discontinued and the unrealized gain of $1.9 million in accumulated other comprehensive income associated with the interest rate collar was reclassified to the Consolidated Statement of Income. The Company did not experience any material ineffectiveness with regard to its cash flow hedges during 20082009 or 2006.2008.
72
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. The Company did not experience any material ineffectiveness with regard to its fair value hedges during 2009, 2008 2007 or 2006.
68
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)2007.
Accumulated Other Comprehensive Income (Loss)
The components of Accumulated Other Comprehensive Income (Loss) are as follows:
| | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | | 2009 | | 2008 | |
| | (Thousands) | | | (Thousands) | |
|
Funded Status of the Pension and Other Post-Retirement Benefit Plans | | $ | (19,741 | ) | | $ | (12,482 | )(1) | | $ | (63,802 | ) | | $ | (19,741 | ) |
Cumulative Foreign Currency Translation Adjustment | | | (71 | ) | | | (83 | ) | | | (104 | ) | | | (71 | ) |
Net Unrealized Gain (Loss) on Derivative Financial Instruments | | | 15,949 | | | | (3,886 | ) | |
Net Unrealized Gain on Derivative Financial Instruments | | | | 18,491 | | | | 15,949 | |
Net Unrealized Gain on Securities Available for Sale | | | 6,826 | | | | 10,248 | | | | 3,019 | | | | 6,826 | |
| | | | | | | | | | |
Accumulated Other Comprehensive Income (Loss) | | $ | 2,963 | | | $ | (6,203 | ) | | $ | (42,396 | ) | | $ | 2,963 | |
| | | | | | | | | | |
| | |
(1) | | In accordance with the transition recognition implementation provisions of SFAS 158, the adjustment to recognize the funded status of the pension and other post-retirement benefit plans are shown as an adjustment to the ending balance of accumulated other comprehensive income (loss). The adjustment is not shown as other comprehensive income (loss) in the Consolidated Statements of Comprehensive Income. |
At September 30, 2008,2009, it is estimated that of the $15.9$18.5 million net unrealized gain on derivative financial instruments shown in the table above, $13.1$18.6 million of unrealized gains will be reclassified into the Consolidated Statement of Income during 2009.2010. The remaining unrealized gainloss on derivative financial instruments of $2.8$0.1 million will be reclassified into the Consolidated Statement of Income in subsequent years. As disclosed in Note F — Financial Instruments, theThe Company’s derivative financial instruments extend out to 2012.
The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of an unrecognized transition obligation, prior service costs and accumulated losses. The total unrecognized transition obligation was $0.1 million at September 30, 2007 (nothing at September 30, 2008). The total amount for prior service costs was $0.4$0.3 million and $1.0$0.4 million at September 30, 20082009 and September 30, 2007,2008, respectively. The total amount for accumulated losses was $19.3$63.5 million and $11.4$19.3 million at September 30, 20082009 and September 30, 2007,2008, respectively.
Gas Stored Underground — Current
In the Utility segment, gas stored underground — current in the amount of $34.1$30.4 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2008,2009, including transportation costs, the current cost of replacing this inventory of gas stored underground — current exceeded the amount stated on a LIFO basis by approximately $195.4$51.6 million at September 30, 2008.2009. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at lower of cost or market on an average cost method.
69
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Purchased Timber Rights
In the Timber segment, theThe Company purchases the right to harvest timber from land owned by other parties. These rights, which extend from several months to several years, are purchased to ensure an adequate supply of timber for the Company’s sawmill and kiln operations. The historical value of timber rights expected to be harvested during the following year are included in Materials and Supplies on the Consolidated Balance Sheets while the
73
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
historical value of timber rights expected to be harvested beyond one year are included in Other Assets on the Consolidated Balance Sheets. The components of the Company’s purchased timber rights are as follows:
| | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | | 2009 | | 2008 | |
| | (Thousands) | | | (Thousands) | |
|
Materials and Supplies | | $ | 9,911 | | | $ | 8,925 | | | $ | 6,349 | | | $ | 9,911 | |
Other Assets | | | 7,383 | | | | 5,641 | | | | 6,343 | | | | 7,383 | |
| | | | | | | | | | |
| | $ | 17,294 | | | $ | 14,566 | | | $ | 12,692 | | | $ | 17,294 | |
| | | | | | | | | | |
Unamortized Debt Expense
Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related debt. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment.
Foreign Currency Translation
The functional currency for the Company’s foreign operations is the local currency of the country where the operations are located. Asset and liability accounts are translated at the rate of exchange on the balance sheet date. Revenues and expenses are translated at the average exchange rate during the period. Foreign currency translation adjustments are recorded as a component of accumulated other comprehensive income (loss). With the sale of SECI on August 31, 2007, the Company eliminated its major foreign operation. While the Company is in the process of winding up or selling certain power development projects in Europe, the investment in such projects is not significant and the Company does not expect to have any significant foreign currency translation adjustments in the future.
Income Taxes
The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction.
Consolidated Statements of Cash Flows
For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.
At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System at September 30, 2009. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represent non-cash investing activities at that date.
At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount has beenwas excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it representsrepresented a non-cash investing activity at that date.
Hedging Collateral Account
These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash held in margin accounts serves as collateralFlows for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.the year ended September 30, 2009.
7074
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Hedging Collateral Account
This is an account title for cash held in margin accounts funded by the Company to serve as collateral for open hedging positions. At September 30, 2009, the Company had hedging collateral deposits of $0.8 million related to its exchange-traded futures contracts. It is the Company’s policy to not offset hedging collateral deposits paid or received against the derivative financial instruments liability or asset balances.
Cash Held in Escrow
On July 20, 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired of $4.3 million). The cash acquired at acquisition includes $2 million held in escrow at September 30, 2009. Seneca placed this amount in escrow as part of the purchase price, and in accordance with the purchase agreement, this amount will remain in escrow for one year from the closing of the transaction provided there are no pending disputes or actions regarding obligations and liabilities required to be satisfied or discharged by Ivanhoe Energy.
On August 31, 2007, the Company received approximately $232.1 million of proceeds from the sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. The escrow account was a Canadian dollar denominated account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30, 2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency exchange risk related to the cash being held in escrow, the Company held a forward contract to sell Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the year ended September 30, 2008, the Cash Held in Escrow line item within Investing Activities reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the impact of the foreign currency hedge.
Other Current Assets
Other Current Assets consist of prepayments in the amounts of $10.6$12.2 million and $14.1$10.6 million at September 30, 20082009 and 2007,2008, respectively, prepaid property and other taxes of $11.2$12.0 million and $14.1$11.2 million at September 30, 20082009 and 2007,2008, respectively, federal income taxes receivable in the amounts of $27.5$23.3 million and $8.7$27.5 million at September 30, 20082009 and 2007,2008, respectively, state income taxes receivable in the amounts of $5.0$13.5 million and zero$5.0 million at September 30, 20082009 and 2007,2008, respectively, and fair values of firm commitments in the amounts of $10.9$7.5 million and $8.2$10.9 million at September 30, 2009 and 2008, respectively.
Customer Advances
The Company’s Utility and 2007,Energy Marketing segments have balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2009 and 2008, customers in the balanced billing programs had advanced excess funds of $24.6 million and $33.0 million, respectively.
Customer Security Deposits
The Company, in its Utility, Pipeline and Storage, and Energy Marketing segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2009 and 2008, the Company had received customer security deposits amounting to $17.4 million and $14.0 million, respectively.
75
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Earnings Per Common Share
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options and stock-settled SARs. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these stock options and stock-settled SARs as determined using the Treasury Stock Method. Stock options and stock-settled SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. For 2009, there were 365,000 stock-settled SARs and 765,000 stock options excluded as being antidilutive. For 2008, there were 7,344 stock-settled SARs excluded as being antidilutive, and there were no stock options excluded as being antidilutive. For 2007, no stock options or stock-settled SARs were excluded as being antidilutive. For 2006, 119,241 stock options were excluded as being antidilutive. There were no stock-settled SARs excluded as being antidilutive for 2006.
Share Repurchases
The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note E — Capitalization and Short-Term Borrowings for further discussion of the share repurchase program.
Stock-Based Compensation
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock-settled SARs, restricted stock, performance units or performance shares. Stock options and stock-settled SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or stock-settled SAR is exercisable less than one year or more than ten years
71
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
after the date of each grant. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
Prior to October 1, 2005, the Company accounted for its stock-based compensation under the recognition and measurement principles of APB 25 and related interpretations. Under that method, no compensation expense was recognized for options granted under the Company’s stock option and stock award plans. The Company did record, in accordance with APB 25, compensation expense for the market value of restricted stock on the date of the award over the periods during which the vesting restrictions existed.
Effective October 1, 2005, the Company adopted SFAS 123R,follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options and stock-settled SARs. The Company has chosen to use the modified version of prospective application, as allowed by SFAS 123R. Using the modified prospective application, the Company recorded compensation cost for the portion of awards granted prior to October 1, 2005 for which the requisite service had not been rendered and recognized such compensation cost as the requisite service was rendered on or after October 1, 2005. Such compensation expense is based on the grant-date fair value of the awards as calculated for the Company’s disclosure using a Binomial option-pricing model under SFAS 123. Any new awards, modifications to awards, repurchases of awards, or cancellations of awards subsequent to September 30, 2005 will follow the provisions of SFAS 123R, with compensation expense being calculated using the Black-Scholes-Merton closed form model. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with such share-based payments since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model.
The Company did not grant any stock options during the years ended September 30, 2009 and 2008. There were no448,000 stock options granted during the year ended September 30, 2008. There were 448,000 and 317,000 stock options granted during the years ended September 30, 2007 and 2006, respectively.2007. The Company granted 610,000 and 321,000 performance based stock-settled SARs during the year ended September 30, 2008. There were no2009 and 2008, respectively, but did not grant any performance based stock-settled SARs granted during the year ended September 30, 2007. The Company granted 50,000 non-performance based stock-settled SARs during the year ended September 30, 2007. There were no2007, but did not grant any non-performance based stock-settled SARs granted during the yearyears ended September 30, 2009 and 2008. There were no performance based or non-performance based stock-settled SARs granted during the year ended September 30, 2006. The accounting treatment for such performance based and non-performance based stock-settled SARs is the same under SFAS 123R as the accounting for stock options under SFAS 123R.the current authoritative guidance for stock-based compensation. The performance based stock-settled SARs granted for the year ended
76
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
September 30, 2009 vest and become exercisable annually in one-third increments, provided that a performance condition is met. The performance condition for each fiscal year, generally stated, is an increase over the prior fiscal year of at least five percent in certain oil and natural gas production of the Exploration and Production segment. The performance based stock-settled SARs granted for the year ended September 30, 2008 vest and become exercisable annually, in one-third increments, provided that a performance condition for diluted earnings per share is met for the prior fiscal year. The weighted average grant date fair value of the performance based stock-settled SARs granted during 2009 and 2008 was estimated on the date of grant using the same accounting treatment that is applied for stock options, under SFAS 123R, and assumes that the performance conditions specified will be achieved. If such conditions are not met or it is not considered probable that such conditions will be met, no compensation expense is recognized and any previously recognized compensation expense is reversed. During 2009, the Company reversed $0.5 million of previously recognized compensation expense associated with performance based stock-settled SARs. The Company also granted 25,000,63,000, 25,000, and 16,00025,000 restricted share awards (non-vested stock as defined by SFAS 123R)the current accounting literature) during the years ended September 30, 2009, 2008 and 2007, and 2006, respectively.
Stock-based compensation expense for the years ended September 30, 2009, 2008 2007 and 20062007 was approximately $2,332,000, $3,727,000,$2.1 million (net of the $0.5 million reversal of compensation expense discussed above), $2.3 million, and $1,705,000,$3.7 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statement of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2009, 2008 2007 and 20062007 was approximately $945,000, $1,488,000$0.8 million, $0.9 million and $653,000,$1.5 million, respectively. There were no capitalized stock-based compensation costs during the years ended September 30, 20082009 and 2007.
72
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)2008.
Stock Options
The total intrinsic value of stock options exercised during the years ended September 30, 2009, 2008 2007 and 20062007 totaled approximately $18.7 million, $24.6 million, $38.7 million, and $30.9$38.7 million, respectively. For 2009, 2008 2007 and 2006,2007, the amount of cash received by the Company from the exercise of such stock options was approximately $29.2 million, $18.5 million, $26.0 million, and $30.1$26.0 million, respectively.
The Company realizes tax benefits related to the exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2008, 2007, 2006, and 2005,2006, the Company realized a tax benefit of $1.6 million, $4.4 million, and $3.2 million, and $0.9respectively. For stock options exercised during the period of January 1, 2009 through September 30, 2009, the Company will realize a tax benefit of approximately $5.7 million respectively.in the quarter ended December 31, 2009. For stock options exercised during the period of January 1, 2008 through September 30, 2008, the Company will realizerealized a tax benefit of approximately $4.3 million in the quarter ended December 31, 2008. For stock options exercised during the period of January 1, 2007 through September 30, 2007, the Company realized a tax benefit of approximately $12.0 million in the quarter ended December 31, 2007. For stock options exercised during the period of January 1, 2006 through September 30, 2006, the Company realized a tax benefit of approximately $11.4 million in the quarter ended December 31, 2006. The weighted average grant date fair value of options granted in 2007 and 2006 is $7.27 per shareshare. As stated above, there were no stock options granted during the years ended September 30, 2009 and $6.68 per share, respectively.2008. For the years ended September 30, 2009, 2008 and 2007, 27,000, 358,000 and 2006, 358,000, 327,501 and 89,665 stock options became fully vested, respectively. The total fair value of thesethe stock options was approximately $2.6 million, $2.1 million and $0.4 million, respectively, forthat became vested during the years ended September 30, 2009, 2008 and 2007 was approximately $0.2 million, $2.6 million and 2006.$2.1 million, respectively. As of September 30, 2008,2009, unrecognized compensation expense related to stock options totaled approximately $0.3 million,$47,000, which will be recognized over a weighted average period of 8.63.0 months. For a summary of transactions during 20082009 involving option shares for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
77
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The fair value of options at the date of grant was estimated using a Binomial option-pricing model for options granted prior to October 1, 2005 and the Black-Scholes-Merton closed form model for options granted after September 30, 2005.model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
|
Risk Free Interest Rate | | | N/A | | | | 4.46 | % | | | 5.08 | % | | | N/A | | | | N/A | | | | 4.46 | % |
Expected Life (Years) | | | N/A | | | | 7.0 | | | | 7.0 | | | | N/A | | | | N/A | | | | 7.0 | |
Expected Volatility | | | N/A | | | | 17.73 | % | | | 17.71 | % | | | N/A | | | | N/A | | | | 17.73 | % |
Expected Dividend Yield (Quarterly) | | | N/A | | | | 0.76 | % | | | 0.83 | % | | | N/A | | | | N/A | | | | 0.76 | % |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the option. The expected life and expected volatility are based on historical experience.
For grants during the yearsyear ended September 30, 2007, and 2006, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Non-Performance Based Stock-settled SARs
There were noParticipants in the stock option and award plans did not exercise any non-performance based stock-settled SARs exercised during the years ended September 30, 2009, 2008 and 2007 and 2006 assince none of the non-performance based stock-settled SARs granted have vested. ThereAs stated above, there were 50,000 non-performance based stock-settled SARs granted during 2007. The weighted average grant date fair value of non-performance based stock-settled SARs granted in 2007 is $7.81 per share. There were noThe Company did not grant any non-performance based stock-settled SARs granted during 20082009 or 2006.2008. As of September 30, 2008,2009, unrecognized compensation expense related to non-performance based stock-settled SARs totaled approximately $0.2$0.1 million, which will be recognized over a weighted average period of 10.24.3 months. For a summary of transactions during
73
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2008 2009 involving non-performance based stock-settled SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
The fair value of non-performance based stock-settled SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
| | | | |
| | Year Ended
| |
| | September 30,
| |
| | 2007 | |
|
Risk Free Interest Rate | | | 4.53 | % |
Expected Life (Years) | | | 7.0 | |
Expected Volatility | | | 17.55 | % |
Expected Dividend Yield (Quarterly) | | | 0.73 | % |
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
|
Risk Free Interest Rate | | | N/A | | | | N/A | | | | 4.53 | % |
Expected Life (Years) | | | N/A | | | | N/A | | | | 7.0 | |
Expected Volatility | | | N/A | | | | N/A | | | | 17.55 | % |
Expected Dividend Yield (Quarterly) | | | N/A | | | | N/A | | | | 0.73 | % |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the non-performance based stock-settled SARs. The expected life and expected volatility are based on historical experience.
For grants during the year ended September 30, 2007, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Performance Based Stock-settled SARs
There were noParticipants in the stock option and award plans did not exercise any performance based stock-settled SARs exercised during the years ended September 30, 2009, 2008 2007 and 2006 as none of the performance based stock-settled SARs granted have vested. There2007. As stated above, there were 610,000 and 321,000 performance based stock-settled SARs granted during 2008.the years ended September 30, 2009 and 2008,
78
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
respectively. The weighted average grant date fair value of performance based stock-settled SARs granted in 2009 and 2008 is $4.09 per share and $9.06 per share. There were noshare, respectively. The Company did not grant any performance based stock-settled SARs granted during 2007 or 2006.2007. For the yearsyear ended September 30, 2008, 2007 and 2006, there were no2009, 96,984 performance based stock-settled SARs became fully vested. Fiscal 2009 was the first year in which performance based stock-settled SARs became vested. The total fair value of the performance based stock-settled SARs that became fully vested.vested during the year ended September 30, 2009 was approximately $0.8 million. As of September 30, 2008,2009, unrecognized compensation expense related to performance based stock-settled SARs totaled approximately $1.9$1.3 million, which will be recognized over a weighted average period of 1.1 years.10.9 months. For a summary of transactions during 20082009 involving performance based stock-settled SARs for all plans, refer to Note E — Capitalization and Short-Term Borrowings.
The fair value of performance based stock-settled SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
| | | | |
| | Year Ended
| |
| | September 30,
| |
| | 2008 | |
|
Risk Free Interest Rate | | | 3.78 | % |
Expected Life (Years) | | | 7.25 | |
Expected Volatility | | | 17.69 | % |
Expected Dividend Yield (Quarterly) | | | 0.64 | % |
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
|
Risk Free Interest Rate | | | 2.56 | % | | | 3.78 | % | | | N/A | |
Expected Life (Years) | | | 7.50 | | | | 7.25 | | | | N/A | |
Expected Volatility | | | 22.16 | % | | | 17.69 | % | | | N/A | |
Expected Dividend Yield (Quarterly) | | | 1.09 | % | | | 0.64 | % | | | N/A | |
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the performance based stock-settled SARs. The expected life and expected volatility are based on historical experience.
For grants during the yearyears ended September 30, 2009 and 2008, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
74
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Restricted Share Awards
The weighted average fair value of restricted share awards granted in 2009, 2008 and 2007 and 2006 is $47.46 per share, $48.41 per share $40.18 per share and $34.94$40.18 per share, respectively. As of September 30, 2008,2009, unrecognized compensation expense related to restricted share awards totaled approximately $1.6$3.9 million, which will be recognized over a weighted average period of 2.54.4 years. For a summary of transactions during 20082009 involving restricted share awards, refer to Note E — Capitalization and Short-Term Borrowings.
During 2006, a modification was made to a restricted share award involving one employee. The modification accelerated the vesting date of 4,000 shares from December 7, 2006 to July 1, 2006. The incremental compensation expense, totaling approximately $32,000, was included with the total stock-based compensation expense for the year ended September 30, 2006.
New Authoritative Accounting Pronouncementsand Financial Reporting Guidance
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 providesauthoritative guidance for using fair value to measure assets and liabilities. The pronouncementThis guidance serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157This guidance is to be applied whenever another standard requires or allows assets or liabilities are to be measured at fair value. In accordance with FASB Staff PositionFAS No. 157-2, SFAS 157 is effectiveOn October 1, 2008, the Company adopted this guidance for financial assets and financial liabilities that are recognized or disclosed at fair value on a recurring basis as of the Company’s first quarter of fiscal 2009. The same FASB Staff Positionbasis. This guidance delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value on a recurring basis, until the Company’s first quarter of fiscal 2010. For further discussion of the impact of the adoption of the authoritative guidance for financial assets and financial liabilities, refer to Note F — Fair Value Measurements. The Company does not expectis currently evaluating the impact that SFAS 157the adoption of the authoritative guidance for nonfinancial assets and nonfinancial liabilities will have a significant impact on its consolidated financial statements. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of this guidance. The Company does not believe there are any nonfinancial liabilities that will be impacted by the adoption of this guidance.
79
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158authoritative guidance which requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncementThis guidance requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. This guidance also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. In accordance with SFAS 158,this authoritative guidance, the Company has recognized the funded status of its benefit plans and implemented the related disclosure requirements of SFAS 158 at September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will bewas fully adopted by the Company by the endas of fiscalSeptember 30, 2009. Currently, theThe Company measureshas historically measured its plan assets and benefit obligations using a June 30th measurement date. AtAs a result of the change to a September 30, 2007, in order to recognize the funded status of its pension and post-retirement benefit plans in accordance with SFAS 158,30th measurement date, the Company recorded additional liabilities or reduced assetsfifteen months of pension and other post-retirement benefit costs during fiscal 2009. Such costs were calculated using June 30, 2008 measurement date data. Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $5.1 million and were recorded by the Company during the quarter ended December 31, 2008 as a cumulative amount of $78.7$3.8 million ($71.1 million net of deferred tax benefits recognized for the portion recorded as an increase to Accumulated Other Comprehensive Loss). Of the $71.1 million recognized, $61.9 million was recorded as an increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments $12.5and a $1.3 million (net of deferred tax benefits of $7.6 million) was recorded as an increase($0.8 million after tax) adjustment to Accumulated Other Comprehensive Loss, and $3.3 million was recorded as an increase to Other Regulatory Liabilitiesearnings reinvested in the Company’s Utility segment. The Company has recorded amounts to Other Regulatory Assets or Other Regulatory Liabilities in the Utility and Pipeline and Storage segments in accordance with the provisions of SFAS 71. The Company, in those segments, has certain regulatory commission authorizations, which allow the Company to defer as a regulatory asset or liability the difference between pension and post-retirement benefit costs as calculated in accordance with SFAS 87 and SFAS 106 and what is collected in rates.business. Refer to Note GH — Retirement Plan and Other Post-Retirement Benefits for further disclosures regarding the impact of SFAS 158this authoritative guidance on the Company’s consolidated financial statements.
75
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of SFAS 115.” SFAS 159 permits entities to choose to measure many financial instruments at fair value that are not otherwise required to be measured at fair value under GAAP. A company that elects the fair value option for an eligible item will be required to recognize in current earnings any changes in that item’s fair value in reporting periods subsequent to the date of adoption. SFAS 159 is effective as of the Company’s first quarter of fiscal 2009. The Company does not plan to elect the fair value measurement option for any of its financial instruments other than those that are already being measured at fair value.
In December 2007, the FASB issued SFAS 141R, “Business Combinations.” SFAS 141R willrevised authoritative guidance that significantly changechanges the accounting for business combinations in a number of areas including the treatment of contingent consideration, contingencies, acquisition costs, in process research and development and restructuring costs. In addition, under SFAS 141R,this guidance, changes in deferred tax asset valuation allowances and acquired income tax uncertainties in a business combination after the measurement period will impact income tax expense. SFAS 141RThis guidance is effective as of the Company’s first quarter of fiscal 2010.
In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB 51.” SFAS 160 will changeauthoritative guidance that changes the accounting and reporting for minority interests, which will be recharacterized as noncontrolling interests (NCI) and classified as a component of equity. This new consolidation method will significantly change the accounting for transactions with minority interest holders. SFAS 160This authoritative guidance is effective as of the Company’s first quarter of fiscal 2010. The Company currently does not have any NCI.
In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities, an Amendment of SFAS 133.” SFAS 161authoritative guidance that requires entities to provide enhanced disclosures related to an entity’s derivative instruments and hedging activities in order to enable investors to better understand how derivative instruments and hedging activities impact an entity’s financial reporting. The additional disclosures include how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133authoritative guidance for derivative instruments and its related interpretations,hedging activities, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161The Company adopted the disclosure provisions of this authoritative guidance during the Company’s second quarter of fiscal 2009. Refer to Note G — Financial Instruments for these disclosures.
In June 2008, the FASB issued authoritative guidance concerning whether certain instruments granted in share-based payment transactions are participating securities. This guidance specified that unvested share-based payment awards that contain nonforfeitable rights to dividends are participating securities and shall be included in the computation of earnings per share pursuant to the “two-class” method. The“two-class” method allocates undistributed earnings between common shares and participating securities. This authoritative
80
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
guidance is effective as of the Company’s secondfirst quarter of fiscal 2009.2010. The Company does not believe this guidance will have a material impact on its earnings per share calculation.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting. The final rule modifies the SEC’s reporting and disclosure rules for oil and gas reserves and aligns the full cost accounting rules with the revised disclosures. The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and gas reserves to a12-month average of the first day of the month price for each month within the reporting period. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements are effective for the Company’sForm 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that the adoption of SFAS 161these rules will have on its consolidated financial statements and MD&A disclosures.
In March 2009, the FASB issued authoritative guidance that expands the disclosures required in an employer’s financial statements about pension and other post-retirement benefit plan assets. The additional disclosures include more details on how investment allocation decisions are made, the plan’s investment policies and strategies, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period, and disclosure regarding significant concentrations of risk within plan assets. The additional disclosure requirements are required for the Company’sForm 10-K for the period ended September 30, 2010. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
Effective with the June 30, 2009Form 10-Q, the Company adopted the FASB authoritative guidance for subsequent events that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Refer to Note R — Subsequent Events for disclosures made as a result of the adoption of this guidance.
In June 2009, the FASB issued authoritative guidance that establishes the FASB Accounting Standards Codificationtm (the Codification) as the source of authoritative GAAP recognized by the FASB to be applied by all nongovernmental entities in the notespreparation of financial statements in conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal securities law are also sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting literature not included in the Codification will become nonauthoritative. The Codification was effective for interim and annual periods ending after September 15, 2009. Effective with this September 30, 2009Form 10-K, the Company has updated its disclosures to conform to the Codification. There has been no impact on the Company’s consolidated financial statements.statements as the Codification does not change or alter existing GAAP.
| |
Note B — | Asset Retirement Obligations |
Note B — Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with the provisions of SFAS 143. SFAS 143authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timingand/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.
As previously disclosed, the Company follows the full cost method of accounting for its exploration and production costs. UponIn accordance with the adoption of SFAS 143 on October 1, 2002,current authoritative guidance for asset retirement obligations, the Company has recorded an asset retirement obligation representing plugging and abandonment costs associated
81
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
with the Exploration and Production segment’s crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool). Prior toUnder the adoption of SFAS 143, plugging and abandonment costs were accountedcurrent authoritative guidance for solely through the Company’s units-of-production depletion calculation. An estimate of such costs was added to the depletion base, which also included capitalized costs in the full cost pool and estimated future expenditures to be incurred in developing proved reserves. With the adoption of SFAS 143,asset retirement obligations, since plugging and abandonment costs are already included in capitalized costs and the full cost pool, theunits-of-production depletion calculation has been modified to excludeexcludes from the depletion base any estimate of future plugging and abandonment costs that are already recorded in the full cost pool.
The full cost method of accounting provides a limit to the amount of costs that can be capitalized in the full cost pool. This limit is referred to as the full cost ceiling. Prior toIn accordance with current authoritative guidance, since the adoptionfull cost pool includes an amount associated with plugging and abandoning the wells, as discussed in the preceding paragraph, the calculation of SFAS 143, in calculating the full
76
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
cost ceiling the Company reducedno longer reduces the future net cash flows from proved oil and gas reserves by the estimated plugging and abandonment costs. Such future net cash flows would then be compared to capitalized costs in the full cost pool, with any excess capitalized costs being expensed. With the adoptionan estimate of SFAS 143, since the full cost pool now includes an amount associated with plugging and abandoning the wells, the calculation of the full cost ceiling has been changed so that future net cash flows from proved oil and gas reserves are no longer reduced by the estimated plugging and abandonment costs.
On September 30, 2006,In addition to the Company adopted FIN 47, an interpretation of SFAS 143. FIN 47 provides clarification of the term “conditional asset retirement obligation” as used in SFAS 143, defined as a legal obligation to perform an asset retirement activity in which the timingand/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under this standard, if the fair value of a conditional asset retirement obligation can be reasonably estimated, a company must record a liabilityrecorded in the Exploration and a corresponding asset forProduction segment, the conditional asset retirement obligation representing the present value of that obligation at the date the obligation was incurred. FIN 47 also serves to clarify when a company would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation.
Upon the adoption of FIN 47, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company has also identifiedrecorded asset retirement obligations for certain costs connected with the retirement of distribution mains and services pipeline systems in the Utility segment and with the transmission mains and other components in the pipeline systems in the Pipeline and Storage segment. These retirement costs within the distribution and transmission systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for theclean-up of PCB contamination associated with the removal of certain pipe.
As a result of the implementation of FIN 47 as of September 30, 2006, the Company recorded additional asset retirement obligations of $23.2 million and corresponding long-lived plant assets, net of accumulated depreciation, of $3.5 million. These assets will be depreciated over their respective remaining depreciable life. The remaining $19.7 million represents the cumulative accretion and depreciation of the asset retirement obligations that would have been recognized if this interpretation had been in effect at the inception of the obligations. Of this amount, the Company recorded an increase to regulatory assets of $9.0 million and a reduction to cost of removal regulatory liability of $10.7 million. The cost of removal regulatory liability represents amounts collected from customers through depreciation expense in the Company’s Utility and Pipeline and Storage segments. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 requires that such costs of removal be reclassified from accumulated depreciation to other regulatory liabilities. At September 30, 2008 and 2007, the costs of removal reclassified to other regulatory liabilities amounted to $103.1 million and $91.2 million, respectively.
A reconciliation of the Company’s asset retirement obligation calculated in accordance with SFAS 143 is shown below:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | | | (Thousands) | | | | | | | (Thousands) | | | |
|
Balance at Beginning of Year | | $ | 75,939 | | | $ | 77,392 | | | $ | 41,411 | | | $ | 93,247 | | | $ | 75,939 | | | $ | 77,392 | |
Additions — Adoption of FIN 47 | | | — | | | | — | | | | 23,234 | | |
Liabilities Incurred and Revisions of Estimates | | | 18,739 | | | | (932 | ) | | | 11,244 | | | | 4,492 | | | | 18,739 | | | | (932 | ) |
Liabilities Settled | | | (6,871 | ) | | | (6,108 | ) | | | (1,303 | ) | | | (13,155 | ) | | | (6,871 | ) | | | (6,108 | ) |
Accretion Expense | | | 5,440 | | | | 5,394 | | | | 2,671 | | | | 6,789 | | | | 5,440 | | | | 5,394 | |
Exchange Rate Impact | | | — | | | | 193 | | | | 135 | | | | — | | | | — | | | | 193 | |
| | | | | | | | | | | | | | |
Balance at End of Year | | $ | 93,247 | | | $ | 75,939 | | | $ | 77,392 | | | $ | 91,373 | | | $ | 93,247 | | | $ | 75,939 | |
| | | | | | | | | | | | | | |
7782
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
Note C — | Regulatory Matters |
Note C — Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
| | | | | | | | | | | | | | | | |
| | At September 30 | | | At September 30 | |
| | 2008 | | 2007 | | | 2009 | | 2008 | |
| | (Thousands) | | | (Thousands) | |
|
Regulatory Assets(1): | | | | | | | | | | | | | | | | |
Pension and Other Post-Retirement Benefit Costs(2) (Note G) | | $ | 147,909 | | | $ | 98,787 | | |
Pension and Other Post-Retirement Benefit Costs(2) (Note H) | | | $ | 461,352 | | | $ | 147,909 | |
Recoverable Future Taxes (Note D) | | | 82,506 | | | | 83,954 | | | | 138,435 | | | | 82,506 | |
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A) | | | 37,708 | | | | 14,769 | | |
Environmental Site Remediation Costs(2) (Note H) | | | 22,530 | | | | 20,738 | | |
NYPSC Assessment(2) | | | | 24,445 | | | | — | |
Environmental Site Remediation Costs(2) (Note I) | | | | 21,456 | | | | 22,530 | |
Asset Retirement Obligations(2) (Note B) | | | 8,155 | | | | 8,315 | | | | 7,884 | | | | 8,155 | |
Unamortized Debt Expense (Note A) | | | 7,524 | | | | 8,470 | | | | 6,610 | | | | 7,524 | |
Recoverable Worker Compensation Expense(2) | | | 4,518 | | | | 4,445 | | |
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A) | | | | — | | | | 37,708 | |
Other(2) | | | 6,475 | | | | 5,292 | | | | 15,776 | | | | 10,993 | |
| | | | | | | | | | |
Total Regulatory Assets | | | 317,325 | | | | 244,770 | | | | 675,958 | | | | 317,325 | |
| | | | | | | | | | |
Regulatory Liabilities: | | | | | | | | | | | | | | | | |
Cost of Removal Regulatory Liability (Note B) | | | 103,100 | | | | 91,226 | | |
Pension and Other Post-Retirement Benefit Costs(3) (Note G) | | | 42,994 | | | | 21,676 | | |
Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | | | | 105,778 | | | | 2,753 | |
Cost of Removal Regulatory Liability | | | | 105,546 | | | | 103,100 | |
Taxes Refundable to Customers (Note D) | | | | 67,046 | | | | 18,449 | |
Pension and Other Post-Retirement Benefit Costs(3) (Note H) | | | | 61,003 | | | | 42,994 | |
Tax Benefit on Medicare Part D Subsidy(3) | | | 23,502 | | | | 19,147 | | | | 28,817 | | | | 23,502 | |
New York Rate Settlements(3) | | | 19,012 | | | | 27,964 | | |
Taxes Refundable to Customers (Note D) | | | 18,449 | | | | 14,026 | | |
Off-System Sales and Capacity Release Credits(3) | | | | 8,340 | | | | 8,977 | |
Deferred Insurance Proceeds(3) | | | 3,933 | | | | 7,422 | | | | 3,804 | | | | 3,933 | |
Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | | | 2,753 | | | | 10,409 | | |
Other(3) | | | 2,492 | | | | 450 | | | | 18,265 | | | | 12,527 | |
| | | | | | | | | | |
Total Regulatory Liabilities | | | 216,235 | | | | 192,320 | | | | 398,599 | | | | 216,235 | |
| | | | | | | | | | |
Net Regulatory Position | | $ | 101,090 | | | $ | 52,450 | | | $ | 277,359 | | | $ | 101,090 | |
| | | | | | | | | | |
| | |
(1) | | The Company recovers the cost of its regulatory assets but with the exception of Unrecovered Purchased Gas Costs,generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates. |
|
(2) | | Included in Other Regulatory Assets on the Consolidated Balance Sheets. |
|
(3) | | Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. |
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheetConsolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item.
7883
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
New York Rate SettlementsCost of Removal Regulatory Liability
With respect to utility services providedIn the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in New York,Note B — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has entered into rate settlements approved bycollected dollars from the NYPSC. The rate settlements have given rise to several significant liabilities, which are described as follows:
Gross Receipts Tax Over-Collections — In accordance with NYPSC policies, Distribution Corporation deferred the difference between the revenues it collects under a New York State gross receipts tax surcharge and its actual New York State income tax expense. Distribution Corporation’s cumulative gross receipts tax revenues exceeded its New York State income tax expense, resulting in a regulatory liability at September 30, 2008 and 2007 of $4.1 million and $6.7 million, respectively. Under the terms of its 2005 rate agreement, Distribution Corporation has been passing backcustomer that regulatory liability to rate payers since August 1, 2005. Further, the gross receipts tax surcharge that gave rise to the regulatory liability was eliminated from Distribution Corporation’s tariff (New York State income taxes are now recovered as a component of base rates).
Cost Mitigation Reserve (“CMR”) — The CMR is a regulatory liability that canwill be used to offset certain expense items specified in Distribution Corporation’s rate settlements. The source of the CMR was principally the accumulation of certain refunds from upstream pipeline companies. During 2005, under the terms of the 2005 rate agreement, Distribution Corporation transferred the remaining balance in a generic restructuring reserve (which had been established in a prior rate settlement) and the balances it had accumulated under various earnings sharing mechanisms to the CMR. The balance in the CMR at September 30, 2008 and 2007 amounted to $0.3 million and $7.4 million, respectively.
Other — The 2005 agreement also established a reservefuture to fund area development projects. The balance in the area development projects reserve at September 30, 2008 and 2007 amounted to $3.0 million and $3.6 million, respectively (Distribution Corporation established the reserve at September 30, 2005 by transferring $3.8 million from the CMR discussed above). Various other regulatory liabilities have also been created through the New York rate settlements and amounted to $11.6 million and $10.3 million at September 30, 2008 and 2007, respectively.asset retirement costs.
Tax Benefit on Medicare Part D Subsidy
The Company has established a regulatory liability for the tax benefit it will receive under the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act). The Act provides a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In the Company’s Utility and Pipeline and Storage segments, the ratepayercustomer funds the Company’s post-retirement benefit plans. As such, any tax benefit received under the Act must be flowed-through to the ratepayer.customer. Refer to Note GH — Retirement Plan and Other Post-Retirement Benefits for further discussion of the Act and its impact on the Company.
Deferred Insurance Proceeds
The Company, in its Utility and Pipeline and Storage segments,segment, has deferred environmental insurance settlement proceeds amounting to $3.9$3.8 million and $7.4$3.9 million at September 30, 20082009 and 2007,2008, respectively. Such proceeds have been deferred as a regulatory liability to be applied against any future environmental claims that may be incurred. The proceeds have been classified as a regulatory liability in recognition of the fact that ratepayerscustomers funded the premiums on the former insurance policies.
Recoverable Worker Compensation ExpenseNYPSC Assessment
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the current rate ofone-third of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge equal, as applied, to an additional one percent of the utility’s gross operating revenue. The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills in the Utility segment’s New York jurisdiction.
Off-System Sales and Capacity Release Credits
The Company, has established a liability in its Utility segment, in accordancehas entered into off-system sales and capacity release transactions. Most of the margins on such transactions are returned to the customer with only a small percentage being retained by the provisions of SFAS 112 for future worker compensation liabilities. Such amounts haveCompany. The amount owed to the customer has been deferred as a regulatory asset because the Company is allowed to recover worker compensation expense in rates.liability.
7984
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note D — Income Taxes
The components of federal, state and foreign income taxes included in the Consolidated Statements of Income are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | | | (Thousands) | | | | | | | (Thousands) | | | |
|
Current Income Taxes — | | | | | | | | | | | | | | | | | | | | | | | | |
Federal | | $ | 75,079 | | | $ | 99,608 | | | $ | 65,593 | | | $ | 43,300 | | | $ | 75,079 | | | $ | 99,608 | |
State | | | 20,257 | | | | 21,700 | | | | 13,511 | | | | 10,341 | | | | 20,257 | | | | 21,700 | |
Foreign | | | 90 | | | | 22 | | | | 2,212 | | | | — | | | | 90 | | | | 22 | |
Deferred Income Taxes — | | | | | | | | | | | | | | | | | | | | | | | | |
Federal | | | 56,668 | | | | 39,340 | | | | 19,111 | | | | (4,940 | ) | | | 56,668 | | | | 39,340 | |
State | | | 15,828 | | | | 10,751 | | | | 9,024 | | | | 2,419 | | | | 15,828 | | | | 10,751 | |
Foreign | | | — | | | | 2,756 | | | | (33,365 | ) | | | — | | | | — | | | | 2,756 | |
| | | | | | | | | | | | | | |
| | | 167,922 | | | | 174,177 | | | | 76,086 | | | | 51,120 | | | | 167,922 | | | | 174,177 | |
Deferred Investment Tax Credit | | | (697 | ) | | | (697 | ) | | | (697 | ) | | | (697 | ) | | | (697 | ) | | | (697 | ) |
| | | | | | | | | | | | | | |
Total Income Taxes | | $ | 167,225 | | | $ | 173,480 | | | $ | 75,389 | | | $ | 50,423 | | | $ | 167,225 | | | $ | 173,480 | |
| | | | | | | | | | | | | | |
Presented as Follows: | | | | | | | | | | | | | | | | | | | | | | | | |
Other Income | | $ | (697 | ) | | $ | (697 | ) | | $ | (697 | ) | | $ | (697 | ) | | $ | (697 | ) | | $ | (697 | ) |
Income Tax Expense — Continuing Operations | | | 167,922 | | | | 131,813 | | | | 108,245 | | | | 51,120 | | | | 167,922 | | | | 131,813 | |
Discontinued Operations — | | | | | | | | | | | | | | | | | | | | | | | | |
Income From Operations | | | — | | | | 2,792 | | | | (32,159 | ) | | | — | | | | — | | | | 2,792 | |
Gain on Disposal | | | — | | | | 39,572 | | | | — | | | | — | | | | — | | | | 39,572 | |
| | | | | | | | | | | | | | |
Total Income Taxes | | $ | 167,225 | | | $ | 173,480 | | | $ | 75,389 | | | $ | 50,423 | | | $ | 167,225 | | | $ | 173,480 | |
| | | | | | | | | | | | | | |
The U.S. and foreign components of income (loss) before income taxes are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | | | (Thousands) | | | | | (Thousands) | |
|
U.S. | | $ | 435,982 | | | $ | 496,074 | | | $ | 293,887 | | | $ | 151,160 | | | $ | 435,982 | | | $ | 496,074 | |
Foreign | | | (29 | ) | | | 14,861 | | | | (80,407 | ) | | | (29 | ) | | | (29 | ) | | | 14,861 | |
| | | | | | | | | | | | | | |
| | $ | 435,953 | | | $ | 510,935 | | | $ | 213,480 | | | $ | 151,131 | | | $ | 435,953 | | | $ | 510,935 | |
| | | | | | | | | | | | | | |
8085
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | | | (Thousands) | | | | | (Thousands) | |
|
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% | | $ | 152,584 | | | $ | 178,827 | | | $ | 74,718 | | | $ | 52,896 | | | $ | 152,584 | | | $ | 178,827 | |
Increase in Taxes Resulting from: | | | | | | | | | | | | | |
Increase (Reduction) in Taxes Resulting from: | | | | | | | | | | | | | |
State Income Taxes | | | 23,455 | | | | 21,093 | | | | 14,648 | | | | 8,294 | | | | 23,455 | | | | 21,093 | |
Foreign Tax Differential | | | 69 | | | | (20,980 | ) | | | (3,718 | ) | | | 10 | | | | 69 | | | | (20,980 | ) |
Reversal of Capital Loss Valuation Allowance | | | — | | | | — | | | | (2,877 | ) | |
Miscellaneous | | | (8,883 | ) | | | (5,460 | ) | | | (7,382 | ) | | | (10,777 | ) | | | (8,883 | ) | | | (5,460 | ) |
| | | | | | | | | | | | | | |
Total Income Taxes | | $ | 167,225 | | | $ | 173,480 | | | $ | 75,389 | | | $ | 50,423 | | | $ | 167,225 | | | $ | 173,480 | |
| | | | | | | | | | | | | | |
The foreign tax differential amount shown above for 2007 includes tax effects relating to the gain on disposition of a foreign subsidiary. Also, the foreign tax differential amount shown above for 2006 includes a $5.1 million deferred tax benefit relating to additional future tax deductions forecasted in Canada. The miscellaneous amount shown above for 2006 includes a net reversal of $3.2 million relating to a tax contingency reserve.
Significant components of the Company’s deferred tax liabilities and assets are as follows:
| | | | | | | | | | | | | | | | |
| | At September 30 | | | At September 30 | |
| | 2008 | | 2007 | | | 2009 | | 2008 | |
| | (Thousands) | | | (Thousands) | |
|
Deferred Tax Liabilities: | | | | | | | | | | | | | | | | |
Property, Plant and Equipment | | $ | 673,313 | | | $ | 612,648 | | | $ | 733,581 | | | $ | 673,313 | |
Pension and Other Post-Retirement Benefit Costs — SFAS 158 | | | 43,340 | | | | 21,892 | | |
Pension and Other Post-Retirement Benefit Costs | | | | 164,120 | | | | 43,340 | |
Other | | | 55,391 | | | | 39,724 | | | | 69,297 | | | | 55,391 | |
| | | | | | | | | | |
Total Deferred Tax Liabilities | | | 772,044 | | | | 674,264 | | | | 966,998 | | | | 772,044 | |
| | | | | | | | | | |
Deferred Tax Assets: | | | | | | | | | | | | | | | | |
Pension and Other Post-Retirement Benefit Costs — SFAS 158 | | | (43,340 | ) | | | (21,892 | ) | |
Pension and Other Post-Retirement Benefit Costs | | | | (202,627 | ) | | | (55,309 | ) |
Other | | | (92,461 | ) | | | (85,566 | ) | | | (154,358 | ) | | | (80,492 | ) |
| | | | | | | | | | |
Total Deferred Tax Assets | | | (135,801 | ) | | | (107,458 | ) | | | (356,985 | ) | | | (135,801 | ) |
| | | | | | | | | | |
Total Net Deferred Income Taxes | | $ | 636,243 | | | $ | 566,806 | | | $ | 610,013 | | | $ | 636,243 | |
| | | | | | | | | | |
Presented as Follows: | | | | | | | | | | | | | | | | |
Net Deferred Tax Liability/(Asset) — Current | | $ | 1,871 | | | $ | (8,550 | ) | | $ | (53,863 | ) | | $ | 1,871 | |
Net Deferred Tax Liability — Non-Current | | | 634,372 | | | | 575,356 | | | | 663,876 | | | | 634,372 | |
| | | | | | | | | | |
Total Net Deferred Income Taxes | | $ | 636,243 | | | $ | 566,806 | | | $ | 610,013 | | | $ | 636,243 | |
| | | | | | | | | | |
As of September 30, 2009, the Company recorded a deferred tax asset relating to a federal net operating loss carryover of $25.1 million. This carryover, which is available as a result of an acquisition, expires in varying amounts between 2023 and 2029. Although this loss carryover is subject to certain annual limitations, no valuation allowance was recorded because of management’s determination that the amount will be fully utilized during the carryforward period.
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $18.4$67.0 million and $14.0$18.4 million at September 30, 20082009 and 2007,2008, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $82.5 million and $84.0 million at September 30, 2008 and 2007, respectively.
8186
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
of prior ratemaking practices, amounted to $138.4 million and $82.5 million at September 30, 2009 and 2008, respectively.
During fiscal 2009, consent was received from the Internal Revenue Service (IRS) National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. Included in the regulatory liabilities and assets as of September 30, 2009 noted above are liabilities of $47.3 million and assets of $51.1 million associated with this tax accounting method change.
The Company adopted FIN 48the FASB authoritative guidance for income tax uncertainties on October 1, 2007. As of the date of adoption, a cumulative effect adjustment was recorded that resulted in a decrease to retained earnings of $0.4 million. Upon adoption, the unrecognized tax benefits were $1.7 million, all of which would impact the effective tax rate (net of federal benefit) if recognized.million.
A tabular reconciliation of the change in unrecognized tax benefits for the twelve monthsyear ended September 30, 2009 and 2008 is as follows:
| | | | |
| | Amount | |
| | (thousands) | |
|
Opening Balance of Unrecognized Tax Benefits — October 1, 2007 | | $ | 1,700 | |
Gross Increase — Tax Positions in Prior Periods | | | — | |
Gross Decrease — Tax Positions in Prior Periods | | | — | |
Gross Increase — Tax Positions in Current Periods | | | — | |
Gross Decrease — Tax Positions in Current Periods | | | — | |
Decrease in Unrecognized Tax Benefits Related to Tax Settlements | | | — | |
Reduction to Unrecognized Tax Benefits Due to Lapse of Statute of Limitations | | | — | |
| | | | |
Ending Balance of Unrecognized Tax Benefits — September 30, 2008 | | $ | 1,700 | |
| | | | |
| | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | |
| | (Thousands) | |
|
Balance at Beginning of Year | | $ | 1,700 | | | $ | 1,700 | |
Additions for Tax Positions Related to Current Year | | | 8,721 | | | | — | |
Additions for Tax Positions of Prior Years | | | — | | | | — | |
Reductions for Tax Positions of Prior Years | | | — | | | | — | |
Settlements with Taxing Authorities | | | (1,700 | ) | | | — | |
Lapse of Statute of Limitations | | | — | | | | — | |
| | | | | | | | |
Balance at End of Year | | $ | 8,721 | | | $ | 1,700 | |
| | | | | | | | |
WithinThe balance of $8.7 million as of September 30, 2009 relates to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Due to the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not materially affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company anticipates that the unrecognized tax benefits will not significantly change within the next twelve months, the Company believes it is reasonably possible that the total amount of unrecognized tax benefits may be eliminated. This potential decrease in the amount of unrecognized tax benefits is associated with the anticipated completion of state income tax audits for various prior years.months.
The Company recognizes estimated interest payable relating to income taxes in Other Interest Expense and estimated penalties relating to income taxes in Other Income. The Company has accrueddid not recognize any interest expense related to income taxes during fiscal 2009. The Company recognized interest expense related to income taxes of $0.5 million through September 30, 2008 andduring fiscal 2008. The Company has not accrued any penalties.penalties during fiscal 2009 and 2008.
The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS)IRS is currently conducting an examination of the Company for fiscal 20082009 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 20052006 and later years, IRS examinations for fiscal 20072008 and prior years have been completed and the Company believes such years are effectively settled.
ForThe Company is also subject to various routine state income tax examinations. The Company’s operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the major states in whichdate of filing of the various subsidiary companies operate, the earliestincome tax year open for examination is as follows:
| | |
New York | | Fiscal 2002 |
Pennsylvania | | Fiscal 2003 |
California | | Fiscal 2004 |
Texas | | Fiscal 2004 |
return.
8287
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
Note E — | Capitalization and Short-Term Borrowings |
Note E — Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Earnings
| | Accumulated
| | | | | | | | | Earnings
| | Accumulated
| |
| | | | | | | | Reinvested
| | Other
| | | | | | | | | Reinvested
| | Other
| |
| | | | | | Paid
| | in
| | Comprehensive
| | | | | | | Paid
| | in
| | Comprehensive
| |
| | Common Stock | | In
| | the
| | Income
| | | Common Stock | | In
| | the
| | Income
| |
| | Shares | | Amount | | Capital | | Business | | (Loss) | | | Shares | | Amount | | Capital | | Business | | (Loss) | |
| | (Thousands, except per share amounts) | | | | | (Thousands, except per share amounts) | | | |
|
Balance at September 30, 2005 | | | 84,357 | | | $ | 84,357 | | | $ | 529,834 | | | $ | 813,020 | | | $ | (197,628 | ) | |
Net Income Available for Common Stock | | | | | | | | | | | | | | | 138,091 | | | | | | |
Dividends Declared on Common Stock ($1.18 Per Share) | | | | | | | | | | | | | | | (98,829 | ) | | | | | |
Other Comprehensive Income, Net of Tax | | | | | | | | | | | | | | | | | | | 228,044 | | |
Share-Based Payment Expense(2) | | | | | | | | | | | 1,705 | | | | | | | | | | |
Common Stock Issued Under Stock and Benefit Plans(1) | | | 1,572 | | | | 1,572 | | | | 28,564 | | | | | | | | | | |
Share Repurchases | | | (2,526 | ) | | | (2,526 | ) | | | (16,373 | ) | | | (66,269 | ) | | | | | |
| | | | | | | | | | | | |
Balance at September 30, 2006 | | | 83,403 | | | | 83,403 | | | | 543,730 | | | | 786,013 | | | | 30,416 | | | | 83,403 | | | $ | 83,403 | | | $ | 543,730 | | | $ | 786,013 | | | $ | 30,416 | |
| | | | | | | | | | | | |
Net Income Available for Common Stock | | | | | | | | | | | | | | | 337,455 | | | | | | | | | | | | | | | | | | | | 337,455 | | | | | |
Dividends Declared on Common Stock ($1.22 Per Share) | | | | | | | | | | | | | | | (101,496 | ) | | | | | | | | | | | | | | | | | | | (101,496 | ) | | | | |
Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | (24,137 | ) | | | | | | | | | | | | | | | | | | | (24,137 | ) |
Adjustment to Recognize the Funded Position of the Pension and Other Post-Retirement Benefit Plans | | | | | | | | | | | | | | | | | | | (12,482 | ) | | | | | | | | | | | | | | | | | | | (12,482 | ) |
Share-Based Payment Expense(2) | | | | | | | | | | | 3,727 | | | | | | | | | | | | | | | | | | | | 3,727 | | | | | | | | | |
Common Stock Issued Under Stock and Benefit Plans(1) | | | 1,367 | | | | 1,367 | | | | 30,193 | | | | | | | | | | | | 1,367 | | | | 1,367 | | | | 30,193 | | | | | | | | | |
Share Repurchases | | | (1,309 | ) | | | (1,309 | ) | | | (8,565 | ) | | | (38,196 | ) | | | | | | | (1,309 | ) | | | (1,309 | ) | | | (8,565 | ) | | | (38,196 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
Balance at September 30, 2007 | | | 83,461 | | | | 83,461 | | | | 569,085 | | | | 983,776 | | | | (6,203 | ) | | | 83,461 | | | | 83,461 | | | | 569,085 | | | | 983,776 | | | | (6,203 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
Net Income Available for Common Stock | | | | | | | | | | | | | | | 268,728 | | | | | | | | | | | | | | | | | | | | 268,728 | | | | | |
Dividends Declared on Common Stock ($1.27 Per Share) | | | | | | | | | | | | | | | (103,523 | ) | | | | | | | | | | | | | | | | | | | (103,523 | ) | | | | |
Cumulative Effect of the Adoption of FIN 48 | | | | | | | | | | | | | | | (406 | ) | | | | | |
Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | 9,166 | | |
Cumulative Effect of the Adoption of Authoritative Guidance for Income Taxes | | | | | | | | | | | | | | | | (406 | ) | | | | |
Other Comprehensive Income, Net of Tax | | | | | | | | | | | | | | | | | | | | 9,166 | |
Share-Based Payment Expense(2) | | | | | | | | | | | 2,332 | | | | | | | | | | | | | | | | | | | | 2,332 | | | | | | | | | |
Common Stock Issued Under Stock and Benefit Plans(1) | | | 854 | | | | 854 | | | | 33,335 | | | | | | | | | | | | 854 | | | | 854 | | | | 33,335 | | | | | | | | | |
Share Repurchases | | | (5,194 | ) | | | (5,194 | ) | | | (37,036 | ) | | | (194,776 | ) | | | | | | | (5,194 | ) | | | (5,194 | ) | | | (37,036 | ) | | | (194,776 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
Balance at September 30, 2008 | | | 79,121 | | | $ | 79,121 | | | $ | 567,716 | | | $ | 953,799 | (3) | | $ | 2,963 | | | | 79,121 | | | | 79,121 | | | | 567,716 | | | | 953,799 | | | | 2,963 | |
| | | | | | | | | | | | | | | | | | | | | | |
Net Income Available for Common Stock | | | | | | | | | | | | | | | | 100,708 | | | | | |
Dividends Declared on Common Stock ($1.32 Per Share) | | | | | | | | | | | | | | | | (105,410 | ) | | | | |
Adoption of Authoritative Guidance for Defined Benefit Pension and Other Post-Retirement Plans | | | | | | | | | | | | | | | | (804 | ) | | | | |
Other Comprehensive Loss, Net of Tax | | | | | | | | | | | | | | | | | | | | (45,359 | ) |
Share-Based Payment Expense(2) | | | | | | | | | | | | 2,055 | | | | | | | | | |
Common Stock Issued Under Stock and Benefit Plans(1) | | | | 1,379 | | | | 1,379 | | | | 33,068 | | | | | | | | | |
| | | | | | | | | | | | |
Balance at September 30, 2009 | | | | 80,500 | | | $ | 80,500 | | | $ | 602,839 | | | $ | 948,293 | (3) | | $ | (42,396 | ) |
| | | | | | | | | | | | |
88
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | |
(1) | | Paid in Capital includes tax benefits of $5.9 million, $16.3 million $13.7 million and $6.5$13.7 million for September 30, 2009, 2008 2007 and 2006,2007, respectively, associated with the exercise of stock options. |
|
(2) | | As of October 1, 2005, Paid in Capital includes compensation costs associated with stock option, stock-settled SARs and/or restricted stock awards, in accordance with SFAS 123R.awards. The expense is included within Net Income Available For Common Stock, net of tax benefits. |
|
(3) | | The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2008, $808.82009, $804.1 million of accumulated earnings was free of such limitations. |
83
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Common Stock
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.
During 2008,2009, the Company issued 890,9441,609,597 original issue shares of common stock as a result of stock option exercises and 25,00063,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R)existing guidance). Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise pricesand/or applicable withholding taxes. During 2008, 72,2052009, 303,091 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
The Company also has a director stock program under which it issues shares of Company common stock to the eight non-employee directors of the Company who receive compensation under the Company’s Retainer Policy for Non-Employee Directors, as partial consideration for their services as directors.the directors’ services. Under this program, the Company issued 9,6009,865 original issue shares of common stock during 2008.2009.
In December 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of eight million shares in the open market or through privately negotiated transactions. The Company completed the repurchase of the eight million shares during 2008 for a total program cost of $324.2 million (of which 4,165,122 shares were repurchased during the year ended September 30, 2008 for $191.0 million). In September 2008, the Company’s Board of Directors authorized the repurchase of an additional eight million shares. Under this new authorization, the Company repurchased 1,028,981 shares for $46.0 million through September 17, 2008. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. However, suchSuch repurchases may be made in the future if conditions improve. Allfuture. The share repurchases mentioned above were funded with cash provided by operating activitiesand/or through the use of the Company’s lines of credit.
Shareholder Rights Plan
In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended fiveseveral times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective July 11, 2008, which is an Exhibit to this Annual Report and
89
Form 10-K.NATIONAL FUEL GAS COMPANY
TheNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Agreement effective December 4, 2008, a copy of which was included as an exhibit to theForm 8-K filed by the Company on December 4, 2008.
Pursuant to the Plan, the holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock.
The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors (an Acquiring Person).
The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date Rights that are owned by an Acquiring Person will be null and void. At any time following a
84
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Distribution Date, each holder of a Right may exercise its right to receive, a numberupon payment of shares ofan amount calculated under the Rights Agreement, common stock determined in accordance with a Plan formula that is based on the current market value of the Company’s common stock. UnderCompany (or, under certain circumstances, each holder of a Right may instead receive other propertysecurities or assets of the Company.Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below.
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock.
In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to exercise its Rights to receive, a numberupon exercise of shares ofthe right, common stock determined in accordance with a Plan formula based on the current market value of the Company’s common stock, or other property ofacquiring company having a value equal to two times the Company.amount paid to exercise the right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power are sold or transferred.
At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments.
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date.
Stock Option and Stock Award Plans
The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock-settled SARs, restricted stock, performance units or performance shares. Stock options and stock-settled SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option or stock-settled SAR is exercisable less than one year or more than ten years after the date of each grant.
8590
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
grant, and generally no option or stock-settled SAR is exercisable less than one year or more than ten years after the date of each grant.
Transactions involving option shares for all plans are summarized as follows:
| | | | | | | | | | | | | | | | |
| | | | | | | | Weighted
| | | | |
| | | | | | | | Average
| | | | |
| | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | to Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | (In thousands) | |
|
Outstanding at September 30, 2007 | | | 7,360,041 | | | $ | 25.89 | | | | | | | | | |
Granted in 2008 | | | — | | | $ | — | | | | | | | | | |
Exercised in 2008 | | | (890,944 | ) | | $ | 23.78 | | | | | | | | | |
Forfeited in 2008 | | | (4,400 | ) | | $ | 27.97 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at September 30, 2008 | | | 6,464,697 | | | $ | 26.17 | | | | 3.11 | | | $ | 103,477 | |
| | | | | | | | | | | | | | | | |
Option shares exercisable at September 30, 2008 | | | 6,337,697 | | | $ | 25.94 | | | | 3.02 | | | $ | 102,909 | |
| | | | | | | | | | | | | | | | |
Option shares available for future grant at September 30, 2008(1) | | | 745,797 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | Weighted
| | | | |
| | | | | | | | Average
| | | | |
| | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | to Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | (In thousands) | |
|
Outstanding at September 30, 2008 | | | 6,464,697 | | | $ | 26.17 | | | | | | | | | |
Granted in 2009 | | | — | | | $ | — | | | | | | | | | |
Exercised in 2009 | | | (1,609,597 | ) | | $ | 23.15 | | | | | | | | | |
Forfeited in 2009 | | | — | | | $ | — | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at September 30, 2009 | | | 4,855,100 | | | $ | 27.18 | | | | 2.80 | | | $ | 90,463 | |
| | | | | | | | | | | | | | | | |
Option shares exercisable at September 30, 2009 | | | 4,755,100 | | | $ | 26.92 | | | | 2.71 | | | $ | 89,832 | |
| | | | | | | | | | | | | | | | |
Option shares available for future grant at September 30, 2009(1) | | | 72,797 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | |
(1) | | Including shares available for stock-settled SARs and restricted stock grants. |
Transactions involving non-performance based stock-settled SARs for all plans are summarized as follows:
| | | | | | | | | | | | | | | | |
| | | | | | | | Weighted
| | | | |
| | | | | | | | Average
| | | | |
| | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | To Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | (In thousands) | |
|
Outstanding at September 30, 2007 | | | 50,000 | | | $ | 41.20 | | | | | | | | | |
Granted in 2008 | | | — | | | $ | — | | | | | | | | | |
Exercised in 2008 | | | — | | | $ | — | | | | | | | | | |
Forfeited in 2008 | | | — | | | $ | — | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at September 30, 2008 | | | 50,000 | | | $ | 41.20 | | | | 8.45 | | | $ | 49 | |
| | | | | | | | | | | | | | | | |
Stock-settled SARs exercisable at September 30, 2008 | | | — | | | | — | | | | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | Weighted
| | | | |
| | | | | | | | Average
| | | | |
| | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | To Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | (In thousands) | |
|
Outstanding at September 30, 2008 | | | 50,000 | | | $ | 41.20 | | | | | | | | | |
Granted in 2009 | | | — | | | $ | — | | | | | | | | | |
Exercised in 2009 | | | — | | | $ | — | | | | | | | | | |
Forfeited in 2009 | | | — | | | $ | — | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at September 30, 2009 | | | 50,000 | | | $ | 41.20 | | | | 7.45 | | | $ | 231 | |
| | | | | | | | | | | | | | | | |
Stock-settled SARs exercisable at September 30, 2009 | | | — | | | | — | | | | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
8691
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Transactions involving performance based stock-settled SARs for all plans are summarized as follows:
| | | | | | | | | | | | | | | | |
| | | | | | | | Weighted
| | | | |
| | | | | | | | Average
| | | | |
| | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | To Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | (In thousands) | |
|
Outstanding at September 30, 2007 | | | — | | | $ | — | | | | | | | | | |
Granted in 2008 | | | 321,000 | | | $ | 48.46 | | | | | | | | | |
Exercised in 2008 | | | — | | | $ | — | | | | | | | | | |
Forfeited in 2008 | | | (6,000 | ) | | $ | 58.99 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at September 30, 2008 | | | 315,000 | | | $ | 48.26 | | | | 9.42 | | | $ | (1,914 | ) |
| | | | | | | | | | | | | | | | |
Stock-settled SARs exercisable at September 30, 2008 | | | — | | | | — | | | | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | Weighted
| | | | |
| | | | | | | | Average
| | | | |
| | Number of
| | | | | | Remaining
| | | Aggregate
| |
| | Shares Subject
| | | Weighted Average
| | | Contractual
| | | Intrinsic
| |
| | To Option | | | Exercise Price | | | Life (Years) | | | Value | |
| | | | | | | | | | | (In thousands) | |
|
Outstanding at September 30, 2008 | | | 315,000 | | | $ | 48.26 | | | | | | | | | |
Granted in 2009 | | | 610,000 | | | $ | 29.88 | | | | | | | | | |
Exercised in 2009 | | | — | | | $ | — | | | | | | | | | |
Forfeited in 2009 | | | — | | | $ | — | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Outstanding at September 30, 2009 | | | 925,000 | | | $ | 36.14 | | | | 8.96 | | | $ | 8,947 | |
| | | | | | | | | | | | | | | | |
Stock-settled SARs exercisable at September 30, 2009 | | | 96,984 | | | $ | 47.37 | | | | 8.40 | | | $ | — | |
| | | | | | | | | | | | | | | | |
Restricted Share Awards
Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective.
Transactions involving restricted shares for all plans are summarized as follows:
| | | | | | | | |
| | Number of
| | | Weighted Average
| |
| | Restricted
| | | Fair Value per
| |
| | Share Awards | | | Award | |
|
Restricted Share Awards Outstanding at September 30, 2007 | | | 36,328 | | | $ | 38.16 | |
Granted in 2008 | | | 25,000 | | | $ | 48.41 | |
Vested in 2008 | | | (2,500 | ) | | $ | 34.94 | |
Forfeited in 2008 | | | — | | | $ | — | |
| | | | | | | | |
Restricted Share Awards Outstanding at September 30, 2008 | | | 58,828 | | | $ | 42.65 | |
| | | | | | | | |
| | | | | | | | |
| | Number of
| | | Weighted Average
| |
| | Restricted
| | | Fair Value per
| |
| | Share Awards | | | Award | |
|
Restricted Share Awards Outstanding at September 30, 2008 | | | 58,828 | | | $ | 42.65 | |
Granted in 2009 | | | 63,000 | | | $ | 47.46 | |
Vested in 2009 | | | (3,828 | ) | | $ | 31.30 | |
Forfeited in 2009 | | | — | | | $ | — | |
| | | | | | | | |
Restricted Share Awards Outstanding at September 30, 2009 | | | 118,000 | | | $ | 46.59 | |
| | | | | | | | |
Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 20082009 will lapse as follows: 2009 — 2,500 shares; 2010 — 28,82827,500 shares; 2011 — 2,500 shares; 2012 — 5,000 shares; 2013 — 5,000 shares; 2014 — 5,000 shares; 2015 — 5,00013,000 shares; and 2016 — 5,000 shares; 2018 — 35,000 shares; and 2021 — 20,000 shares.
Redeemable Preferred Stock
As of September 30, 2007,2009, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
8792
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Long-Term Debt
The outstanding long-term debt is as follows:
| | | | | | | | | | | | | | | | |
| | At September 30 | | | At September 30 | |
| | 2008 | | 2007 | | | 2009 | | 2008 | |
| | (Thousands) | | | (Thousands) | |
|
Medium-Term Notes(1): | | | | | | | | | | | | | | | | |
6.0% to 7.50% due March 2009 to June 2025 | | $ | 549,000 | | | $ | 749,000 | | |
6.7% to 7.50% due November 2010 to June 2025 | | | $ | 449,000 | | | $ | 549,000 | |
Notes(1): | | | | | | | | | | | | | | | | |
5.25% to 6.5% due March 2013 to September 2022(2) | | | 550,000 | | | | 250,000 | | |
| | | | | | |
| | | 1,099,000 | | | | 999,000 | | |
| | | | | | |
Other Notes: | | | | | | | | | |
Unsecured | | | — | | | | 24 | | |
5.25% to 8.75% due March 2013 to May 2019 | | | | 800,000 | | | | 550,000 | |
| | | | | | | | | | |
Total Long-Term Debt | | | 1,099,000 | | | | 999,024 | | | | 1,249,000 | | | | 1,099,000 | |
Less Current Portion | | | 100,000 | | | | 200,024 | | | | — | | | | 100,000 | |
| | | | | | | | | | |
| | $ | 999,000 | | | $ | 799,000 | | | $ | 1,249,000 | | | $ | 999,000 | |
| | | | | | | | | | |
| | |
(1) | | The medium-term notesMedium-Term Notes and notesNotes are unsecured. |
|
(2) | | In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private placement exempt from registration under the Securities Act of 1933. The notes have a term of 10 years, with a maturity date in April 2018. The holders of the notes may require the Company to repurchase their notes in the event of a change in control at a price equal to 101% of the principal amount. In addition, the Company is required to either offer to exchange the notes for substantially similar notes registered under the Securities Act of 1933 or, in certain circumstances, register the resale of the notes. The Company used $200.0 million of the proceeds from the sale of the notes to refund $200.0 million of 6.303% medium-term notes that subsequently matured on May 27, 2008. |
In April 2009, the Company issued $250.0 million of 8.75% notes due in May 2019. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $247.8 million. These notes were registered under the Securities Act of 1933. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including to replenish cash that was used to pay the $100 million due at the maturity of the Company’s 6.0% medium-term notes on March 1, 2009.
In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private placement exempt from registration under the Securities Act of 1933. In February 2009, the Company exchanged the notes for economically identical notes registered under the Securities Act of 1933. The notes have a term of 10 years, with a maturity date in April 2018. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. The Company used $200.0 million of the proceeds of the issuance to refund $200.0 million of 6.303% medium-term notes that matured on May 27, 2008.
As of September 30, 2008,2009, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $100.0 million in 2009, zero in 2010, $200.0 million in 2011, $150.0 million in 2012, $250.0 million in 2013, zero in 2014, and $399.0$649.0 million thereafter.
Short-Term Borrowings
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These uncommitted credit lines, which aggregate to $420.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed, or replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million that extends through September 30, 2010.
At September 30, 20082009 and 2007,2008, the Company had no outstanding short-term notes payable to banks or commercial paper.
8893
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Debt Restrictions
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September 30, 2010. At September 30, 2008,2009, the Company’s debt to capitalization ratio (as calculated under the facility) was .41..44. The constraints specified in the committed credit facility would permit an additional $1.88$1.7 billion in short-termand/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.
Under the Company’s existing indenture covenants, at September 30, 2008,2009, the Company would have been permitted to issue up to a maximum of $1.3 billion$435.0 million in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. If the Company were to experience another impairment of oil and gas properties in the future, it is possible that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness. This would not preclude the Company from issuing new indebtedness to replace maturing debt.
The Company’s 1974 indenture pursuant to which $199.0$99.0 million (or 18%7.9%) of the Company’s long-term debt (as of September 30, 2008)2009) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest oron any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2008,2009, the Company had no debt outstanding under the committed credit facility.
| |
Note F — | Financial Instruments |
Note F — Fair Value Measurements
Beginning in fiscal 2009, the Company adopted the FASB authoritative guidance regarding fair value measurements which establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The adoption of this authoritative guidance regarding fair value measurements has not had a significant impact on the consolidated financial statements.
94
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
| | | | | | | | | | | | | | | | |
| | At fair Value as of September 30, 2009 | |
Recurring Fair Value Measures | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | (Dollars in thousands) | |
|
Assets: | | | | | | | | | | | | | | | | |
Cash Equivalents | | $ | 390,462 | | | $ | — | | | $ | — | | | $ | 390,462 | |
Derivative Financial Instruments | | | 5,312 | | | | 12,536 | | | | 26,969 | | | | 44,817 | |
Other Investments | | | 24,276 | | | | — | | | | — | | | | 24,276 | |
Hedging Collateral Deposits | | | 848 | | | | — | | | | — | | | | 848 | |
| | | | | | | | | | | | | | | | |
Total | | $ | 420,898 | | | $ | 12,536 | | | $ | 26,969 | | | $ | 460,403 | |
| | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | |
Derivative Financial Instruments | | $ | — | | | $ | 2,148 | | | $ | — | | | $ | 2,148 | |
| | | | | | | | | | | | | | | | |
Total | | $ | — | | | $ | 2,148 | | | $ | — | | | $ | 2,148 | |
| | | | | | | | | | | | | | | | |
Cash Equivalents
The cash equivalents reported in Level 1 consist of SEC registered money market mutual funds.
Derivative Financial Instruments
The derivative financial instruments reported in Level 1 consist of NYMEX futures contracts. The hedging collateral deposits associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in the Company’s Exploration and Production segment and natural gas swap agreements used in the Energy Marketing segment. The fair value of these natural gas swap agreements is based on an internal model that uses observable inputs. The fair market value of the price swap agreements reported in Level 2 as assets has been reduced by $0.2 million based on an assessment of counterparty credit risk. The derivative financial instruments reported in Level 3 consist of all of the Exploration and Production segment’s crude oil swap agreements. The fair value of the crude oil swap agreements is based on an internal model that uses both observable and unobservable inputs. The fair market value of the price swap agreements reported in Level 3 as assets has been reduced by $0.7 million based on an assessment of counterparty credit risk. The fair market value of the price swap agreements reported in Level 2 as liabilities has been reduced by less than $0.1 million based on an assessment of the Company’s credit risk. This credit reserve, as well as the credit reserve established for the Level 2 and Level 3 swap agreement assets, was determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.
Other Investments
The other investments reported in Level 1 consist of publicly traded equity securities and a publicly traded balanced equity mutual fund.
The table listed below provides a reconciliation of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3.
95
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fair ValuesValue Measurements Using Unobservable Inputs (Level 3)
| | | | | | | | | | | | | | | | | | | | |
| | | | | Total Gains/Losses—
| | | | | | | |
| | | | | Realized and Unrealized | | | | | | | |
| | | | | | | | Included in Other
| | | Transfer
| | | | |
| | October 1,
| | | Included in
| | | Comprehensive Income
| | | In/(Out) of
| | | September 30,
| |
| | 2008 | | | Earnings | | | (Loss) | | | Level 3 | | | 2009 | |
| | (Dollars in thousands) | |
|
Assets: | | | | | | | | | | | | | | | | | | | | |
Derivative Financial Instruments | | $ | 7,110 | | | $ | (47,076 | )(1) | | $ | 75,077 | | | $ | (8,142 | )(2) | | $ | 26,969 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 7,110 | | | $ | (47,076 | ) | | $ | 75,077 | | | $ | (8,142 | ) | | $ | 26,969 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
Derivative Financial Instruments | | $ | (777 | ) | | $ | (12,104 | )(1) | | $ | 12,070 | | | $ | 811 | (2) | | $ | — | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | (777 | ) | | $ | (12,104 | ) | | $ | 12,070 | | | $ | 811 | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | |
| | |
(1) | | Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2009. |
|
(2) | | These transfers occurred because the Company was able to obtain and utilize forward-looking, observable basis differential information for its hedges on southern California natural gas production. |
Note G — Financial Instruments
Long-Term Debt
TheAt September 30, 2009, the fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit risk in determining the yield, and subsequently, the fair market value of the debt. At September 30, 2008, the fair market value of the Company’s long-term debt is estimatedwas determined based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
| | | | | | | | | | | | | | | | |
| | At September 30 | |
| | 2008 Carrying
| | | 2008 Fair
| | | 2007 Carrying
| | | 2007 Fair
| |
| | Amount | | | Value | | | Amount | | | Value | |
| | (Thousands) | |
|
Long-Term Debt | | $ | 1,099,000 | | | $ | 1,027,098 | | | $ | 999,024 | | | $ | 1,024,417 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | At September 30 | |
| | 2009 Carrying
| | | 2009 Fair
| | | 2008 Carrying
| | | 2008 Fair
| |
| | Amount | | | Value | | | Amount | | | Value | |
| | (Thousands) | |
|
Long-Term Debt | | $ | 1,249,000 | | | $ | 1,347,368 | | | $ | 1,099,000 | | | $ | 1,027,098 | |
| | | | | | | | | | | | | | | | |
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value.
Temporary cash investments, notes payable to banks and commercial paper are stated at cost, which approximates their fair value due to the short-term maturities of those financial instruments.Other Investments in life
89
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other Investments
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $53.6$54.2 million and $54.7$53.6 million at September 30, 20082009 and 2007,2008, respectively. The fair value of the equity mutual fund was $12.4$15.8 million and $14.7$12.4 million at September 30, 20082009 and 2007, 2008,
96
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
respectively. The gross unrealized loss on this equity mutual fund was $(1.0)$1.0 million at September 30, 2008. The equity mutual fund was in a gross unrealized gain position of $2.2 million at2009 and September 30, 2007.2008. Although this investment has been in an unrealized loss position for over twelve months, management has the intent and ability to hold the investment for a sufficient period of time for the asset to recover in value. As such, management does not consider this investment to be other than temporarily impaired. The fair value of the stock of an insurance company was $14.5$8.3 million and $16.3$14.5 million at September 30, 20082009 and 2007,2008, respectively. The gross unrealized gain on this stock was $12.1$5.9 million and $13.8$12.1 million at September 30, 20082009 and 2007,2008, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses a variety ofis exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative financial instruments to manage a portion of the marketis commodity price risk associated with the fluctuations in the price of natural gasExploration and crude oil. These instruments include priceProduction and Energy Marketing segments. The Company enters into futures contracts andover-the-counter swap agreements no cost collars and futures contracts.
Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed price and a variable price as specified by the agreement. The variable price is either a crude oil or natural gas price quoted on the NYMEX or a quoted natural gas price in various national natural gas publications. The majority of these derivative financial instruments are accounted for as cash flow hedges and are used to lock in a price for the anticipated sale of natural gas and crude oil productionto manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, and withdrawal of gas from storage to meet customer demand. The duration of the Company’s hedges do not typically exceed 3 years and the majority of the positions settle within one year.
The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheet at September 30, 2009 as shown in the table below.
| | | | | | | | | | | | |
| | Fair Values of Derivative Instruments
|
| | (Dollar Amounts in Thousands) |
| | Asset Derivatives
| | Liability Derivatives
|
Derivatives
| | September 30, 2009 | | September 30, 2009 |
Designated as
| | Consolidated
| | | | Consolidated
| | |
Hedging
| | Balance Sheet
| | | | Balance Sheet
| | |
Instruments | | Location | | Fair Value | | Location | | Fair Value |
|
Commodity Contracts | | Fair Value of Derivative Financial Instruments | | $ | 44,817 | | | Fair Value of Derivative Financial Instruments | | $ | 2,148 | |
The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheet at September 30, 2009.
| | | | |
Derivatives
| | Fair Values of Derivative Instruments
|
Designated as
| | (Dollar Amounts in Thousands) |
Hedging
| | Gross Asset Derivatives
| | Gross Liability Derivatives
|
Instruments | | September 30, 2009 | | September 30, 2009 |
|
| | Fair Value | | Fair Value |
Commodity Contracts | | $63,601 | | $20,932 |
Cash Flow Hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
As of September 30, 2009, the Company’s Exploration and Production segment andhad the All Other category. The Energy Marketing segment accounts for thesefollowing commodity derivative financial instruments as fair value hedges and uses themcontracts (swaps) outstanding to hedge against falling prices, a risk to which they are exposed on their fixed price gas purchase commitments. The Energy Marketing segment also uses these derivative financial instruments to hedge against rising prices, a risk to which they are exposed on their fixed priceforecasted sales commitments. At September 30, 2008,(where the Company had natural gas price swap agreements covering a notional amount of 15.1 Bcf extending through 2011 at a weighted average fixed rate of $9.69 per Mcf. Of this amount, 0.9 Bcf is accounted for as fair value hedges at a weighted average fixed rate of $9.64 per Mcf. The remaining 14.2 Bcf are accounted for as cash flow hedges at a weighted average fixed rate of $9.69 per Mcf. At September 30, 2008, the Company would have received a net $20.3 million to terminate the price swap agreements. The Company also had crude oil price swap agreements covering a notional amount of 1,920,000 bbls extending through 2011 at a weighted average fixed rate of $90.50 per bbl. At September 30, 2008, the Company would have had to pay a net $0.8 million to terminate the price swap agreements. The Energy Marketing segment also used natural gas swaps to hedge basis risk on their fixed price purchase commitments. At September 30, 2008, the Company had natural gas swap agreements covering 1.4 Bcf at a weighted average fixed rate of $0.47 per Mcf. These are treated as fair value hedges and the Company would have had to pay $0.2 million at September 30, 2008 to terminate the agreements.
At September 30, 2008, the Company had long (purchased) futures contracts covering 9.1 Bcf of gas extending through 2012 at a weighted average contract price of $9.24 per Mcf. They are accounted for as fair value hedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with residential, commercial and industrial customers. The Company would have had to pay $9.9 million to terminate these futures contracts at September 30, 2008.uses short
9097
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Atpositions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):
| | |
Commodity | | Units |
|
Natural Gas | | 36.9 Bcf (all short positions) |
Crude Oil | | 2,688,000 Bbls (all short positions) |
As of September 30, 2008,2009, the Company’s Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):
| | |
Commodity | | Units |
|
Natural Gas | | 6.4 Bcf (6.2 Bcf short positions (forecasted storage withdrawals) and 0.2 Bcf long positions (forecasted storage injections)) |
As of September 30, 2009, the Company’s Exploration and Production segment had short (sold) futures contracts covering 6.7 Bcf$36.2 million ($21.3 million after tax) of gas extending through 2010 at a weighted average contractgains included in the accumulated other comprehensive income balance. It is expected that $36.4 million ($21.4 million after tax) of these gains will be reclassified into income within the next 12 months as the sales of the underlying commodities are expected to occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note A includes both the Exploration and Production and Energy Marketing segments).
As of September 30, 2009, the Company’s Energy Marketing segment had $4.7 million ($2.8 million after tax) of losses included in the accumulated other comprehensive income (loss) balance. It is expected that $4.7 million ($2.8 million after tax) of these losses will be reclassified into income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note A includes both the Exploration and Production and Energy Marketing segments).
98
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | |
| | The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
|
| | Year Ended September 30, 2009 (Dollar Amounts in Thousands) |
| | Amount of
| | | | Amount of
| | | | |
| | Derivative Gain or
| | | | Derivative Gain or
| | | | |
| | (Loss) Recognized
| | Location of
| | (Loss) Reclassified
| | | | |
| | in Other
| | Derivative Gain or
| | from Accumulated
| | | | Derivative Gain or
|
| | Comprehensive
| | (Loss) Reclassified
| | Other Comprehensive
| | Location of
| | (Loss) Recognized
|
| | Income (Loss) on
| | from Accumulated
| | Income (Loss) on
| | Derivative Gain or
| | in the Consolidated
|
| | the Consolidated
| | Other Comprehensive
| | the Consolidated
| | (Loss) Recognized
| | Statement of Income
|
| | Statement of
| | Income (Loss) on
| | Balance Sheet into
| | in the Consolidated
| | (Ineffective
|
| | Comprehensive
| | the Consolidated
| | the Consolidated
| | Statement of Income
| | Portion and Amount
|
| | Income (Effective
| | Balance Sheet into
| | Statement of Income
| | (Ineffective
| | Excluded from
|
Derivatives in Cash
| | Portion) for the
| | the Consolidated
| | (Effective Portion)
| | Portion and Amount
| | Effectiveness Testing)
|
Flow Hedging
| | Year Ended
| | Statement of Income
| | for the Year Ended
| | Excluded from
| | for the Year Ended
|
Relationships | | September 30, 2009 | | (Effective Portion) | | September 30, 2009 | | Effectiveness Testing) | | September 30, 2009 |
|
Commodity Contracts — Exploration & Production segment | | $ | 110,883 | | | Operating Revenue | | $ | 91,808 | | | Operating Revenue | | $ | — | |
Commodity Contracts — Energy Marketing segment | | $ | 7,492 | | | Purchased Gas | | $ | 21,301 | | | Operating Revenue | | $ | — | |
Commodity Contracts — Pipeline & Storage segment(1) | | $ | 652 | | | Operating Revenue | | $ | 1,952 | | | Operating Revenue | | $ | — | |
Commodity Contracts — All Other(1) | | $ | 183 | | | Purchased Gas | | $ | (681 | ) | | Purchased Gas | | $ | — | |
| | | | | | | | | | | | | | | | |
Total | | $ | 119,210 | | | | | $ | 114,380 | | | | | $ | — | |
| | | | | | | | | | | | | | | | |
| | |
(1) | | There were no open hedging positions at September 30, 2009. As such there is no mention of these positions in the preceding sections of this footnote. |
Fair value hedges
The Company’s Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price of $11.02 per Mcf. Of this amount, 3.5 Bcf is accounted for as cash flow hedges as these contracts relatesales commitments, fixed price purchase commitments, and commitments related to the anticipated saleinjection and withdrawal of storage gas. In order to hedge fixed price sales commitments, the Company enters into long positions to mitigate the risk that after the Company enters into fixed price sales agreements with its customers, the price of natural gas byincreases (thereby passing up the opportunity for higher operating revenue). With fixed price purchase commitments, the Company enters into short positions to mitigate the risk that after the Company locks into fixed price purchase deals with its suppliers, the price of natural gas decreases (thereby passing up the opportunity for lower purchased gas expense). Fair value hedges related to the injection and withdrawal of storage gas impact purchased gas expense. As of September 30, 2009, the Company’s Energy Marketing segment. The remaining 3.2 Bcf is accounted for assegment had fair value hedges used to hedge against falling prices on theircovering approximately 13.0 Bcf (11.7 Bcf of fixed price sales commitments (all long positions), 0.9 Bcf of fixed price purchase commitments (all short positions), and 0.4 Bcf of commitments related to the withdrawal of storage gas purchasing commitments(all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, against decreasesthe gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in natural gas prices associated with the eventual sale of gas in storage. The Company would have received $18.6 million to terminate these futures contracts at September 30, 2008.current earnings, as shown below.
| | | | | | | | |
Consolidated Statement of Income | | Gain/(Loss) on Derivative | | Gain/(Loss) on Commitment |
|
Operating Revenues | | $ | 5,242,000 | | | $ | (5,242,000 | ) |
Purchased Gas | | $ | (8,252,000 | ) | | $ | 8,252,000 | |
99
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | |
| | | | Amount of
|
| | | | Derivative Gain or
|
| | Location of
| | (Loss) Recognized
|
| | Derivative Gain or
| | in the Consolidated
|
| | (Loss) Recognized
| | Statement of Income
|
| | in the Consolidated
| | for the Year Ended
|
Derivatives in Fair Value Hedging Relationships | | Statement of Income | | September 30, 2009 |
| | | | (In thousands) |
|
Commodity Contracts — Energy Marketing segment(1) | | | Operating Revenues | | | $ | 5,242 | |
Commodity Contracts — Energy Marketing segment(2) | | | Purchased Gas | | | $ | 11 | |
Commodity Contracts — Energy Marketing segment(3) | | | Purchased Gas | | | $ | (8,263 | ) |
| | | | | | | | |
| | | | | | $ | (3,010 | ) |
| | | | | | | | |
| | |
(1) | | Represents hedging of fixed price sales commitments of natural gas. |
|
(2) | | Represents hedging of fixed price purchase commitments of natural gas. |
|
(3) | | Represents hedging of storage withdrawal commitments of natural gas. |
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on an ongoinga quarterly basis monitors counterparty credit exposure. Management has obtained guarantees from manyThe majority of the parent companies of the respectiveCompany’s counterparties to its derivativeare financial instruments.institutions and energy traders. The Company hasover-the-counter swap positions with ten counterparties. At September 30, 2008,2009, the Company had eleven counterparties for its over the counter derivative financial instruments and no individual counterparty represented greater than 42% of total credit risk (measured as volumes hedged by an individual counterparty as a percentagethat were in gain positions with eight of the Company’s total over the counter volumes hedged).counterparties. The Company recorded a $0.6had derivative financial instruments that were in loss positions with the other two counterparties. The Company had $26.6 million reduction to the fair market value of its derivative contractscredit exposure with one counterparty (which is rated A1 (Moody’s Investor Service), A (S&P), and A+ (Fitch Ratings Service) as of September 30, 2009). On average for those financial instruments that arewere in a gain position, basedthe Company had $1.8 million of credit exposure per counterparty with the other seven counterparties that were in a gain position. The Company had not received any collateral from the counterparties at September 30, 2009 since the Company’s gain position on its assessmentsuch derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.
As of counterparty credit risk. This credit reserve was determined by applying default probabilitiesSeptember 30, 2009, eight of the ten counterparties to the anticipated cash flows thatCompany’s outstanding derivative instrument contracts (specifically theover-the-counter swaps) had a common credit-risk-related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (the lower of the S&P or Moody’s Debt Rating), the available credit extended to the Company is expecting fromwould either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position and the Company’s credit rating declined, then additional hedging collateral deposits would be required. At September 30, 2009, these credit-risk related contingency features were not triggered since the Company had assets of $37.9 million related to derivative financial instruments with the eight counterparties.
| |
Note G — | Retirement Plan and Other Post-Retirement Benefits |
For its exchange traded futures contracts, which are in an asset position, the Company had paid $0.8 million in hedging collateral as of September 30, 2009. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions (i.e. those positions that have been settled for cash) and margin requirements. (This is discussed in Note A under Hedging Collateral Deposits.)
100
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Note H — Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers approximately 65%a majority of the full-time employees of the Company. The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Employees hired after June 30, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account benefit have been $0.6 million through September 30, 2008 (with $0.2were $0.4 million, $0.2 million and $0.1$0.2 million of costs occurring infor the years ended September 30, 2009, 2008 and 2007, and 2006, respectively).respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans were $4.0$4.1 million, $4.1$4.0 million, and $4.1 million for the years ended September 30, 2009, 2008 2007 and 2006,2007, respectively.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations. Retirement Plan, VEBA trust and 401(h) account assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds.
91
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The expected return on plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is equal to market value as of the measurement date.
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30, 2009, June 30, 2008 and June 30, 2007, for fiscal year 2009, 2008 and 2006,2007, respectively.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | | Other Post-Retirement Benefits | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| | (Thousands) | |
|
Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation at Beginning of Period | | $ | 742,519 | | | $ | 732,207 | | | $ | 825,204 | | | $ | 444,545 | | | $ | 445,931 | | | $ | 546,273 | |
Service Cost | | | 12,597 | | | | 12,898 | | | | 16,416 | | | | 5,104 | | | | 5,614 | | | | 8,029 | |
Interest Cost | | | 44,949 | | | | 44,350 | | | | 40,196 | | | | 27,081 | | | | 27,198 | | | | 26,804 | |
Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 1,990 | | | | 1,566 | | | | 1,559 | |
Retiree Drug Subsidy Receipts | | | — | | | | — | | | | — | | | | 1,532 | | | | 1,325 | | | | — | |
Amendments(1) | | | — | | | | — | | | | — | | | | (31,874 | ) | | | — | | | | — | |
Actuarial (Gain) Loss | | | (34,189 | ) | | | (2,986 | ) | | | (108,112 | ) | | | (14,390 | ) | | | (14,450 | ) | | | (115,052 | ) |
Benefits Paid | | | (46,817 | ) | | | (43,950 | ) | | | (41,497 | ) | | | (22,443 | ) | | | (22,639 | ) | | | (21,682 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation at End of Period | | $ | 719,059 | | | $ | 742,519 | | | $ | 732,207 | | | $ | 411,545 | | | $ | 444,545 | | | $ | 445,931 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Assets at Beginning of Period | | $ | 765,144 | | | $ | 664,521 | | | $ | 616,462 | | | $ | 412,371 | | | $ | 325,624 | | | $ | 271,636 | |
Actual Return on Plan Assets | | | (39,206 | ) | | | 119,662 | | | | 68,649 | | | | (43,478 | ) | | | 65,552 | | | | 34,785 | |
Employer Contributions | | | 3,817 | | | | 16,488 | | | | 20,907 | | | | 29,200 | | | | 42,268 | | | | 39,326 | |
Employer Contributions During Period from Measurement Date to Fiscal Year End | | | 12,151 | | | | 8,423 | | | | — | | | | — | | | | — | | | | — | |
Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 1,990 | | | | 1,566 | | | | 1,559 | |
Benefits Paid | | | (46,817 | ) | | | (43,950 | ) | | | (41,497 | ) | | | (22,443 | ) | | | (22,639 | ) | | | (21,682 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Assets at End of Period | | $ | 695,089 | | | $ | 765,144 | | | $ | 664,521 | | | $ | 377,640 | | | $ | 412,371 | | | $ | 325,624 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Reconciliation of Funded Status | | | | | | | | | | | | | | | | | | | | | | | | |
Funded Status | | $ | (23,970 | ) | | $ | 22,625 | | | $ | (67,686 | ) | | $ | (33,905 | ) | | $ | (32,174 | ) | | $ | (120,307 | ) |
Unrecognized Net Actuarial Loss | | | — | | | | — | | | | 107,626 | | | | — | | | | — | | | | 54,487 | |
Unrecognized Transition Obligation | | | — | | | | — | | | | — | | | | — | | | | — | | | | 49,890 | |
Unrecognized Prior Service Cost | | | — | | | | — | | | | 7,185 | | | | — | | | | — | | | | 12 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net Amount Recognized at End of Period | | $ | (23,970 | ) | | $ | 22,625 | | | $ | 47,125 | | | $ | (33,905 | ) | | $ | (32,174 | ) | | $ | (15,918 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
92101
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | | Other Post-Retirement Benefits | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| | (Thousands) | |
|
Amounts Recognized in the Balance Sheets Consist of: | | | | | | | | | | | | | | | | | | | | | | | | |
Accrued Benefit Liability | | $ | (23,970 | ) | | $ | — | | | $ | — | | | $ | (54,939 | ) | | $ | (70,555 | ) | | $ | (32,918 | ) |
Prepaid Benefit Cost | | | — | | | | 22,625 | | | | 47,125 | | | | 21,034 | | | | 38,381 | | | | 17,000 | |
Intangible Assets | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
Accumulated Other Comprehensive Loss from Additional Minimum Pension Liability Adjustment (Pre-Tax) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net Amount Recognized at End of Period | | $ | (23,970 | ) | | $ | 22,625 | | | $ | 47,125 | | | $ | (33,905 | ) | | $ | (32,174 | ) | | $ | (15,918 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
Discount Rate | | | 6.75 | % | | | 6.25 | % | | | 6.25 | % | | | 6.75 | % | | | 6.25 | % | | | 6.25 | % |
Expected Return on Plan Assets | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % |
Rate of Compensation Increase | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % |
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | | | | | | | |
Service Cost | | $ | 12,598 | | | $ | 12,898 | | | $ | 16,416 | | | $ | 5,104 | | | $ | 5,614 | | | $ | 8,029 | |
Interest Cost | | | 44,949 | | | | 44,350 | | | | 40,196 | | | | 27,081 | | | | 27,198 | | | | 26,804 | |
Expected Return on Plan Assets | | | (55,000 | ) | | | (51,235 | ) | | | (49,943 | ) | | | (33,715 | ) | | | (26,960 | ) | | | (22,302 | ) |
Amortization of Prior Service Cost | | | 808 | | | | 882 | | | | 957 | | | | 4 | | | | 4 | | | | 4 | |
Amortization of Transition Amount | | | — | | | | — | | | | — | | | | 7,127 | | | | 7,127 | | | | 7,127 | |
Recognition of Actuarial Loss(2) | | | 11,063 | | | | 13,528 | | | | 23,108 | | | | 2,927 | | | | 8,214 | | | | 23,402 | |
Net Amortization and Deferral for Regulatory Purposes | | | 6,008 | | | | 1,211 | | | | (6,409 | ) | | | 22,264 | | | | 16,220 | | | | (11,084 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net Periodic Benefit Cost | | $ | 20,426 | | | $ | 21,634 | | | $ | 24,325 | | | $ | 30,792 | | | $ | 37,417 | | | $ | 31,980 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change In Additional Minimum Liability Recognition | | $ | — | | | $ | — | | | $ | (165,914 | ) | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to Adoption of SFAS 158 | | | NA | | | $ | 11,256 | | | | NA | | | | NA | | | $ | 778 | | | | NA | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
Discount Rate | | | 6.25 | % | | | 6.25 | % | | | 5.00 | % | | | 6.25 | % | | | 6.25 | % | | | 5.00 | % |
Expected Return on Plan Assets | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % |
Rate of Compensation Increase | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | | Other Post-Retirement Benefits | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | | | 2007 | |
| | (Thousands) | |
|
Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation at Beginning of Period | | $ | 719,059 | | | $ | 742,519 | | | $ | 732,207 | | | $ | 411,545 | | | $ | 444,545 | | | $ | 445,931 | |
Service Cost | | | 10,913 | | | | 12,597 | | | | 12,898 | | | | 3,801 | | | | 5,104 | | | | 5,614 | |
Interest Cost | | | 46,836 | | | | 44,949 | | | | 44,350 | | | | 27,499 | | | | 27,081 | | | | 27,198 | |
Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 2,185 | | | | 1,990 | | | | 1,566 | |
Retiree Drug Subsidy Receipts | | | — | | | | — | | | | — | | | | 1,427 | | | | 1,532 | | | | 1,325 | |
Amendments(1) | | | — | | | | — | | | | — | | | | (10,765 | ) | | | (31,874 | ) | | | — | |
Actuarial (Gain) Loss | | | 102,430 | | | | (34,189 | ) | | | (2,986 | ) | | | 55,776 | | | | (14,390 | ) | | | (14,450 | ) |
Adjustment for Change in Measurement Date | | | 14,438 | | | | — | | | | — | | | | 7,825 | | | | — | | | | — | |
Benefits Paid | | | (62,180 | ) | | | (46,817 | ) | | | (43,950 | ) | | | (31,998 | ) | | | (22,443 | ) | | | (22,639 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Benefit Obligation at End of Period | | $ | 831,496 | | | $ | 719,059 | | | $ | 742,519 | | | $ | 467,295 | | | $ | 411,545 | | | $ | 444,545 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Assets at Beginning of Period | | $ | 695,089 | | | $ | 765,144 | | | $ | 664,521 | | | $ | 377,640 | | | $ | 412,371 | | | $ | 325,624 | |
Actual Return on Plan Assets | | | (99,511 | ) | | | (39,206 | ) | | | 119,662 | | | | (62,368 | ) | | | (43,478 | ) | | | 65,552 | |
Employer Contributions | | | 15,993 | | | | 3,817 | | | | 16,488 | | | | 25,659 | | | | 29,200 | | | | 42,268 | |
Employer Contributions During Period from Measurement Date to Fiscal Year End | | | N/A | | | | 12,151 | | | | 8,423 | | | | N/A | | | | — | | | | — | |
Plan Participants’ Contributions | | | — | | | | — | | | | — | | | | 2,185 | | | | 1,990 | | | | 1,566 | |
Adjustment for Change in Measurement Date | | | 14,490 | | | | — | | | | — | | | | 7,904 | | | | — | | | | — | |
Benefits Paid | | | (62,180 | ) | | | (46,817 | ) | | | (43,950 | ) | | | (31,998 | ) | | | (22,443 | ) | | | (22,639 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Assets at End of Period | | $ | 563,881 | | | $ | 695,089 | | | $ | 765,144 | | | $ | 319,022 | | | $ | 377,640 | | | $ | 412,371 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net Amount Recognized at End of Period (Funded Status) | | $ | (267,615 | ) | | $ | (23,970 | ) | | $ | 22,625 | | | $ | (148,273 | ) | | $ | (33,905 | ) | | $ | (32,174 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Amounts Recognized in the Balance Sheets Consist of: | | | | | | | | | | | | | | | | | | | | | | | | |
Accrued Benefit Liability | | $ | (267,615 | ) | | $ | (23,970 | ) | | $ | — | | | $ | (148,273 | ) | | $ | (54,939 | ) | | $ | (70,555 | ) |
Prepaid Benefit Cost | | | — | | | | — | | | | 22,625 | | | | — | | | | 21,034 | | | | 38,381 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net Amount Recognized at End of Period | | $ | (267,615 | ) | | $ | (23,970 | ) | | $ | 22,625 | | | $ | (148,273 | ) | | $ | (33,905 | ) | | $ | (32,174 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Accumulated Benefit Obligation | | $ | 758,658 | | | $ | 659,004 | | | $ | 672,340 | | | | N/A | | | | N/A | | | | N/A | |
| | | | | | | | | | | | | | | | | | | | | | | | |
93102
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | | Other Post-Retirement Benefits | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | | | 2007 | |
| | (Thousands) | |
|
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
Discount Rate | | | 5.50 | % | | | 6.75 | % | | | 6.25 | % | | | 5.50 | % | | | 6.75 | % | | | 6.25 | % |
Expected Return on Plan Assets | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % |
Rate of Compensation Increase | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % |
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | | | | | | | |
Service Cost | | $ | 10,913 | | | $ | 12,597 | | | $ | 12,898 | | | $ | 3,801 | | | $ | 5,104 | | | $ | 5,614 | |
Interest Cost | | | 46,836 | | | | 44,949 | | | | 44,350 | | | | 27,499 | | | | 27,081 | | | | 27,198 | |
Expected Return on Plan Assets | | | (57,958 | ) | | | (55,000 | ) | | | (51,235 | ) | | | (31,615 | ) | | | (33,715 | ) | | | (26,960 | ) |
Amortization of Prior Service Cost | | | 732 | | | | 808 | | | | 882 | | | | (1,074 | ) | | | 4 | | | | 4 | |
Amortization of Transition Amount | | | — | | | | — | | | | — | | | | 2,265 | | | | 7,127 | | | | 7,127 | |
Recognition of Actuarial Loss(2) | | | 5,676 | | | | 11,064 | | | | 13,528 | | | | 9,271 | | | | 2,927 | | | | 8,214 | |
Net Amortization and Deferral for Regulatory Purposes | | | 12,817 | | | | 6,008 | | | | 1,211 | | | | 18,037 | | | | 22,264 | | | | 16,220 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net Periodic Benefit Cost | | $ | 19,016 | | | $ | 20,426 | | | $ | 21,634 | | | $ | 28,184 | | | $ | 30,792 | | | $ | 37,417 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Accumulated Other Comprehensive Loss (Pre-Tax) Attributable to Recognition of Funded Status of Benefit Plans | | | N/A | | | | N/A | | | $ | 11,256 | | | | N/A | | | | N/A | | | $ | 778 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | | | | | | | | | | | | | | | | | | | | | | | | |
Discount Rate | | | 6.75 | % | | | 6.25 | % | | | 6.25 | % | | | 6.75 | % | | | 6.25 | % | | | 6.25 | % |
Expected Return on Plan Assets | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % | | | 8.25 | % |
Rate of Compensation Increase | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % | | | 5.00 | % |
| | |
(1) | | In Fiscalfiscal 2008 and 2009, the Company passed an amendment,amendments, for most of the subsidiaries, which increased the participant contributions for active employees at the time of the amendment. This decreased the benefit obligation. |
|
(2) | | Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach. |
The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under SFAS 87 and SFAS 106the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets)assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
In September 2006, the FASB issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of Company’s fiscal year, with limited exceptions. Under SFAS 158, certain previously unrecognized actuarial gains and losses, previously unrecognized prior service costs, and a previously unrecognized transition obligation are required to be recognized. These amounts were not required to be recorded on the Company’s Consolidated Balance Sheet before the adoption of SFAS 158, but were instead amortized over a period of time. In accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and implemented the disclosure requirements of SFAS 158 as of September 30, 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. Currently, the Company measures its plan assets and benefit obligations using a June 30th measurement date. The incremental effects of adopting the provisions of SFAS 158 on the Company’s Consolidated Balance Sheet at September 30, 2007 are presented in the table below:
| | | | | | | | | | | | |
| | Before
| | | Consolidated
| | | After
| |
| | Application of
| | | SFAS 158
| | | Application of
| |
| | SFAS 158(1) | | | Impact | | | SFAS 158 | |
| | (Thousands) | |
|
Qualified Retirement Plan | | | | | | | | | | | | |
Reduction in Prepaid Pension and Other Post-Retirement Benefit Costs | | $ | 51,612 | | | $ | (28,987 | ) | | $ | 22,625 | |
Increase in Other Regulatory Assets Related to SFAS 158 | | $ | — | | | $ | 17,731 | | | $ | 17,731 | |
Reduction in Accumulated Other Comprehensive Income | | $ | — | | | $ | 7,008 | | | $ | 7,008 | |
Reduction in Deferred Income Taxes (under Deferred Credits) | | $ | — | | | $ | 4,248 | | | $ | 4,248 | |
94
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | |
| | Before
| | | Consolidated
| | | After
| |
| | Application of
| | | SFAS 158
| | | Application of
| |
| | SFAS 158(1) | | | Impact | | | SFAS 158 | |
| | (Thousands) | |
|
Other Post-Retirement Benefits | | | | | | | | | | | | |
Increase in Prepaid Pension and OtherPost-Retirement Benefit Costs | | $ | 26,067 | | | $ | 12,314 | | | $ | 38,381 | |
Increase in Other Regulatory Assets Related to SFAS 158 | | $ | — | | | $ | 38,472 | | | $ | 38,472 | |
Increase in Other Regulatory Liabilities Related to SFAS 158 | | $ | — | | | $ | (3,247 | ) | | $ | (3,247 | ) |
Reduction in Accumulated Other Comprehensive Income | | $ | — | | | $ | 484 | | | $ | 484 | |
Reduction in Deferred Income Taxes (under Deferred Credits) | | $ | — | | | $ | 294 | | | $ | 294 | |
Increase in Other Post-Retirement Liabilities | | $ | (22,238 | ) | | $ | (48,317 | ) | | $ | (70,555 | ) |
Non-Qualified Benefit Plan | | | | | | | | | | | | |
Increase in Other Regulatory Assets Related to SFAS 158 | | $ | — | | | $ | 5,704 | | | $ | 5,704 | |
Reduction in Accumulated Other Comprehensive Income | | $ | — | | | $ | 4,990 | | | $ | 4,990 | |
Reduction in Deferred Income Taxes (under Deferred Credits) | | $ | — | | | $ | 3,027 | | | $ | 3,027 | |
Increase in Other Deferred Credits | | $ | (30,115 | ) | | $ | (13,721 | ) | | $ | (43,836 | ) |
Total Consolidated | | | | | | | | | | | | |
Reduction in Prepaid Pension and OtherPost-Retirement Benefit Costs | | $ | 77,679 | | | $ | (16,673 | ) | | $ | 61,006 | |
Increase in Other Regulatory Assets Related to SFAS 158 | | $ | — | | | $ | 61,907 | | | $ | 61,907 | |
Increase in Other Regulatory Liabilities Related to SFAS 158 | | $ | — | | | $ | (3,247 | ) | | $ | (3,247 | ) |
Reduction in Accumulated Other Comprehensive Income | | $ | — | | | $ | 12,482 | | | $ | 12,482 | |
Reduction in Deferred Income Taxes (under Deferred Credits) | | $ | — | | | $ | 7,569 | | | $ | 7,569 | |
Increase in Other Post-Retirement Liabilities | | $ | (22,238 | ) | | $ | (48,317 | ) | | $ | (70,555 | ) |
Increase in Other Deferred Credits | | $ | (30,115 | ) | | $ | (13,721 | ) | | $ | (43,836 | ) |
| | |
(1) | | Amounts represent balances before applying the effects of the adoption of SFAS 158, but after giving effect to any necessary adjustments as a result of recognizing an additional minimum pension liability. At September 30, 2007, there was no additional minimum pension liability adjustment since the fair value of the plan assets exceeded the accumulated benefit obligation. |
In order to adjust the funded status of its pension and otherpost-retirement benefit plans at September 30, 2008, the Company recorded a $57.2 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $7.3 million (net of deferred tax benefits of $4.4 million) increase to Accumulated Other Comprehensive Loss.
95103
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As note above, through 2008, the Company used June 30th as the measurement date for financial reporting purposes. In 2009, in accordance with the current authoritative guidance for defined benefit pension and other postretirement plans, the Company began measuring the Plan’s assets and liabilities for its pension and other post-retirement benefit plans as of September 30th, its fiscal year end. In making this change and as permitted by the current authoritative guidance, the Company recorded fifteen months of pension and post-retirement benefits expense (for the period from July 1, 2008 through September 30, 2009) during the fiscal year ended September 30, 2009. The pension and other post-retirement benefit costs for the period of July 1, 2008 to September 30, 2008 amounted to $3.8 million and were recorded by the Company during the year ended September 30, 2009 as a $3.4 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to earnings reinvested in the business. In addition, for the Company’s non-qualified benefit plan, benefit costs of $1.3 million were recorded by the Company during the year ended September 30, 2009 as a $0.4 million increase to Other Regulatory Assets in the Company’s Utility segment and a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business.
The cumulative amounts recognized in accumulated other comprehensive loss,income (loss), regulatory assets, and regulatory liabilities through fiscal 2009, the changes in fiscal 2008,such amounts during 2009, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 20092010 are presented in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Other
| | | | | | | Other
| | | |
| | Retirement
| | Post-Retirement
| | Non-Qualified
| | | Retirement
| | Post-Retirement
| | Non-Qualified
| |
| | Plan | | Benefits | | Benefit Plan | | | Plan | | Benefits | | Benefit Plan | |
| | (Thousands) | | | (Thousands) | |
|
Amounts Recognized In Accumulated Other Comprehensive Loss, Regulatory Assets and Regulatory Liabilities(1) | | | | | | | | | | | | | |
Net Actuarial Gain/(Loss) | | $ | (71,637 | ) | | $ | (53,108 | ) | | $ | (13,530 | ) | |
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) | | | | | | | | | | | | | |
Net Actuarial Loss | | | $ | (324,615 | ) | | $ | (191,360 | ) | | $ | (24,690 | ) |
Transition Obligation | | | — | | | | (11,326 | ) | | | — | | | | — | | | | (2,027 | ) | | | — | |
Prior Service (Cost) Credit | | | (5,495 | ) | | | 7,561 | | | | (11 | ) | | | (4,581 | ) | | | 10,517 | | | | — | |
| | | | | | | | | | | | | | |
Net Amount Recognized | | $ | (77,132 | ) | | $ | (56,873 | ) | | $ | (13,541 | ) | | $ | (329,196 | ) | | $ | (182,870 | ) | | $ | (24,690 | ) |
| | | | | | | | | | | | | | |
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2009(1) | | | | | | | | | | | | | |
Increase in Net Actuarial Loss | | | $ | (252,978 | ) | | $ | (138,252 | ) | | $ | (11,160 | ) |
Reduction in Transition Obligation | | | | — | | | | 9,299 | | | | — | |
Prior Service (Cost) Credit | | | | 914 | | | | 2,956 | | | | 11 | |
| | | | | | | | |
Net Change | | | $ | (252,064 | ) | | $ | (125,997 | ) | | $ | (11,149 | ) |
| | | | | | | | |
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) | | | | | | | | | | | | | | | | | | | | | | | | |
Net Actuarial Gain/(Loss) | | $ | (5,676 | ) | | $ | (9,271 | ) | | $ | (1,322 | ) | |
Net Actuarial Loss | | | $ | (21,641 | ) | | $ | (25,882 | ) | | $ | (2,623 | ) |
Transition Obligation | | | — | | | | (2,265 | ) | | | — | | | | — | | | | (541 | ) | | | — | |
Prior Service (Cost) Credit | | | (731 | ) | | | 1,074 | | | | — | | | | (655 | ) | | | 1,710 | | | | — | |
| | | | | | | | | | | | | | |
Net Amount Expected to be Recognized | | $ | (6,407 | ) | | $ | (10,462 | ) | | $ | (1,322 | ) | | $ | (22,296 | ) | | $ | (24,713 | ) | | $ | (2,623 | ) |
| | | | | | | | | | | | | | |
| | |
(1) | | Amounts presented are shown before recognizing deferred taxes. |
In accordance withorder to adjust the provisionsfunded status of SFAS 87,its pension and other post-retirement benefit plans at September 30, 2009, the Company recorded an additional minimum pension liability at September 30, 2005 representinga $318.4 million increase to Other Regulatory Assets in the excessCompany’s Utility and
104
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Pipeline and Storage segments and a $70.8 million (pre-tax) increase to Accumulated Other Comprehensive Loss.
The effect of the accumulated benefit obligation over the fair value of plan assets plus accrued amounts previously recorded. An intangible asset offset the additional liability to the extent of previously Unrecognized Prior Service Cost. The amount in excess of Unrecognized Prior Service Cost was recorded net of the related tax benefit as accumulated other comprehensive loss. At September 30, 2006, the Company reversed the additional minimum pension liability, intangible asset and accumulated other comprehensive loss recorded in prior years since the fair value of the plan assets exceeded the accumulated benefit obligation at September 30, 2006. The pre-tax amounts of thediscount rate change in accumulated other comprehensive (income) loss related to the additional minimum pension liability adjustment at September 30, 2006 are shown in the table above. At September 30, 2007, prior to recognizing the impact of adopting SFAS 158, there was no additional minimum pension liability adjustment recorded since the fair value of the plan assets exceeded the accumulated benefit obligation. The projected benefit obligation, accumulated benefit obligation and fair value of assets for the Retirement Plan were as follows:
| | | | | | | | | | | | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands) | |
|
Projected Benefit Obligation | | $ | 719,059 | | | $ | 742,519 | | | $ | 732,207 | |
Accumulated Benefit Obligation | | $ | 659,004 | | | $ | 672,340 | | | $ | 660,026 | |
Fair Value of Plan Assets | | $ | 695,089 | | | $ | 765,144 | | | $ | 664,520 | |
in 2009 was to increase the projected benefit obligation of the Retirement Plan by $102.6 million. The effect of the discount rate change for the Retirement Plan in 2008 was to decrease the projected benefit obligation of the Retirement Plan by $38.6 million. In 2008, other actuarial experience increased the projected benefit obligation for the Retirement Plan by $4.4 million. There2007, there was no change to the discount rate used to estimate the projected benefit obligation for the Retirement Plan during 2007. The effect of the discount rate change for the Retirement Plan in 2006 was to decrease the projected benefit obligation of the Retirement Plan by $113.1 million.
96
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Plan.
The Company made cash contributions totaling $16.0 million to the Retirement Plan during the year ended September 30, 2008.2009. The Company expects that the annual contribution to the Retirement Plan in 20092010 will be in the range of $15.0$20.0 million to $20.0$30.0 million. As a result of the recent downturn in the stock markets and general economic conditions, itIt is likely that the Company will have to fund larger amounts to the Retirement Plan subsequent to 20092010 in order to be in compliance with the Pension Protection Act of 2006.
The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter: $50.5 million in 2009; $51.0$51.8 million in 2010; $51.4$52.2 million in 2011; $51.9$52.6 million in 2012; $52.9$53.3 million in 2013; $54.4 million in 2014; and $286.7$294.3 million in the five years thereafter.
In addition to the Retirement Plan discussed above, the Company also has a Non QualifiedNon-Qualified benefit plan that covers a group of management employees designated by the Chief Executive Officer of the Company. This plan provides for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit cost associated with this plan was $5.2 million, $5.0 million and $5.5 million in 2009, 2008 and $5.4 million in 2008, 2007, and 2006, respectively. At September 30, 2008,2007, an $8.0 million (pre-tax) loss was includedrecognized in accumulated other comprehensive income (loss) on the Consolidated Balance Sheet. This was first recognized in 2007Sheet upon adoption of SFAS 158. There were no amounts recognized inthe FASB revised authoritative guidance for defined benefit pension and other comprehensive income (loss) attributable to the recognition of an additional minimum liability for 2006.postretirement plans. The accumulated benefit obligation for this plan was $31.8$35.8 million and $28.8$31.8 million at September 30, 20082009 and 2007,2008, respectively. The projected benefit obligation for the plan was $47.5$60.3 million and $43.8$47.5 million at September 30, 20082009 and 2007,2008, respectively. The actuarial valuations for this plan were determined based on a discount rate of 6.75%5.25%, 6.25%6.75% and 6.25% as of September 30, 2009, 2008 2007 and 2006,2007, respectively; a rate of compensation increase of 10.0% as of September 30, 2009, 2008 2007 and 2006;2007; and an expected long-term rate of return on plan assets of 8.25% at September 30, 2009, 2008 2007 and 2006.2007.
The effect of the discount rate change in 2009 was to increase the other post-retirement benefit obligation by $60.9 million. Effective October 1, 2009, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $27.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2009 by $32.1 million.
The effect of the discount rate change in 2008 was to decrease the other post-retirement benefit obligation by $26.3 million. Effective July 1, 2008, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $20.0 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2008 by $8.1 million.
There was no change to the discount rate used to estimate the other post-retirement benefit obligation during 2007. Effective July 1, 2007, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to increase the other post-retirement benefit obligation by $8.6 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2007 by $23.0 million.
The effect of the discount rate change in 2006 was to decrease the other post-retirement benefit obligation by $77.5 million. Effective July 1, 2006, the Medicare Part B reimbursement trend, prescription drug trend and medical trend assumptions were changed. The effect of these assumption changes was to decrease the other post-retirement benefit obligation by $1.7 million. A change in the disability assumption decreased the other post-retirement benefit obligation by $1.4 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2006 by $34.4 million.
On December 8, 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. This Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least
105
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
actuarially equivalent to Medicare Part D. In accordance with FASB Staff PositionFAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, sinceSince the Company is assumed to continue to provide a prescription drug benefit to retirees in the point of service and indemnity plans that is at least actuarially equivalent to Medicare Part D, the impact of the Act was reflected as of December 8, 2003.
97
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows:
| | | | | | | | | | | | | | | | |
| | Benefit Payments | | Subsidy Receipts | | | Benefit Payments | | Subsidy Receipts |
|
2009 | | $ | 26,210,000 | | | $ | (1,714,000 | ) | |
2010 | | $ | 28,248,000 | | | $ | (1,942,000 | ) | | $ | 26,827,000 | | | $ | (1,933,000 | ) |
2011 | | $ | 30,122,000 | | | $ | (2,167,000 | ) | | $ | 28,592,000 | | | $ | (2,156,000 | ) |
2012 | | $ | 31,484,000 | | | $ | (2,437,000 | ) | | $ | 29,970,000 | | | $ | (2,444,000 | ) |
2013 | | $ | 32,687,000 | | | $ | (2,719,000 | ) | | $ | 31,299,000 | | | $ | (2,758,000 | ) |
2014 through 2018 | | $ | 181,354,000 | | | $ | (17,304,000 | ) | |
2014 | | | $ | 32,743,000 | | | $ | (3,066,000 | ) |
2015 through 2019 | | | $ | 185,348,000 | | | $ | (20,026,000 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 |
|
Rate of Increase for Pre Age 65 Participants | | | 9.0 | %(1) | | | 8.0 | %(2) | | | 9.0 | %(2) | | | 8.0 | %(1) | | | 9.0 | %(2) | | | 8.0 | %(3) |
Rate of Increase for Post Age 65 Participants | | | 7.0 | %(1) | | | 6.67 | %(2) | | | 7.0 | %(2) | | | 7.0 | %(1) | | | 7.0 | %(2) | | | 6.67 | %(3) |
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits | | | 10.0 | %(1) | | | 10.0 | %(2) | | | 11.0 | %(2) | | | 9.0 | %(1) | | | 10.0 | %(2) | | | 10.0 | %(3) |
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement | | | 7.0 | %(1) | | | 7.0 | %(3) | | | 5.25 | %(4) | | | 7.0 | %(1) | | | 7.0 | %(2) | | | 7.0 | %(4) |
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy | | | | 7.9 | %(1) | | | 10.0 | %(2) | | | 10.0 | %(3) |
| | |
(1) | | It was assumed that this rate would gradually decline to 5.0%4.5% by 2018.2028. |
|
(2) | | It was assumed that this rate would gradually decline to 5.0% by 2014.2018. |
|
(3) | | It was assumed that this rate would gradually decline to 5.0% by 2016.2014. |
|
(4) | | It was assumed that this rate would gradually decline to 5.0% by 2017.2016. |
The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, 20082009 would increase by $45.1$54.5 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 20082009 by $4.7$3.9 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 20082009 would decrease by $38.4$46.2 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 20072009 by $3.9$3.3 million.
The Company made cash contributions totaling $29.1$25.5 million to the VEBA trusts and 401(h) accounts during the year ended September 30, 2008.2009. In addition, the Company made direct payments of $0.1$0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2008.2009. The Company expects that the annual contribution to the VEBA trusts and 401(h) accounts in 20092010 will be in the range of $25.0 million to $30.0 million.
The Company’s Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2008, 2007 and 2006 by asset category are as follows:
| | | | | | | | | | | | | | | | |
| | | | | Percentage of Plan
| |
| | Target Allocation
| | | Assets at September 30 | |
Asset Category | | 2009 | | | 2008 | | | 2007 | | | 2006 | |
|
Equity Securities | | | 60-75 | % | | | 67 | % | | | 70 | % | | | 67 | % |
Fixed Income Securities | | | 20-35 | % | | | 29 | % | | | 24 | % | | | 26 | % |
Other | | | 0-15 | % | | | 4 | % | | | 6 | % | | | 7 | % |
| | | | | | | | | | | | | | | | |
Total | | | | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | | |
98106
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company’s Retirement Plan weighted average asset allocations (excluding the 401(h) accounts) at September 30, 2009, 2008 and 2007 by asset category are as follows:
| | | | | | | | | | | | | | | | |
| | | | | Percentage of Plan
| |
| | Target Allocation
| | | Assets at September 30 | |
Asset Category | | 2010 | | | 2009 | | | 2008 | | | 2007 | |
|
Equity Securities | | | 60-75 | % | | | 66 | % | | | 67 | % | | | 70 | % |
Fixed Income Securities | | | 20-35 | % | | | 21 | % | | | 23 | % | | | 18 | % |
Other | | | 0-15 | % | | | 13 | % | | | 10 | % | | | 12 | % |
| | | | | | | | | | | | | | | | |
Total | | | | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | | | |
The Company’s weighted average asset allocations for its VEBA trusts and 401(h) accounts at September 30, 2009, 2008 2007 and 20062007 by asset category are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Percentage of Plan
| | | | | Percentage of Plan
| |
| | Target Allocation
| | Assets at September 30 | | | Target Allocation
| | Assets at September 30 | |
Asset Category | | 2009 | | 2008 | | 2007 | | 2006 | | | 2010 | | 2009 | | 2008 | | 2007 | |
|
Equity Securities | | | 85-100 | % | | | 93 | % | | | 95 | % | | | 95 | % | | | 85-100 | % | | | 93 | % | | | 93 | % | | | 95 | % |
Fixed Income Securities | | | 0-15 | % | | | 2 | % | | | 1 | % | | | 1 | % | | | 0-15 | % | | | 2 | % | | | 1 | % | | | 1 | % |
Other | | | 0-15 | % | | | 5 | % | | | 4 | % | | | 4 | % | | | 0-15 | % | | | 5 | % | | | 6 | % | | | 4 | % |
| | | | | | | | | | | | | | |
Total | | | | | | | 100 | % | | | 100 | % | | | 100 | % | | | | | | | 100 | % | | | 100 | % | | | 100 | % |
| | | | | | | | | | | | | | |
The Company’s assumption regarding the expected long-term rate of return on plan assets is 8.25%. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes historical investment data, projected capital market conditions, and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition.
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
The discount rate which is used to present value the future benefit payment obligations of the Retirement Plan the Non-Qualified benefit plan, and the Company’s other post-retirement benefits is 6.75%5.50% as of September 30, 2008.2009. The discount rate which is used to present value the future benefit payment obligations of the Non-Qualified benefit plan is 5.25% as of September 30, 2009. The Company utilizes a yield curve model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments.
| |
Note H — | Commitments and Contingencies |
Note I — Commitments and Contingencies
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
107
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
It is the Company’s policy to accrue estimated environmentalclean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2008,2009, the Company has estimated its remainingclean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $19.4$18.7 million to $23.6$22.9 million. The minimum estimated liability of $19.4$18.7 million has been recorded on the Consolidated Balance Sheet at September 30, 2008.2009. The Company expects to recover its environmentalclean-up costs from a combination of rate recovery and deferred insurance proceeds that are currently recorded as a regulatory liability on the Consolidated Balance Sheet (refer to Note C — Regulatory Matters for further discussion of the insurance proceeds). Other than as discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
99
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
(i) | Former Manufactured Gas Plant Sites |
The Company has incurred investigationand/orclean-up costs at several former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing monitoring and long-term maintenance at two sites.
With respectThe Company has agreed with the NYDEC to remediate another former manufactured gas plant site the Company received, in 1998 and again in October 1999, notice that the NYDEC believes the Company is responsible for contamination discovered at the site located in New York for which the Company had not been named as a PRP. In February 2007, the NYDEC identified the Company as a PRP for the site and issued a proposed remedial action plan. The NYDEC estimatedclean-up costs under its proposed remedy to be $8.9 million if implemented. Although the Company commented to the NYDEC that the proposed remedial action plan contained a number of material errors, omissions and procedural defects, the NYDEC, in a March 2007 Record of Decision, selected the remedy it had previously proposed. In July 2007, the Company appealed the NYDEC’s Record of Decision to the New York State Supreme Court, Albany County. The Court dismissed the appeal in January 2008. The Company filed a notice of appeal in February 2008. In July 2008, the Company withdrew its appeal and, without admitting liability or fault, agreed to the terms of an Order on Consent issued by the NYDEC. Pursuant to the order, the Company will remediate the site consistent with the remedy selected in the NYDEC’s Record of Decision. The Company reimbursed the NYDEC in the amount of approximately $1.5 million for costs incurred in connection with the site from 1998 through May 30, 2007. The Company acknowledged that additional charges related to the site will be billed to the Company at a later date, including costs incurred by the NYDEC after May 30, 2007 and any costs incurred by the New York Department of Health.York. The Company has not received and does not expect to receive any estimatesapproval from the NYDEC of such additional costs. The Company has submitted a Remedial Design/Remedial ActionDesign work plan to the NYDEC in accordance with the Order on Consentfor this site and has increased its recorded an estimated minimum liability for remediation of this site to $16.5of $15.7 million.
In June 2007, the NYDEC notified the Company, as well as a number of other companies, of their potential liability with respect to a remedial action at a waste disposal site in New York. The notification identified the Company as one of approximately 500 other companies considered to be PRPs related to this site and requested that the remedy the NYDEC proposed in a Record of Decision issued in March 2006 be performed. The estimatedclean-up costs under the remedy selected by the NYDEC are estimated to be approximately $13.0 million if implemented. The Company participates in an organized group with other PRPs who are addressing this site.
Other
The Company, in its Utility segment, Energy Marketing segment, and All Other category, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Substantially all of these contracts expire within the next five years. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $793.2 million in 2009, $168.0$520.2 million in 2010, $55.6$101.8 million in 2011, $47.0$66.6 million in 2012, $21.6$40.2 million in 2013, $39.8 million in 2014, and $100.7$76.3 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
The Company has entered into leases for the use of buildings, vehicles, construction tools, meters, computer equipment and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $6.0 million in 2009, $4.6$5.4 million in 2010, $3.6$3.9 million in 2011, $3.2$3.3 million in 2012, $2.5$2.4 million in 2013, $2.3 million in 2014, and $12.4$10.5 million thereafter.
100
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company has entered into several contractual commitments associated with the construction of the Empire Connector project, including the pipeline construction itself and construction of a compressor station, as well as other contractual commitments for engineering and consulting services. The Empire Connector is scheduled to go in service by December 2008. As of September 30, 2008, the future contractual commitments related to the construction of the Empire Connector during 2009 is $13.5 million.
The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C — Regulatory Matters, the Company is involved in other regulatory
108
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
| |
Note I — | Discontinued Operations |
Note J — Discontinued Operations
On August 31, 2007, the Company, in its Exploration and Production segment, completed the sale of SECI, Seneca’s wholly owned subsidiary that operated in Canada. The Company received approximately $232.1 million of proceeds from the sale, of which $58.0 million was placed in escrow pending receipt of a tax clearance certificate from the Canadian government. In December 2007, the Canadian government issued the tax clearance certificate, thereby releasing the proceeds from restriction as of December 31, 2007. The sale resulted in the recognition of a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. SECI is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the provinces of Alberta, Saskatchewan and British Columbia in Canada. The decision to sell was based on lower than expected returns from the Canadian oil and gas properties combined with difficulty in finding significant new reserves. Seneca will continue its exploration and development activities in Appalachia, the Gulf of Mexico,United States, primarily in Appalachia and California. As a result of the decision to sell SECI, the Company began presenting all SECI operations as discontinued operations during the fourth quarter of 2007.
The following is selected financial information of the discontinued operations for SECI:
| | | | | | | | |
| | Year Ended September 30 | |
| | 2007 | | | 2006 | |
| | (Thousands) | |
|
Operating Revenues | | $ | 50,495 | | | $ | 71,984 | |
Operating Expenses | | | 33,306 | | | | 151,532 | |
| | | | | | | | |
Operating Income (Loss) | | | 17,189 | | | | (79,548 | ) |
Interest Income | | | 1,082 | | | | 866 | |
| | | | | | | | |
Income (Loss) before Income Taxes | | | 18,271 | | | | (78,682 | ) |
Income Tax Expense (Benefit) | | | 2,792 | | | | (32,159 | ) |
| | | | | | | | |
Income (Loss) from Discontinued Operations | | | 15,479 | | | | (46,523 | ) |
Gain on Disposal, Net of Taxes of $39,572 | | | 120,301 | | | | — | |
| | | | | | | | |
Income (Loss) from Discontinued Operations | | $ | 135,780 | | | $ | (46,523 | ) |
| | | | | | | | |
| | | | |
| | Year Ended
| |
| | September 30,
| |
| | 2007 | |
| | (Thousands) | |
|
Operating Revenues | | $ | 50,495 | |
Operating Expenses | | | 33,306 | |
| | | | |
Operating Income | | | 17,189 | |
Interest Income | | | 1,082 | |
| | | | |
Income before Income Taxes | | | 18,271 | |
Income Tax Expense | | | 2,792 | |
| | | | |
Income from Discontinued Operations | | | 15,479 | |
Gain on Disposal, Net of Taxes of $39,572 | | | 120,301 | |
| | | | |
Income from Discontinued Operations | | $ | 135,780 | |
| | | | |
101
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNote K — (Continued)Business Segment Information
| |
Note J — | Business Segment Information |
The Company reports financial results for five businesshas four reportable segments: Utility, Pipeline and Storage, Exploration and Production, and Energy Marketing, and Timber.Marketing. The breakdowndivision of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
109
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Pipeline and Storage segment operations are regulated. Theregulated by the FERC regulates the operations offor both Supply Corporation and the NYPSC regulates the operations of Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR) and pipeline companies in the northeastern United States markets. Empire transports natural gas from the United States/Canadian border near Buffalo, New York into Central New York just north of Syracuse, New York. Empire is constructing theEmpire’s new facilities (the Empire Connector project,project), which consists of a compressor station and a pipeline extension from near Rochester, New York to an interconnection near Corning, New York with the unaffiliated Millennium Pipeline. The Empire Connector is anticipated to be ready to commencePipeline, were placed into service in earlyon December 2008, on or before the in-service date of the Millennium Pipeline.10, 2008. Empire transports gas to major industrial companies, utilities (including Distribution Corporation) and power producers.
The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in California, in the Appalachian region of the United States, and in the Gulf Coast region of Texas Louisiana and Alabama.Louisiana. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. As disclosed in Note IJ — Discontinued Operations, on August 31, 2007, Seneca completed the sale of SECI, its wholly owned subsidiary operating in Canada, for a gain of approximately $120.3 million, net of tax, during the fourth quarter of 2007. As a result of the sale, SECI’s operations have been reported as discontinued operations. As disclosed in Note M — Acquisition, on July 20, 2009, Seneca acquired Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million (including cash acquired). Ivanhoe Energy’s United States oil and gas operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009.
The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.
The Timber segment’s operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings (primarily high quality hardwoods) in the northeastern United States and sawmills and kilns in Pennsylvania.
The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income.
102110
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2008 | | | Year Ended September 30, 2009 |
| | | | | | | | | | | | | | | | Corporate
| | | | | | | | | | | | | | | | | Corporate
| | |
| | | | Pipeline
| | Exploration
| | | | | | Total
| | | | and
| | | | | | | Pipeline
| | Exploration
| | | | Total
| | | | and
| | |
| | | | and
| | and
| | Energy
| | | | Reported
| | All
| | Intersegment
| | Total
| | | | | and
| | and
| | Energy
| | Reportable
| | All
| | Intersegment
| | Total
|
| | Utility | | Storage | | Production | | Marketing | | Timber | | Segments | | Other | | Eliminations | | Consolidated | | | Utility | | Storage | | Production | | Marketing | | Segments | | Other | | Eliminations | | Consolidated |
| | (Thousands) | | | (Thousands) |
|
Revenue from External Customers | | $ | 1,194,657 | | | $ | 135,052 | | | $ | 466,760 | | | $ | 549,932 | | | $ | 49,516 | | | $ | 2,395,917 | | | $ | 3,749 | | | $ | 695 | | | $ | 2,400,361 | | | $ | 1,097,550 | | | $ | 137,478 | | | $ | 382,758 | | | $ | 397,763 | | | $ | 2,015,549 | | | $ | 41,409 | | | $ | 894 | | | $ | 2,057,852 | |
Intersegment Revenues | | $ | 15,612 | | | $ | 81,504 | | | $ | — | | | $ | 1,300 | | | $ | — | | | $ | 98,416 | | | $ | 14,115 | | | $ | (112,531 | ) | | $ | — | | | $ | 15,474 | | | $ | 81,795 | | | $ | — | | | $ | 558 | | | $ | 97,827 | | | $ | 3,890 | | | $ | (101,717 | ) | | $ | — | |
Interest Income | | $ | 1,836 | | | $ | 843 | | | $ | 10,921 | | | $ | 323 | | | $ | 1,053 | | | $ | 14,976 | | | $ | 179 | | | $ | (4,340 | ) | | $ | 10,815 | | | $ | 2,486 | | | $ | 995 | | | $ | 2,430 | | | $ | 79 | | | $ | 5,990 | | | $ | 583 | | | $ | (797 | ) | | $ | 5,776 | |
Interest Expense | | $ | 27,683 | | | $ | 13,783 | | | $ | 41,645 | | | $ | 175 | | | $ | 3,142 | | | $ | 86,428 | | | $ | 640 | | | $ | (13,099 | ) | | $ | 73,969 | | | $ | 32,417 | | | $ | 21,580 | | | $ | 33,368 | | | $ | 215 | | | $ | 87,580 | | | $ | 2,471 | | | $ | (3,135 | ) | | $ | 86,916 | |
Depreciation, Depletion and Amortization | | $ | 39,113 | | | $ | 32,871 | | | $ | 92,221 | | | $ | 42 | | | $ | 4,904 | | | $ | 169,151 | | | $ | 783 | | | $ | 689 | | | $ | 170,623 | | | $ | 39,675 | | | $ | 35,115 | | | $ | 90,816 | | | $ | 42 | | | $ | 165,648 | | | $ | 7,066 | | | $ | 696 | | | $ | 173,410 | |
Income Tax Expense | | $ | 36,303 | | | $ | 34,008 | | | $ | 92,686 | | | $ | 3,180 | | | $ | (378 | ) | | $ | 165,799 | | | $ | 2,564 | | | $ | (441 | ) | | $ | 167,922 | | |
Income Tax Expense (Benefit) | | | $ | 37,097 | | | $ | 30,579 | | | $ | (14,616 | ) | | $ | 4,470 | | | $ | 57,530 | | | $ | (5,221 | ) | | $ | (1,189 | ) | | $ | 51,120 | |
Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 6,303 | | | $ | — | | | $ | 6,303 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,366 | | | $ | — | | | $ | 3,366 | |
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | | | $ | — | | | $ | — | | | $ | 182,811 | | | $ | — | | | $ | 182,811 | | | $ | — | | | $ | — | | | $ | 182,811 | |
Significant Non-Cash Item: Impairment of Investment in Partnership | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,804 | (1) | | $ | — | | | $ | 1,804 | |
Significant Non-Cash Item: Impairment of Landfill Gas Assets | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,568 | (2) | | $ | — | | | $ | 4,568 | |
Segment Profit: Net Income (Loss) | | $ | 61,472 | | | $ | 54,148 | | | $ | 146,612 | | | $ | 5,889 | | | $ | 107 | | | $ | 268,228 | | | $ | 5,672 | | | $ | (5,172 | ) | | $ | 268,728 | | | $ | 58,664 | | | $ | 47,358 | | | $ | (10,238 | ) | | $ | 7,166 | | | $ | 102,950 | | | $ | (2,071 | ) | | $ | (171 | ) | | $ | 100,708 | |
Expenditures for Additions to Long-Lived Assets | | $ | 57,457 | | | $ | 165,520 | | | $ | 192,187 | | | $ | 39 | | | $ | 1,354 | | | $ | 416,557 | | | $ | 131 | | | $ | (2,186 | ) | | $ | 414,502 | | | $ | 56,178 | | | $ | 50,118 | | | $ | 223,223 | (3) | | $ | 25 | | | $ | 329,544 | | | $ | 9,723 | (4) | | $ | (47 | ) | | $ | 339,220 | |
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | At September 30, 2009 |
| | | (Thousands) |
| |
Segment Assets | | | $ | 2,132,610 | | | $ | 1,046,372 | | | $ | 1,265,678 | | | $ | 52,469 | | | $ | 4,497,129 | | | $ | 210,809 | | | $ | 61,191 | | | $ | 4,769,129 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At September 30, 2008 | |
| | (Thousands) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment Assets | | $ | 1,643,665 | | | $ | 948,984 | | | $ | 1,416,120 | | | $ | 89,527 | | | $ | 149,896 | | | $ | 4,248,192 | | | $ | 67,978 | | | $ | (185,983 | ) | | $ | 4,130,187 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2007 | |
| | | | | | | | | | | | | | | | | | | | | | | Corporate
| | | | |
| | | | | Pipeline
| | | Exploration
| | | | | | | | | Total
| | | | | | and
| | | | |
| | | | | and
| | | and
| | | Energy
| | | | | | Reported
| | | All
| | | Intersegment
| | | Total
| |
| | Utility | | | Storage | | | Production | | | Marketing | | | Timber | | | Segments | | | Other | | | Eliminations | | | Consolidated | |
| | (Thousands) | |
|
Revenue from External Customers | | $ | 1,106,453 | | | $ | 130,410 | | | $ | 324,037 | | | $ | 413,612 | | | $ | 58,897 | | | $ | 2,033,409 | | | $ | 5,385 | | | $ | 772 | | | $ | 2,039,566 | |
Intersegment Revenues | | $ | 14,271 | | | $ | 81,556 | | | $ | — | | | $ | — | | | $ | — | | | $ | 95,827 | | | $ | 8,726 | | | $ | (104,553 | ) | | $ | — | |
Interest Income | | $ | (2,345 | ) | | $ | 357 | | | $ | 9,905 | | | $ | 682 | | | $ | 1,249 | | | $ | 9,848 | | | $ | 16 | | | $ | (8,314 | ) | | $ | 1,550 | |
Interest Expense | | $ | 28,190 | | | $ | 9,623 | | | $ | 51,743 | | | $ | 263 | | | $ | 3,265 | | | $ | 93,084 | | | $ | 2,687 | | | $ | (21,296 | ) | | $ | 74,475 | |
Depreciation, Depletion and Amortization | | $ | 40,541 | | | $ | 32,985 | | | $ | 78,174 | | | $ | 33 | | | $ | 4,709 | | | $ | 156,442 | | | $ | 785 | | | $ | 692 | | | $ | 157,919 | |
Income Tax Expense | | $ | 31,642 | | | $ | 35,740 | | | $ | 52,421 | | | $ | 5,654 | | | $ | 2,818 | | | $ | 128,275 | | | $ | 1,647 | | | $ | 1,891 | | | $ | 131,813 | |
Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,979 | | | $ | — | | | $ | 4,979 | |
Segment Profit: Income from Continuing Operations | | $ | 50,886 | | | $ | 56,386 | | | $ | 74,889 | | | $ | 7,663 | | | $ | 3,728 | | | $ | 193,552 | | | $ | 2,564 | | | $ | 5,559 | | | $ | 201,675 | |
Expenditures for Additions to Long-Lived Assets from Continuing Operations | | $ | 54,185 | | | $ | 43,226 | | | $ | 146,687 | | | $ | 76 | | | $ | 3,657 | | | $ | 247,831 | | | $ | 87 | | | $ | (319 | ) | | $ | 247,599 | |
| | |
(1) | | Amount represents the impairment in the value of the Company’s 50% investment in ESNE, a partnership that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania. |
|
(2) | | Amount represents the impairment in the value of certain long-lived landfill gas site assets due to the loss of a primary customer at the site and the anticipated shut-down of the site. The impairment includes a $2.6 million reduction in intangible assets related to long-term gas purchase contracts and a $2.0 million reduction in property, plant and equipment. |
|
(3) | | Amount includes the acquisition of Ivanhoe Energy’s United States oil and gas operation for $34.9 million, net of cash acquired, and is discussed in Note M — Acquisition. |
|
(4) | | Amount includes a $1.3 million capital contribution made by NFG Midstream Processing, LLC in the Whitetail Processing Plant. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At September 30, 2007 | |
| | (Thousands) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment Assets | | $ | 1,565,593 | | | $ | 810,957 | | | $ | 1,326,073 | | | $ | 59,802 | | | $ | 165,224 | | | $ | 3,927,649 | | | $ | 66,531 | | | $ | (105,768 | ) | | $ | 3,888,412 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2006 | |
| | | | | | | | | | | | | | | | | | | | | | | Corporate
| | | | |
| | | | | Pipeline
| | | Exploration
| | | | | | | | | Total
| | | | | | and
| | | | |
| | | | | and
| | | and
| | | Energy
| | | | | | Reported
| | | All
| | | Intersegment
| | | Total
| |
| | Utility | | | Storage | | | Production | | | Marketing | | | Timber | | | Segments | | | Other | | | Eliminations | | | Consolidated | |
| | (Thousands) | |
|
Revenue from External Customers | | $ | 1,265,695 | | | $ | 132,921 | | | $ | 274,896 | | | $ | 497,069 | | | $ | 65,024 | | | $ | 2,235,605 | | | $ | 3,304 | | | $ | 766 | | | $ | 2,239,675 | |
Intersegment Revenues | | $ | 15,068 | | | $ | 81,431 | | | $ | — | | | $ | — | | | $ | 5 | | | $ | 96,504 | | | $ | 9,444 | | | $ | (105,948 | ) | | $ | — | |
Interest Income | | $ | 4,889 | | | $ | 454 | | | $ | 7,816 | | | $ | 445 | | | $ | 747 | | | $ | 14,351 | | | $ | 22 | | | $ | (4,964 | ) | | $ | 9,409 | |
Interest Expense | | $ | 26,174 | | | $ | 6,620 | | | $ | 50,457 | | | $ | 227 | | | $ | 3,095 | | | $ | 86,573 | | | $ | 2,555 | | | $ | (10,547 | ) | | $ | 78,581 | |
Depreciation, Depletion and Amortization | | $ | 40,172 | | | $ | 36,876 | | | $ | 67,122 | | | $ | 53 | | | $ | 6,495 | | | $ | 150,718 | | | $ | 789 | | | $ | 492 | | | $ | 151,999 | |
Income Tax Expense | | $ | 35,699 | | | $ | 33,896 | | | $ | 29,351 | | | $ | 3,748 | | | $ | 3,277 | | | $ | 105,971 | | | $ | 969 | | | $ | 1,305 | | | $ | 108,245 | |
Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,583 | | | $ | — | | | $ | 3,583 | |
Segment Profit: Income (Loss) from Continuing Operations | | $ | 49,815 | | | $ | 55,633 | | | $ | 67,494 | | | $ | 5,798 | | | $ | 5,704 | | | $ | 184,444 | | | $ | 359 | | | $ | (189 | ) | | $ | 184,614 | |
Expenditures for Additions to Long-Lived Assets from Continuing Operations | | $ | 54,414 | | | $ | 26,023 | | | $ | 166,535 | | | $ | 16 | | | $ | 2,323 | | | $ | 249,311 | | | $ | 85 | | | $ | 2,995 | | | $ | 252,391 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At September 30, 2006 | |
| | (Thousands) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Segment Assets | | $ | 1,498,442 | | | $ | 767,889 | | | $ | 1,209,969 | (1) | | $ | 81,374 | | | $ | 159,421 | | | $ | 3,717,095 | | | $ | 64,287 | | | $ | (17,634 | ) | | $ | 3,763,748 | |
103111
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2008 |
| | | | | | | | | | | | | | Corporate
| | |
| | | | Pipeline
| | Exploration
| | | | Total
| | | | and
| | |
| | | | and
| | and
| | Energy
| | Reportable
| | All
| | Intersegment
| | Total
|
| | Utility | | Storage | | Production | | Marketing | | Segments | | Other | | Eliminations | | Consolidated |
| | (Thousands) |
|
Revenue from External Customers | | $ | 1,194,657 | | | $ | 135,052 | | | $ | 466,760 | | | $ | 549,932 | | | $ | 2,346,401 | | | $ | 53,265 | | | $ | 695 | | | $ | 2,400,361 | |
Intersegment Revenues | | $ | 15,612 | | | $ | 81,504 | | | $ | — | | | $ | 1,300 | | | $ | 98,416 | | | $ | 14,115 | | | $ | (112,531 | ) | | $ | — | |
Interest Income | | $ | 1,836 | | | $ | 843 | | | $ | 10,921 | | | $ | 323 | | | $ | 13,923 | | | $ | 1,232 | | | $ | (4,340 | ) | | $ | 10,815 | |
Interest Expense | | $ | 27,683 | | | $ | 13,783 | | | $ | 41,645 | | | $ | 175 | | | $ | 83,286 | | | $ | 3,782 | | | $ | (13,099 | ) | | $ | 73,969 | |
Depreciation, Depletion and Amortization | | $ | 39,113 | | | $ | 32,871 | | | $ | 92,221 | | | $ | 42 | | | $ | 164,247 | | | $ | 5,687 | | | $ | 689 | | | $ | 170,623 | |
Income Tax Expense (Benefit) | | $ | 36,303 | | | $ | 34,008 | | | $ | 92,686 | | | $ | 3,180 | | | $ | 166,177 | | | $ | 2,186 | | | $ | (441 | ) | | $ | 167,922 | |
Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 6,303 | | | $ | — | | | $ | 6,303 | |
Segment Profit: Net Income (Loss) | | $ | 61,472 | | | $ | 54,148 | | | $ | 146,612 | | | $ | 5,889 | | | $ | 268,121 | | | $ | 5,779 | | | $ | (5,172 | ) | | $ | 268,728 | |
Expenditures for Additions to Long-Lived Assets | | $ | 57,457 | | | $ | 165,520 | | | $ | 192,187 | | | $ | 39 | | | $ | 415,203 | | | $ | 1,485 | | | $ | (2,186 | ) | | $ | 414,502 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At September 30, 2008 |
| | (Thousands) |
|
Segment Assets | | $ | 1,643,665 | | | $ | 948,984 | | | $ | 1,416,120 | | | $ | 89,527 | | | $ | 4,098,296 | | | $ | 217,874 | | | $ | (185,983 | ) | | $ | 4,130,187 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2007 |
| | | | | | | | | | | | | | Corporate
| | |
| | | | Pipeline
| | Exploration
| | | | Total
| | | | and
| | |
| | | | and
| | and
| | Energy
| | Reportable
| | All
| | Intersegment
| | Total
|
| | Utility | | Storage | | Production | | Marketing | | Segments | | Other | | Eliminations | | Consolidated |
| | (Thousands) |
|
Revenue from External Customers | | $ | 1,106,453 | | | $ | 130,410 | | | $ | 324,037 | | | $ | 413,612 | | | $ | 1,974,512 | | | $ | 64,282 | | | $ | 772 | | | $ | 2,039,566 | |
Intersegment Revenues | | $ | 14,271 | | | $ | 81,556 | | | $ | — | | | $ | — | | | $ | 95,827 | | | $ | 8,726 | | | $ | (104,553 | ) | | $ | — | |
Interest Income | | $ | (2,345 | ) | | $ | 357 | | | $ | 9,905 | | | $ | 682 | | | $ | 8,599 | | | $ | 1,265 | | | $ | (8,314 | ) | | $ | 1,550 | |
Interest Expense | | $ | 28,190 | | | $ | 9,623 | | | $ | 51,743 | | | $ | 263 | | | $ | 89,819 | | | $ | 5,952 | | | $ | (21,296 | ) | | $ | 74,475 | |
Depreciation, Depletion and Amortization | | $ | 40,541 | | | $ | 32,985 | | | $ | 78,174 | | | $ | 33 | | | $ | 151,733 | | | $ | 5,494 | | | $ | 692 | | | $ | 157,919 | |
Income Tax Expense | | $ | 31,642 | | | $ | 35,740 | | | $ | 52,421 | | | $ | 5,654 | | | $ | 125,457 | | | $ | 4,465 | | | $ | 1,891 | | | $ | 131,813 | |
Income from Unconsolidated Subsidiaries | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,979 | | | $ | — | | | $ | 4,979 | |
Segment Profit: Income from Continuing Operations | | $ | 50,886 | | | $ | 56,386 | | | $ | 74,889 | | | $ | 7,663 | | | $ | 189,824 | | | $ | 6,292 | | | $ | 5,559 | | | $ | 201,675 | |
Expenditures for Additions to Long-Lived Assets from Continuing Operations | | $ | 54,185 | | | $ | 43,226 | | | $ | 146,687 | | | $ | 76 | | | $ | 244,174 | | | $ | 7,044 | (1) | | $ | (319 | ) | | $ | 250,899 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At September 30, 2007 |
| | (Thousands) |
|
Segment Assets | | $ | 1,565,593 | | | $ | 810,957 | | | $ | 1,326,073 | | | $ | 59,802 | | | $ | 3,762,425 | | | $ | 231,755 | | | $ | (105,768 | ) | | $ | 3,888,412 | |
| | |
(1) | | Amount includes $134,930 of assets of SECI, which has been classified as discontinued operations as of September 30, 2007. (See Note I — Discontinued Operations).a $3.3 million capital contribution to Seneca Energy by Horizon Power. |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | For The Year Ended September 30 | | | For The Year Ended September 30 | |
Geographic Information | | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | (Thousands) | | | (Thousands) | |
|
Revenues from External Customers(1): | | | | | | | | | | | | | | | | | | | | | | | | |
United States | | $ | 2,400,361 | | | $ | 2,039,566 | | | $ | 2,239,675 | | | $ | 2,057,852 | | | $ | 2,400,361 | | | $ | 2,039,566 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | At September 30 | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands) | |
|
Long-Lived Assets: | | | | | | | | | | | | |
United States | | $ | 3,630,709 | | | $ | 3,334,274 | | | $ | 3,181,769 | |
Assets of Discontinued Operations | | | — | | | | — | | | | 97,234 | |
| | | | | | | | | | | | |
| | $ | 3,630,709 | | | $ | 3,334,274 | | | $ | 3,279,003 | |
| | | | | | | | | | | | |
112
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | |
| | At September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
| | (Thousands) | |
|
Long-Lived Assets: | | | | | | | | | | | | |
United States | | $ | 3,992,159 | | | $ | 3,630,709 | | | $ | 3,334,274 | |
| | | | | | | | | | | | |
| | |
(1) | | Revenue is based upon the country in which the sale originates. This table excludes revenues from Canadian discontinued operations of $50,495 and $71,984 for September 30, 2007 and 2006, respectively.2007. |
| |
Note K — | Investments in Unconsolidated Subsidiaries |
Note L — Investments in Unconsolidated Subsidiaries
The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy, Model City, ESNE and ESNE.Whitetail Processing Plant. The Company has 50% interests in each of these entities.the first three entities and a 35% ownership interest in the Whitetail Processing Plant. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. ESNE sells its electricity into the New York power grid. Whitetail Processing Plant is currently under construction with completion expected in the fall of 2009. Once completed, the plant will extract natural gas liquids from local production in Pennsylvania.
During the quarter ended December 31, 2008, the Company recorded a pre-tax impairment of $1.8 million ($1.1 million on an after-tax basis) of its equity investment in ESNE due to a decline in the fair market value of ESNE. The impairment was driven by a significant decrease in “run time” for the plant given the economic downturn and the resulting decrease in demand for electric power.
A summary of the Company’s investments in unconsolidated subsidiaries at September 30, 20082009 and 20072008 is as follows:
| | | | | | | | | | | | | | | | |
| | At September 30 | | | At September 30 | |
| | 2008 | | 2007 | | | 2009 | | 2008 | |
| | (Thousands) | | | (Thousands) | |
|
ESNE | | $ | 3,958 | | | $ | 4,652 | | |
Seneca Energy | | | 10,589 | | | | 12,033 | | | $ | 10,924 | | | $ | 10,589 | |
Model City | | | 1,732 | | | | 1,571 | | | | 2,136 | | | | 1,732 | |
ESNE | | | | 1,880 | | | | 3,958 | |
Whitetail Processing Plant | | | | 1,317 | | | | — | |
| | | | | | | | | | |
| | $ | 16,279 | | | $ | 18,256 | | | $ | 16,257 | | | $ | 16,279 | |
| | | | | | | | | | |
Note M — Acquisition
On July 20, 2009, the Company’s wholly-owned subsidiary in the Exploration and Production segment, Seneca, acquired all of the shares of Ivanhoe Energy’s United States oil and gas operations for approximately $39.2 million in cash (including cash acquired), of which $2.0 million was held in escrow at September 30, 2009. In accordance with the purchase agreement, this amount will remain in escrow for one year from the closing of the transaction provided there are no pending disputes or actions regarding obligations and liabilities required to be satisfied or discharged by Ivanhoe Energy. Ivanhoe Energy’s United States oil and gas operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on July 20, 2009. As of the acquisition date, these assets produced approximately 645 (595 net) barrels per day of oil in California and Texas. The purchase also included certain exploration acreage in California. This acquisition adds to the Company’s existing oil producing assets in the Midway Sunset Field in California. The acquisition consisted of approximately $37.1 million in property, plant and equipment,
104113
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
Note L — | Intangible Assets |
$6.2 million of current assets (including $2.0 million of cash held in escrow), $0.3 million of current liabilities and $3.8 million of deferred credits. Details of the acquisition are as follows (all figures in thousands):
| | | | |
Assets Acquired | | $ | 43,282 | |
Liabilities Assumed | | | (4,082 | ) |
Cash Acquired at Acquisition | | | (4,267 | ) |
| | | | |
Cash Paid, Net of Cash Acquired | | $ | 34,933 | |
| | | | |
Note N — Intangible Assets
As a result of the Empire and Toro acquisitions in 2003, the Company acquired certain intangible assets during 2003.assets. In the case of the Empire acquisition, the intangible assets represent the fair value of various long-term transportation contracts with Empire’s customers. In the case of the Toro acquisition, the intangible assets represent the fair value of various long-term gas purchase contracts with the various landfills. These intangible assets are being amortized over the lives of the transportation and gas purchase contracts with no residual value at the end of the amortization period. The weighted-average amortization period for the gross carrying amount of the transportation contracts is 8 years. The weighted-average amortization period for the gross carrying amount of the gas purchase contracts is 20 years. Details of these intangible assets are as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | At September 30,
| | | | | At September 30,
| |
| | At September 30, 2008 | | 2007 | | | At September 30, 2009 | | 2008 | |
| | Gross Carrying
| | Accumulated
| | Net Carrying
| | Net Carrying
| | | Gross Carrying
| | Accumulated
| | Net Carrying
| | Net Carrying
| |
| | Amount | | Amortization | | Amount | | Amount | | | Amount | | Amortization | | Amount | | Amount | |
|
Intangible Assets Subject to Amortization: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Long-Term Transportation Contracts | | $ | 8,580 | | | $ | (6,058 | ) | | $ | 2,522 | | | $ | 3,591 | | | $ | 4,701 | | | $ | (2,630 | ) | | $ | 2,071 | | | $ | 2,522 | |
Long-Term Gas Purchase Contracts | | | 31,864 | | | | (8,212 | ) | | | 23,652 | | | | 25,245 | | | | 31,864 | | | | (12,399 | ) | | | 19,465 | | | | 23,652 | |
| | | | | | | | | | | | | | | | | | |
| | $ | 40,444 | | | $ | (14,270 | ) | | $ | 26,174 | | | $ | 28,836 | | | $ | 36,565 | | | $ | (15,029 | ) | | $ | 21,536 | | | $ | 26,174 | |
| | | | | | | | | | | | | | | | | | |
Aggregate Amortization Expense: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
For the Year Ended September 30, 2009 | | | $ | 4,638 | | | | | | | | | | | | | |
For the Year Ended September 30, 2008 | | $ | 2,662 | | | | | | | | | | | | | | | $ | 2,662 | | | | | | | | | | | | | |
For the Year Ended September 30, 2007 | | $ | 2,662 | | | | | | | | | | | | | | | $ | 2,662 | | | | | | | | | | | | | |
For the Year Ended September 30, 2006 | | $ | 2,662 | | | | | | | | | | | | | | |
In September 2009, the Company recorded a pre-tax impairment of $4.6 million in the value of certain long-lived assets in the All Other category due to the loss of the primary customer at one of Toro’s landfill gas sites and the anticipated shut-down of the site. The impairment was comprised of a $2.6 million reduction in intangible assets related to long-term gas purchase contracts and a $2.0 million reduction in property, plant and equipment. The $2.6 million intangible assets impairment was recorded to Purchased Gas expense and the $2.0 million property, plant and equipment impairment was recorded to Depreciation, Depletion and Amortization expense on the Consolidated Statement of Income. The $2.6 million impairment of the intangible asset is included in amortization expense for the year ended September 30, 2009 in the table shown above.
In October 2008, the Company completed the amortization of intangible assets related to two long-term transportation contracts. As such, the gross carrying amount of intangible assets subject to amortization was reduced from $8.6 million at September 30, 2008 remained unchanged fromto $4.7 million at September 30, 2007. The2009. Accumulated amortization was reduced by the same amount. Aside from this change, the only activity with regard to intangible assets subject to amortization was amortization expense as shown onin the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.5 million in 2009, and $0.4 million inannually for 2010, 2011,
114
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2012, 2013 and 2013.2014. Amortization expense for the long-term gas purchase contracts is estimated to be $1.6$1.4 million annually for 2009, 2010, 2011, 2012, 2013 and 2013.2014.
| |
Note M — | Quarterly Financial Data (unaudited) |
Note O — Quarterly Financial Data (unaudited)
In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.
105
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Net
| | | | | | | | | | |
| | | | | | | | | | Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Income
| | Income
| | Available
| | Earnings from
| | | | | | | | | | | Net
| | | | |
| | | | | | from
| | from
| | for
| | Continuing Operations per
| | | | | | | | | | | Income
| | Earnings per
|
Quarter
| | Operating
| | Operating
| | Continuing
| | Discontinued
| | Common
| | Common Share | | Earnings per Common Share | | | Operating
| | Operating
| | (Loss) Available for
| | Common Share |
Ended | | Revenues | | Income | | Operations | | Operations | | Stock | | Basic | | Diluted | | Basic | | Diluted | | | Revenues | | Income (Loss) | | Common Stock | | Basic | | Diluted |
| | (Thousands, except per common share amounts) | | | (Thousands, except per common share amounts) |
|
2009 | | | | | | | | | | | | | | | | |
9/30/2009 | | | $ | 278,933 | | | $ | 64,922 | | | $ | 26,998 | (1) | | $ | 0.34 | | | $ | 0.33 | |
6/30/2009 | | | $ | 367,111 | | | $ | 88,086 | | | $ | 42,904 | | | $ | 0.54 | | | $ | 0.53 | |
3/31/2009 | | | $ | 804,645 | | | $ | 138,642 | | | $ | 73,484 | | | $ | 0.92 | | | $ | 0.92 | |
12/31/2008 | | | $ | 607,163 | | | $ | (66,820 | ) | | $ | (42,678 | )(2) | | $ | (0.54 | ) | | $ | (0.53 | ) |
2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
9/30/2008 | | $ | 397,858 | | | $ | 79,149 | | | $ | 43,266 | | | $ | — | | | $ | 43,266 | | | $ | 0.54 | | | $ | 0.52 | | | $ | 0.54 | | | $ | 0.52 | | | $ | 397,858 | | | $ | 79,149 | | | $ | 43,266 | | | $ | 0.54 | | | $ | 0.52 | |
6/30/2008 | | $ | 548,382 | | | $ | 110,947 | | | $ | 59,855 | | | $ | — | | | $ | 59,855 | | | $ | 0.74 | | | $ | 0.72 | | | $ | 0.74 | | | $ | 0.72 | | | $ | 548,382 | | | $ | 110,947 | | | $ | 59,855 | | | $ | 0.74 | | | $ | 0.72 | |
3/31/2008 | | $ | 885,853 | | | $ | 170,020 | | | $ | 95,003 | (1) | | $ | — | | | $ | 95,003 | (1) | | $ | 1.14 | | | $ | 1.11 | | | $ | 1.14 | | | $ | 1.11 | | | $ | 885,853 | | | $ | 170,020 | | | $ | 95,003 | (3) | | $ | 1.14 | | | $ | 1.11 | |
12/31/2007 | | $ | 568,268 | | | $ | 126,009 | | | $ | 70,604 | | | $ | — | | | $ | 70,604 | | | $ | 0.84 | | | $ | 0.82 | | | $ | 0.84 | | | $ | 0.82 | | | $ | 568,268 | | | $ | 126,009 | | | $ | 70,604 | | | $ | 0.84 | | | $ | 0.82 | |
2007 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
9/30/2007 | | $ | 302,030 | | | $ | 73,504 | | | $ | 34,295 | | | $ | 123,395 | (2) | | $ | 157,690 | (2) | | $ | 0.41 | | | $ | 0.40 | | | $ | 1.89 | | | $ | 1.84 | | |
6/30/2007 | | $ | 448,779 | | | $ | 83,933 | | | $ | 41,212 | (3) | | $ | 5,586 | | | $ | 46,798 | (3) | | $ | 0.49 | | | $ | 0.48 | | | $ | 0.56 | | | $ | 0.55 | | |
3/31/2007 | | $ | 798,100 | | | $ | 142,404 | | | $ | 75,480 | (4) | | $ | 2,967 | | | $ | 78,447 | (4) | | $ | 0.91 | | | $ | 0.89 | | | $ | 0.95 | | | $ | 0.92 | | |
12/31/2006 | | $ | 490,657 | | | $ | 96,657 | | | $ | 50,688 | (5) | | $ | 3,832 | | | $ | 54,520 | (5) | | $ | 0.61 | | | $ | 0.60 | | | $ | 0.66 | | | $ | 0.64 | | |
| | |
(1) | | Includes a $0.6non-cash $4.6 million gain on sale of turbine.impairment charge ($2.8 million after tax) associated with landfill gas assets in the All Other category. |
|
(2) | | Includes a $120.3non-cash $182.8 million impairment charge ($108.2 million after tax) associated with the Exploration and Production segment’s oil and gas producing properties; a non-cash $1.8 million impairment charge ($1.1 million after tax) associated with an equity investment in the All Other category and a $2.3 million gain realized on life insurance policies in the sale of SECI.Corporate category. |
|
(3) | | Includes $4.8a $0.6 million of income associated withgain on the reversal of reserve for preliminary project costs associated with the Empire Connector project. |
|
(4) | | Includes $2.3 million of income associated with the reversalsale of a purchased gas expense accrual related to the resolution of a contingency. |
|
(5) | | Includes a $1.9 million positive earnings impact associated with the discontinuance of hedge accounting on an interest rate collar.turbine. |
| |
Note N — | Market for Common Stock and Related Shareholder Matters (unaudited) |
Note P — Market for Common Stock and Related Shareholder Matters (unaudited)
At September 30, 2008,2009, there were 16,54416,098 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note E — Capitalization and Short-Term Borrowings. The quarterly price ranges (based onintra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2008 and 2007, are shown below:
| | | | | | | | | | | | |
| | Price Range | | | | |
Quarter Ended | | High | | | Low | | | Dividends Declared | |
|
2008 | | | | | | | | | | | | |
9/30/2008 | | $ | 60.36 | | | $ | 39.16 | | | $ | .325 | |
6/30/2008 | | $ | 63.71 | | | $ | 47.00 | | | $ | .325 | |
3/31/2008 | | $ | 48.78 | | | $ | 38.04 | | | $ | .31 | |
12/31/2007 | | $ | 50.29 | | | $ | 45.20 | | | $ | .31 | |
2007 | | | | | | | | | | | | |
9/30/2007 | | $ | 47.00 | | | $ | 40.95 | | | $ | .31 | |
6/30/2007 | | $ | 47.87 | | | $ | 42.75 | | | $ | .31 | |
3/31/2007 | | $ | 43.79 | | | $ | 36.94 | | | $ | .30 | |
12/31/2006 | | $ | 40.21 | | | $ | 35.02 | | | $ | .30 | |
106
115
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
Note O — | Supplementary Information for Oil and Gas Producing Activities (unaudited) |
ranges (based onintra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2009 and 2008, are shown below:
| | | | | | | | | | | | |
| | Price Range | | |
Quarter Ended | | High | | Low | | Dividends Declared |
|
2009 | | | | | | | | | | | | |
9/30/2009 | | $ | 48.30 | | | $ | 33.77 | | | $ | .335 | |
6/30/2009 | | $ | 37.61 | | | $ | 29.83 | | | $ | .335 | |
3/31/2009 | | $ | 34.34 | | | $ | 26.67 | | | $ | .325 | |
12/31/2008 | | $ | 41.99 | | | $ | 26.83 | | | $ | .325 | |
2008 | | | | | | | | | | | | |
9/30/2008 | | $ | 60.36 | | | $ | 39.16 | | | $ | .325 | |
6/30/2008 | | $ | 63.71 | | | $ | 47.00 | | | $ | .325 | |
3/31/2008 | | $ | 48.78 | | | $ | 38.04 | | | $ | .31 | |
12/31/2007 | | $ | 50.29 | | | $ | 45.20 | | | $ | .31 | |
Note Q — Supplementary Information for Oil and Gas Producing Activities (unaudited)
The following supplementary information is presented in accordance with SFAS 69, “Disclosuresthe authoritative guidance regarding disclosures about Oiloil and Gas Producing Activities,”gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.
Capitalized Costs Relating to Oil and Gas Producing Activities
| | | | | | | | | | | | | | | | |
| | At September 30 | | | At September 30 | |
| | 2008 | | 2007 | | | 2009 | | 2008 | |
| | (Thousands) | | | (Thousands) | |
|
Proved Properties(1) | | $ | 1,783,276 | | | $ | 1,583,956 | | | $ | 1,953,720 | | | $ | 1,783,276 | |
Unproved Properties | | | 23,285 | | | | 20,005 | | | | 70,061 | | | | 23,285 | |
| | | | | | | | | | |
| | | 1,806,561 | | | | 1,603,961 | | | | 2,023,781 | | | | 1,806,561 | |
Less — Accumulated Depreciation, Depletion and Amortization | | | 718,166 | | | | 627,073 | | | | 990,284 | | | | 718,166 | |
| | | | | | | | | | |
| | $ | 1,088,395 | | | $ | 976,888 | | | $ | 1,033,497 | | | $ | 1,088,395 | |
| | | | | | | | | | |
| | |
(1) | | Includes asset retirement costs of $60.9$65.9 million and $40.9$60.9 million at September 30, 20082009 and 2007,2008, respectively. |
Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Following is a summary of costs excluded from amortization at September 30, 2008:
| | | | | | | | | | | | | | | | | | | | |
| | Total
| | | | | | | | | | | | | |
| | as of
| | | | | | | | | | | | | |
| | September 30,
| | | Year Costs Incurred | |
| | 2008 | | | 2008 | | | 2007 | | | 2006 | | | Prior | |
| | (Thousands) | |
|
Acquisition Costs | | $ | 23,285 | | | $ | 7,914 | | | $ | 2,433 | | | $ | 11,918 | | | $ | 1,020 | |
107116
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
capitalized costs being amortized. Following is a summary of costs excluded from amortization at September 30, 2009:
| | | | | | | | | | | | | | | | | | | | |
| | Total
| | | | | | | | | | | | | |
| | as of
| | | | | | | | | | | | | |
| | September 30,
| | | Year Costs Incurred | |
| | 2009 | | | 2009 | | | 2008 | | | 2007 | | | Prior | |
| | (Thousands) | |
|
Acquisition Costs | | $ | 63,708 | | | $ | 44,728 | | | $ | 6,342 | | | $ | 2,361 | | | $ | 10,277 | |
Development Costs | | | 6,353 | | | | 6,353 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
| | $ | 70,061 | (1) | | $ | 51,081 | | | $ | 6,342 | | | $ | 2,361 | | | $ | 10,277 | |
| | | | | | | | | | | | | | | | | | | | |
| | |
(1) | | Costs related to unproved properties excluded from amortization includes $52.3 million related to onshore properties and $17.8 million related to offshore properties at September 30, 2009. |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | (Thousands) | | | (Thousands) | |
|
United States | | | | | | | | | | | | | | | | | | | | | | | | |
Property Acquisition Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
Proved | | $ | 16,474 | | | $ | 2,621 | | | $ | 5,339 | | | $ | 35,803 | | | $ | 16,474 | | | $ | 2,621 | |
Unproved | | | 8,449 | | | | 3,210 | | | | 8,844 | | | | 44,528 | | | | 8,449 | | | | 3,210 | |
Exploration Costs | | | 56,274 | | | | 26,891 | | | | 64,087 | | | | 11,724 | | | | 56,274 | | | | 26,891 | |
Development Costs | | | 106,975 | | | | 113,206 | | | | 87,738 | | | | 125,109 | | | | 106,975 | | | | 113,206 | |
Asset Retirement Costs | | | 20,048 | | | | 2,139 | | | | 10,965 | | | | 2,877 | | | | 20,048 | | | | 2,139 | |
| | | | | | | | | | | | | | |
| | | 208,220 | | | | 148,067 | | | | 176,973 | | | | 220,041 | | | | 208,220 | | | | 148,067 | |
| | | | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | | | | | | | | | | | | | |
Property Acquisition Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
Proved | | | — | | | | (1,404 | ) | | | (427 | ) | | | — | | | | — | | | | (1,404 | ) |
Unproved | | | — | | | | (1,142 | ) | | | 6,492 | | | | — | | | | — | | | | (1,142 | ) |
Exploration Costs | | | — | | | | 20,134 | | | | 20,778 | | | | — | | | | — | | | | 20,134 | |
Development Costs | | | — | | | | 11,414 | | | | 14,385 | | | | — | | | | — | | | | 11,414 | |
Asset Retirement Costs | | | — | | | | 167 | | | | 279 | | | | — | | | | — | | | | 167 | |
| | | | | | | | | | | | | | |
| | | — | | | | 29,169 | | | | 41,507 | | | | — | | | | — | | | | 29,169 | |
| | | | | | | | | | | | | | |
Total | | | | | | | | | | | | | | | | | | | | | | | | |
Property Acquisition Costs: | | | | | | | | | | | | | | | | | | | | | | | | |
Proved | | | 16,474 | | | | 1,217 | | | | 4,912 | | | | 35,803 | | | | 16,474 | | | | 1,217 | |
Unproved | | | 8,449 | | | | 2,068 | | | | 15,336 | | | | 44,528 | | | | 8,449 | | | | 2,068 | |
Exploration Costs | | | 56,274 | | | | 47,025 | | | | 84,865 | | | | 11,724 | | | | 56,274 | | | | 47,025 | |
Development Costs | | | 106,975 | | | | 124,620 | | | | 102,123 | | | | 125,109 | | | | 106,975 | | | | 124,620 | |
Asset Retirement Costs | | | 20,048 | | | | 2,306 | | | | 11,244 | | | | 2,877 | | | | 20,048 | | | | 2,306 | |
| | | | | | | | | | | | | | |
| | $ | 208,220 | | | $ | 177,236 | | | $ | 218,480 | | | $ | 220,041 | | | $ | 208,220 | | | $ | 177,236 | |
| | | | | | | | | | | | | | |
For the years ended September 30, 2008, 2007 and 2006, the Company spent $25.4 million, $30.3 million and $55.6 million, respectively, developing proved undeveloped reserves.
108117
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the years ended September 30, 2009, 2008 and 2007, the Company spent $24.2 million, $25.4 million and $30.3 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | (Thousands, except per Mcfe amounts) | | | (Thousands, except per Mcfe amounts) | |
|
United States | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas (includes revenues from sales to affiliates of $443, $325 and $106, respectively) | | $ | 216,623 | | | $ | 135,399 | | | $ | 152,451 | | |
Natural Gas (includes revenues from sales to affiliates of $239, $443 and $325, respectively) | | | $ | 106,815 | | | $ | 216,623 | | | $ | 135,399 | |
Oil, Condensate and Other Liquids | | | 305,887 | | | | 189,539 | | | | 195,050 | | | | 174,356 | | | | 305,887 | | | | 189,539 | |
| | | | | | | | | | | | | | |
Total Operating Revenues(1) | | | 522,510 | | | | 324,938 | | | | 347,501 | | | | 281,171 | | | | 522,510 | | | | 324,938 | |
Production/Lifting Costs | | | 66,685 | | | | 48,410 | | | | 41,354 | | | | 62,614 | | | | 66,685 | | | | 48,410 | |
Accretion Expense | | | 4,056 | | | | 3,704 | | | | 2,412 | | | | 5,437 | | | | 4,056 | | | | 3,704 | |
Depreciation, Depletion and Amortization ($2.23, $1.97 and $1.74 per Mcfe of production) | | | 91,093 | | | | 77,452 | | | | 66,488 | | |
Income Tax Expense | | | 144,922 | | | | 78,928 | | | | 88,104 | | |
Depreciation, Depletion and Amortization ($2.10, $2.23 and $1.97 per Mcfe of production) | | | | 89,307 | | | | 91,093 | | | | 77,452 | |
Impairment of Oil and Gas Producing Properties(2) | | | | 182,811 | | | | — | | | | — | |
Income Tax Expense (Benefit) | | | | (27,055 | ) | | | 144,922 | | | | 78,928 | |
| | | | | | | | | | | | | | |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | | 215,754 | | | | 116,444 | | | | 149,143 | | | | (31,943 | ) | | | 215,754 | | | | 116,444 | |
| | | | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas | | | — | | | | 39,114 | | | | 54,819 | | | | — | | | | — | | | | 39,114 | |
Oil, Condensate and Other Liquids | | | — | | | | 10,313 | | | | 13,985 | | | | — | | | | — | | | | 10,313 | |
| | | | | | | | | | | | | | |
Total Operating Revenues(1) | | | — | | | | 49,427 | | | | 68,804 | | | | — | | | | — | | | | 49,427 | |
Production/Lifting Costs | | | — | | | | 14,846 | | | | 14,628 | | | | — | | | | — | | | | 14,846 | |
Accretion Expense | | | — | | | | 249 | | | | 258 | | | | — | | | | — | | | | 249 | |
Depreciation, Depletion and Amortization ($0, $1.67 and $2.95 per Mcfe of production) | | | — | | | | 12,787 | | | | 27,439 | | |
Impairment of Oil and Gas Producing Properties(2) | | | — | | | | — | | | | 104,739 | | |
Income Tax Expense (Benefit) | | | — | | | | 3,703 | | | | (31,987 | ) | |
Depreciation, Depletion and Amortization ($1.67 per Mcfe of production for 2007) | | | | — | | | | — | | | | 12,787 | |
Income Tax Expense | | | | — | | | | — | | | | 3,703 | |
| | | | | | | | | | | | | | |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | | — | | | | 17,842 | | | | (46,273 | ) | | | — | | | | — | | | | 17,842 | |
| | | | | | | | | | | | | | |
109118
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 | | | Year Ended September 30 | |
| | 2008 | | 2007 | | 2006 | | | 2009 | | 2008 | | 2007 | |
| | (Thousands, except per Mcfe amounts) | | | (Thousands, except per Mcfe amounts) | |
|
Total | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues: | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas (includes revenues from sales to affiliates of $443, $325 and $106, respectively) | | | 216,623 | | | | 174,513 | | | | 207,270 | | |
Natural Gas (includes revenues from sales to affiliates of $239, $443 and $325, respectively) | | | | 106,815 | | | | 216,623 | | | | 174,513 | |
Oil, Condensate and Other Liquids | | | 305,887 | | | | 199,852 | | | | 209,035 | | | | 174,356 | | | | 305,887 | | | | 199,852 | |
| | | | | | | | | | | | | | |
Total Operating Revenues(1) | | | 522,510 | | | | 374,365 | | | | 416,305 | | | | 281,171 | | | | 522,510 | | | | 374,365 | |
Production/Lifting Costs | | | 66,685 | | | | 63,256 | | | | 55,982 | | | | 62,614 | | | | 66,685 | | | | 63,256 | |
Accretion Expense | | | 4,056 | | | | 3,953 | | | | 2,670 | | | | 5,437 | | | | 4,056 | | | | 3,953 | |
Depreciation, Depletion and Amortization ($2.23, $1.92 and $1.98 per Mcfe of production) | | | 91,093 | | | | 90,239 | | | | 93,927 | | |
Depreciation, Depletion and Amortization ($2.10, $2.23 and $1.92 per Mcfe of production) | | | | 89,307 | | | | 91,093 | | | | 90,239 | |
Impairment of Oil and Gas Producing Properties(2) | | | — | | | | — | | | | 104,739 | | | | 182,811 | | | | — | | | | — | |
Income Tax Expense | | | 144,922 | | | | 82,631 | | | | 56,117 | | | | (27,055 | ) | | | 144,922 | | | | 82,631 | |
| | | | | | | | | | | | | | |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | | $ | 215,754 | | | $ | 134,286 | | | $ | 102,870 | | | $ | (31,943 | ) | | $ | 215,754 | | | $ | 134,286 | |
| | | | | | | | | | | | | | |
| | |
(1) | | Exclusive of hedging gains and losses. See further discussion in Note FG — Financial Instruments. |
|
(2) | | See discussion of impairment in Note A — Summary of Significant Accounting Policies. |
110119
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Reserve Quantity Information
The Company’s proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by qualified Company geologists and engineers and are audited by independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas MMcf | | | Gas MMcf | |
| | U. S. | | | | | | | U. S. | | | | | |
| | Gulf
| | West
| | | | | | Canada
| | | | | Gulf
| | West
| | | | | | Canada
| | | |
| | Coast
| | Coast
| | Appalachian
| | Total
| | (Discontinued
| | Total
| | | Coast
| | Coast
| | Appalachian
| | Total
| | (Discontinued
| | Total
| |
| | Region | | Region | | Region | | U.S. | | Operations) | | Company | | | Region | | Region | | Region | | U.S. | | Operations) | | Company | |
|
Proved Developed and Undeveloped Reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2005 | | | 38,470 | | | | 70,459 | | | | 83,125 | | | | 192,054 | | | | 46,086 | | | | 238,140 | | |
Extensions and Discoveries | | | 11,763 | | | | 1,815 | | | | 11,132 | | | | 24,710 | | | | 6,229 | | | | 30,939 | | |
Revisions of Previous Estimates | | | 679 | | | | 5,757 | | | | (7,776 | ) | | | (1,340 | ) | | | (11,096 | ) | | | (12,436 | ) | |
Production | | | (9,110 | ) | | | (3,880 | ) | | | (5,108 | ) | | | (18,098 | ) | | | (7,673 | ) | | | (25,771 | ) | |
Purchases of Minerals in Place | | | — | | | | 1,715 | | | | — | | | | 1,715 | | | | — | | | | 1,715 | | |
Sales of Minerals in Place | | | — | | | | — | | | | — | | | | — | | | | (12 | ) | | | (12 | ) | |
| | | | | | | | | | | | | | |
September 30, 2006 | | | 41,802 | | | | 75,866 | | | | 81,373 | | | | 199,041 | | | | 33,534 | | | | 232,575 | | | | 41,802 | | | | 75,866 | | | | 81,373 | | | | 199,041 | | | | 33,534 | | | | 232,575 | |
Extensions and Discoveries | | | 3,577 | | | | — | | | | 29,676 | | | | 33,253 | | | | 1,333 | | | | 34,586 | | | | 3,577 | | | | — | | | | 29,676 | | | | 33,253 | | | | 1,333 | | | | 34,586 | |
Revisions of Previous Estimates | | | (9,851 | ) | | | 1,238 | | | | 1,618 | | | | (6,995 | ) | | | 11,634 | | | | 4,639 | | | | (9,851 | ) | | | 1,238 | | | | 1,618 | | | | (6,995 | ) | | | 11,634 | | | | 4,639 | |
Production | | | (10,356 | ) | | | (3,929 | ) | | | (5,555 | ) | | | (19,840 | ) | | | (6,426 | ) | | | (26,266 | ) | | | (10,356 | ) | | | (3,929 | ) | | | (5,555 | ) | | | (19,840 | ) | | | (6,426 | ) | | | (26,266 | ) |
Sales of Minerals in Place | | | (36 | ) | | | — | | | | (34 | ) | | | (70 | ) | | | (40,075 | ) | | | (40,145 | ) | | | (36 | ) | | | — | | | | (34 | ) | | | (70 | ) | | | (40,075 | ) | | | (40,145 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2007 | | | 25,136 | | | | 73,175 | | | | 107,078 | | | | 205,389 | | | | — | | | | 205,389 | | | | 25,136 | | | | 73,175 | | | | 107,078 | | | | 205,389 | | | | — | | | | 205,389 | |
Extensions and Discoveries | | | 8,759 | | | | — | | | | 31,322 | | | | 40,081 | | | | — | | | | 40,081 | | | | 8,759 | | | | — | | | | 31,322 | | | | 40,081 | | | | — | | | | 40,081 | |
Revisions of Previous Estimates | | | 2,156 | | | | 566 | | | | (3,460 | ) | | | (738 | ) | | | — | | | | (738 | ) | | | 2,156 | | | | 566 | | | | (3,460 | ) | | | (738 | ) | | | — | | | | (738 | ) |
Production | | | (11,033 | ) | | | (4,039 | ) | | | (7,269 | ) | | | (22,341 | ) | | | — | | | | (22,341 | ) | | | (11,033 | ) | | | (4,039 | ) | | | (7,269 | ) | | | (22,341 | ) | | | — | | | | (22,341 | ) |
Purchases of Minerals in Place | | | — | | | | 4,539 | | | | 727 | | | | 5,266 | | | | — | | | | 5,266 | | | | — | | | | 4,539 | | | | 727 | | | | 5,266 | | | | — | | | | 5,266 | |
Sales of Minerals in Place | | | (377 | ) | | | (1,381 | ) | | | — | | | | (1,758 | ) | | | — | | | | (1,758 | ) | | | (377 | ) | | | (1,381 | ) | | | — | | | | (1,758 | ) | | | — | | | | (1,758 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2008 | | | 24,641 | | | | 72,860 | | | | 128,398 | | | | 225,899 | | | | — | | | | 225,899 | | | | 24,641 | | | | 72,860 | | | | 128,398 | | | | 225,899 | | | | — | | | | 225,899 | |
Extensions and Discoveries | | | | 6,698 | | | | 3,282 | | | | 49,249 | | | | 59,229 | | | | — | | | | 59,229 | |
Revisions of Previous Estimates | | | | 9,407 | | | | 488 | | | | (19,484 | ) | | | (9,589 | ) | | | — | | | | (9,589 | )(1) |
Production | | | | (9,886 | ) | | | (4,063 | ) | | | (8,335 | ) | | | (22,284 | ) | | | — | | | | (22,284 | ) |
Purchases of Minerals in Place | | | | — | | | | 392 | | | | — | | | | 392 | | | | — | | | | 392 | |
Sales of Minerals in Place | | | | (4,693 | ) | | | — | | | | — | | | | (4,693 | ) | | | — | | | | (4,693 | ) |
| | | | | | | | | | | | | | |
September 30, 2009 | | | | 26,167 | | | | 72,959 | | | | 149,828 | | | | 248,954 | | | | — | | | | 248,954 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2005 | | | 23,108 | | | | 58,692 | | | | 83,125 | | | | 164,925 | | | | 43,980 | | | | 208,905 | | |
September 30, 2006 | | | 32,345 | | | | 64,196 | | | | 81,373 | | | | 177,914 | | | | 33,534 | | | | 211,448 | | | | 32,345 | | | | 64,196 | | | | 81,373 | | | | 177,914 | | | | 33,534 | | | | 211,448 | |
September 30, 2007 | | | 25,136 | | | | 66,017 | | | | 96,674 | | | | 187,827 | | | | — | | | | 187,827 | | | | 25,136 | | | | 66,017 | | | | 96,674 | | | | 187,827 | | | | — | | | | 187,827 | |
September 30, 2008 | | | 18,242 | | | | 68,453 | | | | 115,824 | | | | 202,519 | | | | — | | | | 202,519 | | | | 18,242 | | | | 68,453 | | | | 115,824 | | | | 202,519 | | | | — | | | | 202,519 | |
September 30, 2009 | | | | 18,051 | | | | 67,603 | | | | 120,579 | | | | 206,233 | | | | — | | | | 206,233 | |
| | |
(1) | | During 2009, the Company made a downward revision of its proved developed and undeveloped reserves amounting to 9,589 MMcf. This was primarily attributable to a 19,484 MMcf reduction in the Appalachian |
111120
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Oil Mbbl | |
| | U. S. | | | | | | | |
| | Gulf
| | | West
| | | | | | | | | Canada
| | | | |
| | Coast
| | | Coast
| | | Appalachian
| | | Total
| | | (Discontinued
| | | Total
| |
| | Region | | | Region | | | Region | | | U.S. | | | Operations) | | | Company | |
|
Proved Developed and Undeveloped Reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2005 | | | 1,295 | | | | 57,085 | | | | 177 | | | | 58,557 | | | | 1,700 | | | | 60,257 | |
Extensions and Discoveries | | | 39 | | | | 172 | | | | 108 | | | | 319 | | | | 128 | | | | 447 | |
Revisions of Previous Estimates | | | 595 | | | | (80 | ) | | | 57 | | | | 572 | | | | 101 | | | | 673 | |
Production | | | (685 | ) | | | (2,582 | ) | | | (69 | ) | | | (3,336 | ) | | | (272 | ) | | | (3,608 | ) |
Purchases of Minerals in Place | | | — | | | | 274 | | | | — | | | | 274 | | | | — | | | | 274 | |
Sales of Minerals in Place | | | — | | | | — | | | | — | | | | — | | | | (25 | ) | | | (25 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2006 | | | 1,244 | | | | 54,869 | | | | 273 | | | | 56,386 | | | | 1,632 | | | | 58,018 | |
Extensions and Discoveries | | | 63 | | | | — | | | | 281 | | | | 344 | | | | 108 | | | | 452 | |
Revisions of Previous Estimates | | | 851 | | | | (6,822 | ) | | | 84 | | | | (5,887 | ) | | | (76 | ) | | | (5,963 | ) |
Production | | | (717 | ) | | | (2,403 | ) | | | (124 | ) | | | (3,244 | ) | | | (206 | ) | | | (3,450 | ) |
Sales of Minerals in Place | | | (6 | ) | | | — | | | | (7 | ) | | | (13 | ) | | | (1,458 | ) | | | (1,471 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2007 | | | 1,435 | | | | 45,644 | | | | 507 | | | | 47,586 | | | | — | | | | 47,586 | |
Extensions and Discoveries | | | 298 | | | | 471 | | | | 58 | | | | 827 | | | | — | | | | 827 | |
Revisions of Previous Estimates | | | 203 | | | | (34 | ) | | | (64 | ) | | | 105 | | | | — | | | | 105 | |
Production | | | (505 | ) | | | (2,460 | ) | | | (105 | ) | | | (3,070 | ) | | | — | | | | (3,070 | ) |
Purchases of Minerals in Place | | | — | | | | 2,084 | | | | — | | | | 2,084 | | | | — | | | | 2,084 | |
Sales of Minerals in Place | | | (73 | ) | | | (1,261 | ) | | | — | | | | (1,334 | ) | | | — | | | | (1,334 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2008 | | | 1,358 | | | | 44,444 | | | | 396 | | | | 46,198 | | | | — | | | | 46,198 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2005 | | | 1,229 | | | | 41,701 | | | | 177 | | | | 43,107 | | | | 1,700 | | | | 44,807 | |
September 30, 2006 | | | 1,217 | | | | 42,522 | | | | 273 | | | | 44,012 | | | | 1,632 | | | | 45,644 | |
September 30, 2007 | | | 1,435 | | | | 36,509 | | | | 483 | | | | 38,427 | | | | — | | | | 38,427 | |
September 30, 2008 | | | 1,313 | | | | 37,224 | | | | 357 | | | | 38,894 | | | | — | | | | 38,894 | |
| | |
| | region offset by a 9,407 MMcf increase in the Gulf Coast region. The reduction in the Appalachian region was mainly due to declining natural gas prices, which made certain reserves uneconomical. The improvement in the Gulf Coast region was due to improved performance of Gulf Coast properties. |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Oil Mbbl | |
| | U. S. | | | | | | | |
| | Gulf
| | | West
| | | | | | | | | Canada
| | | | |
| | Coast
| | | Coast
| | | Appalachian
| | | Total
| | | (Discontinued
| | | Total
| |
| | Region | | | Region | | | Region | | | U.S. | | | Operations) | | | Company | |
|
Proved Developed and Undeveloped Reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2006 | | | 1,244 | | | | 54,869 | | | | 273 | | | | 56,386 | | | | 1,632 | | | | 58,018 | |
Extensions and Discoveries | | | 63 | | | | — | | | | 281 | | | | 344 | | | | 108 | | | | 452 | |
Revisions of Previous Estimates | | | 851 | | | | (6,822 | ) | | | 84 | | | | (5,887 | ) | | | (76 | ) | | | (5,963 | ) |
Production | | | (717 | ) | | | (2,403 | ) | | | (124 | ) | | | (3,244 | ) | | | (206 | ) | | | (3,450 | ) |
Sales of Minerals in Place | | | (6 | ) | | | — | | | | (7 | ) | | | (13 | ) | | | (1,458 | ) | | | (1,471 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2007 | | | 1,435 | | | | 45,644 | | | | 507 | | | | 47,586 | | | | — | | | | 47,586 | |
Extensions and Discoveries | | | 298 | | | | 471 | | | | 58 | | | | 827 | | | | — | | | | 827 | |
Revisions of Previous Estimates | | | 203 | | | | (34 | ) | | | (64 | ) | | | 105 | | | | — | | | | 105 | |
Production | | | (505 | ) | | | (2,460 | ) | | | (105 | ) | | | (3,070 | ) | | | — | | | | (3,070 | ) |
Purchases of Minerals in Place | | | — | | | | 2,084 | | | | — | | | | 2,084 | | | | — | | | | 2,084 | |
Sales of Minerals in Place | | | (73 | ) | | | (1,261 | ) | | | — | | | | (1,334 | ) | | | — | | | | (1,334 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2008 | | | 1,358 | | | | 44,444 | | | | 396 | | | | 46,198 | | | | — | | | | 46,198 | |
Extensions and Discoveries | | | 302 | | | | 896 | | | | 15 | | | | 1,213 | | | | — | | | | 1,213 | |
Revisions of Previous Estimates | | | 447 | | | | 43 | | | | (41 | ) | | | 449 | | | | — | | | | 449 | |
Production | | | (640 | ) | | | (2,674 | ) | | | (59 | ) | | | (3,373 | ) | | | — | | | | (3,373 | ) |
Purchases of Minerals in Place | | | — | | | | 2,115 | | | | — | | | | 2,115 | | | | — | | | | 2,115 | |
Sales of Minerals in Place | | | (15 | ) | | | — | | | | — | | | | (15 | ) | | | — | | | | (15 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2009 | | | 1,452 | | | | 44,824 | | | | 311 | | | | 46,587 | | | | — | | | | 46,587 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Proved Developed Reserves: | | | | | | | | | | | | | | | | | | | | | | | | |
September 30, 2006 | | | 1,217 | | | | 42,522 | | | | 273 | | | | 44,012 | | | | 1,632 | | | | 45,644 | |
September 30, 2007 | | | 1,435 | | | | 36,509 | | | | 483 | | | | 38,427 | | | | — | | | | 38,427 | |
September 30, 2008 | | | 1,313 | | | | 37,224 | | | | 357 | | | | 38,894 | | | | — | | | | 38,894 | |
September 30, 2009 | | | 1,194 | | | | 37,711 | | | | 285 | | | | 39,190 | | | | — | | | | 39,190 | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
121
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
| | (Thousands) | |
|
United States | | | | | | | | | | | | |
Future Cash Inflows | | $ | 3,972,026 | | | $ | 5,845,214 | | | $ | 4,879,496 | |
Less: | | | | | | | | | | | | |
Future Production Costs | | | 1,010,851 | | | | 1,231,705 | | | | 872,536 | |
Future Development Costs | | | 312,717 | | | | 265,515 | | | | 229,987 | |
Future Income Tax Expense at Applicable Statutory Rate | | | 916,466 | | | | 1,645,351 | | | | 1,423,707 | |
| | | | | | | | | | | | |
Future Net Cash Flows | | | 1,731,992 | | | | 2,702,643 | | | | 2,353,266 | |
Less: | | | | | | | | | | | | |
10% Annual Discount for Estimated Timing of Cash Flows | | | 856,015 | | | | 1,434,799 | | | | 1,292,804 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows | | $ | 875,977 | | | $ | 1,267,844 | | | $ | 1,060,462 | |
| | | | | | | | | | | | |
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
| | (Thousands) | |
|
United States | | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | | $ | 1,267,844 | | | $ | 1,060,462 | | | $ | 861,659 | |
Sales, Net of Production Costs | | | (218,557 | ) | | | (455,825 | ) | | | (276,529 | ) |
Net Changes in Prices, Net of Production Costs | | | (699,217 | ) | | | 509,705 | | | | 539,895 | |
Purchases of Minerals in Place | | | 38,902 | | | | 67,768 | | | | — | |
Sales of Minerals in Place | | | (20,141 | ) | | | (31,642 | ) | | | 484 | |
Extensions and Discoveries | | | 66,002 | | | | 143,394 | | | | 98,751 | |
Changes in Estimated Future Development Costs | | | (22,392 | ) | | | (100,684 | ) | | | (83,199 | ) |
Previously Estimated Development Costs Incurred | | | 53,285 | | | | 65,156 | | | | 58,710 | |
Net Change in Income Taxes at Applicable Statutory Rate | | | 331,251 | | | | (119,585 | ) | | | (174,920 | ) |
Revisions of Previous Quantity Estimates | | | (27,864 | ) | | | (3,936 | ) | | | (140,203 | ) |
Accretion of Discount and Other | | | 106,864 | | | | 133,031 | | | | 175,814 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | | | 875,977 | | | | 1,267,844 | | | | 1,060,462 | |
| | | | | | | | | | | | |
112
122
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands) | |
|
United States | | | | | | | | | | | | |
Future Cash Inflows | | $ | 5,845,214 | | | $ | 4,879,496 | | | $ | 3,911,059 | |
Less: | | | | | | | | | | | | |
Future Production Costs | | | 1,231,705 | | | | 872,536 | | | | 758,258 | |
Future Development Costs | | | 265,515 | | | | 229,987 | | | | 205,497 | |
Future Income Tax Expense at Applicable Statutory Rate | | | 1,645,351 | | | | 1,423,707 | | | | 1,019,307 | |
| | | | | | | | | | | | |
Future Net Cash Flows | | | 2,702,643 | | | | 2,353,266 | | | | 1,927,997 | |
Less: | | | | | | | | | | | | |
10% Annual Discount for Estimated Timing of Cash Flows | | | 1,434,799 | | | | 1,292,804 | | | | 1,066,338 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows | | | 1,267,844 | | | | 1,060,462 | | | | 861,659 | |
| | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | |
Future Cash Inflows | | | — | | | | — | | | | 197,227 | |
Less: | | | | | | | | | | | | |
Future Production Costs | | | — | | | | — | | | | 92,234 | |
Future Development Costs | | | — | | | | — | | | | 11,520 | |
Future Income Tax Expense at Applicable Statutory Rate | | | — | | | | — | | | | (151 | ) |
| | | | | | | | | | | | |
Future Net Cash Flows | | | — | | | | — | | | | 93,624 | |
Less: | | | | | | | | | | | | |
10% Annual Discount for Estimated Timing of Cash Flows | | | — | | | | — | | | | 19,375 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows | | | — | | | �� | — | | | | 74,249 | |
| | | | | | | | | | | | |
Total | | | | | | | | | | | | |
Future Cash Inflows | | | 5,845,214 | | | | 4,879,496 | | | | 4,108,286 | |
Less: | | | | | | | | | | | | |
Future Production Costs | | | 1,231,705 | | | | 872,536 | | | | 850,492 | |
Future Development Costs | | | 265,515 | | | | 229,987 | | | | 217,017 | |
Future Income Tax Expense at Applicable Statutory Rate | | | 1,645,351 | | | | 1,423,707 | | | | 1,019,156 | |
| | | | | | | | | | | | |
Future Net Cash Flows | | | 2,702,643 | | | | 2,353,266 | | | | 2,021,621 | |
Less: | | | | | | | | | | | | |
10% Annual Discount for Estimated Timing of Cash Flows | | | 1,434,799 | | | | 1,292,804 | | | | 1,085,713 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows | | $ | 1,267,844 | | | $ | 1,060,462 | | | $ | 935,908 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2009 | | | 2008 | | | 2007 | |
| | (Thousands) | |
|
Canada — Discontinued Operations | | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | | | — | | | | — | | | | 74,249 | |
Sales, Net of Production Costs | | | — | | | | — | | | | (34,581 | ) |
Net Changes in Prices, Net of Production Costs | | | — | | | | — | | | | 35,628 | |
Sales of Minerals in Place | | | — | | | | — | | | | (151,236 | ) |
Extensions and Discoveries | | | — | | | | — | | | | 6,908 | |
Changes in Estimated Future Development Costs | | | — | | | | — | | | | 5,722 | |
Previously Estimated Development Costs Incurred | | | — | | | | — | | | | 5,798 | |
Net Change in Income Taxes at Applicable Statutory Rate | | | — | | | | — | | | | (10,075 | ) |
Revisions of Previous Quantity Estimates | | | — | | | | — | | | | 34,998 | |
Accretion of Discount and Other | | | — | | | | — | | | | 32,589 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | | | — | | | | — | | | | — | |
| | | | | | | | | | | | |
Total | | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | | | 1,267,844 | | | | 1,060,462 | | | | 935,908 | |
Sales, Net of Production Costs | | | (218,557 | ) | | | (455,825 | ) | | | (311,110 | ) |
Net Changes in Prices, Net of Production Costs | | | (699,217 | ) | | | 509,705 | | | | 575,523 | |
Purchases of Minerals in Place | | | 38,902 | | | | 67,768 | | | | — | |
Sales of Minerals in Place | | | (20,141 | ) | | | (31,642 | ) | | | (150,752 | ) |
Extensions and Discoveries | | | 66,002 | | | | 143,394 | | | | 105,659 | |
Changes in Estimated Future Development Costs | | | (22,392 | ) | | | (100,684 | ) | | | (77,477 | ) |
Previously Estimated Development Costs Incurred | | | 53,285 | | | | 65,156 | | | | 64,508 | |
Net Change in Income Taxes at Applicable Statutory Rate | | | 331,251 | | | | (119,585 | ) | | | (184,995 | ) |
Revisions of Previous Quantity Estimates | | | (27,864 | ) | | | (3,936 | ) | | | (105,205 | ) |
Accretion of Discount and Other | | | 106,864 | | | | 133,031 | | | | 208,403 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | | $ | 875,977 | | | $ | 1,267,844 | | | $ | 1,060,462 | |
| | | | | | | | | | | | |
Note R — Subsequent Events
In accordance with the authoritative guidance for subsequent events, the Company has evaluated subsequent events through November 25, 2009, which represents the filing date of thisForm 10-K with the SEC, in order to ensure that thisForm 10-K includes appropriate disclosure of events both recognized in the financial statements as of September 30, 2009, and events which occurred subsequent to September 30, 2009 but were
113123
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The principal sources of changenot recognized in the standardized measurefinancial statements. As of discounted future net cash flowsNovember 25, 2009, there were as follows:
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands) | |
|
United States | | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | | $ | 1,060,462 | | | $ | 861,659 | | | $ | 1,491,532 | |
Sales, Net of Production Costs | | | (455,825 | ) | | | (276,529 | ) | | | (306,147 | ) |
Net Changes in Prices, Net of Production Costs | | | 509,705 | | | | 539,895 | | | | (941,545 | ) |
Purchases of Minerals in Place | | | 67,768 | | | | — | | | | 7,607 | |
Sales of Minerals in Place | | | (31,642 | ) | | | 484 | | | | — | |
Extensions and Discoveries | | | 143,394 | | | | 98,751 | | | | 66,975 | |
Changes in Estimated Future Development Costs | | | (100,684 | ) | | | (83,199 | ) | | | (83,750 | ) |
Previously Estimated Development Costs Incurred | | | 65,156 | | | | 58,710 | | | | 67,048 | |
Net Change in Income Taxes at Applicable Statutory Rate | | | (119,585 | ) | | | (174,920 | ) | | | 404,176 | |
Revisions of Previous Quantity Estimates | | | (3,936 | ) | | | (140,203 | ) | | | 4,850 | |
Accretion of Discount and Other | | | 133,031 | | | | 175,814 | | | | 150,913 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | | | 1,267,844 | | | | 1,060,462 | | | | 861,659 | |
| | | | | | | | | | | | |
Canada — Discontinued Operations | | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | | | — | | | | 74,249 | | | | 206,643 | |
Sales, Net of Production Costs | | | — | | | | (34,581 | ) | | | (54,176 | ) |
Net Changes in Prices, Net of Production Costs | | | — | | | | 35,628 | | | | (180,216 | ) |
Sales of Minerals in Place | | | — | | | | (151,236 | ) | | | (238 | ) |
Extensions and Discoveries | | | — | | | | 6,908 | | | | 10,369 | |
Changes in Estimated Future Development Costs | | | — | | | | 5,722 | | | | (3,282 | ) |
Previously Estimated Development Costs Incurred | | | — | | | | 5,798 | | | | 4,450 | |
Net Change in Income Taxes at Applicable Statutory Rate | | | — | | | | (10,075 | ) | | | 82,966 | |
Revisions of Previous Quantity Estimates | | | — | | | | 34,998 | | | | (15,478 | ) |
Accretion of Discount and Other | | | — | | | | 32,589 | | | | 23,211 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | | | — | | | | — | | | | 74,249 | |
| | | | | | | | | | | | |
114
NATIONAL FUEL GAS COMPANY
no subsequent events which required recognition or disclosure.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | |
| | Year Ended September 30 | |
| | 2008 | | | 2007 | | | 2006 | |
| | (Thousands) | |
|
Total | | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | | | 1,060,462 | | | | 935,908 | | | | 1,698,175 | |
Sales, Net of Production Costs | | | (455,825 | ) | | | (311,110 | ) | | | (360,323 | ) |
Net Changes in Prices, Net of Production Costs | | | 509,705 | | | | 575,523 | | | | (1,121,761 | ) |
Purchases of Minerals in Place | | | 67,768 | | | | — | | | | 7,607 | |
Sales of Minerals in Place | | | (31,642 | ) | | | (150,752 | ) | | | (238 | ) |
Extensions and Discoveries | | | 143,394 | | | | 105,659 | | | | 77,344 | |
Changes in Estimated Future Development Costs | | | (100,684 | ) | | | (77,477 | ) | | | (87,032 | ) |
Previously Estimated Development Costs Incurred | | | 65,156 | | | | 64,508 | | | | 71,498 | |
Net Change in Income Taxes at Applicable Statutory Rate | | | (119,585 | ) | | | (184,995 | ) | | | 487,142 | |
Revisions of Previous Quantity Estimates | | | (3,936 | ) | | | (105,205 | ) | | | (10,628 | ) |
Accretion of Discount and Other | | | 133,031 | | | | 208,403 | | | | 174,124 | |
| | | | | | | | | | | | |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | | $ | 1,267,844 | | | $ | 1,060,462 | | | $ | 935,908 | |
| | | | | | | | | | | | |
Schedule II — Valuation and Qualifying Accounts
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Additions
| | | | | | | | | | | Additions
| | | | | | | |
| | Balance
| | Charged
| | Additions
| | | | Balance
| | | Balance
| | Charged
| | Additions
| | | | Balance
| |
| | at
| | to
| | Charged
| | | | at
| | | at
| | to
| | Charged
| | | | at
| |
| | Beginning
| | Costs
| | to
| | | | End
| | | Beginning
| | Costs
| | to
| | | | End
| |
| | of
| | and
| | Other
| | | | of
| | | of
| | and
| | Other
| | | | of
| |
Description | | Period | | Expenses | | Accounts(1) | | Deductions(2) | | Period | | | Period | | Expenses | | Accounts(1) | | Deductions(2) | | Period | |
| | (Thousands) | | | (Thousands) | |
|
Year Ended September 30, 2009 | | | | | | | | | | | | | | | | | | | | | |
Allowance for Uncollectible Accounts | | | $ | 33,117 | | | $ | 31,464 | | | $ | 2,751 | | | $ | 28,998 | | | $ | 38,334 | |
| | | | | | | | | | | | |
Year Ended September 30, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Uncollectible Accounts | | $ | 28,654 | | | $ | 27,274 | | | $ | 2,734 | | | $ | 25,545 | | | $ | 33,117 | | | $ | 28,654 | | | $ | 27,274 | | | $ | 2,734 | | | $ | 25,545 | | | $ | 33,117 | |
| | | | | | | | | | | | | | | | | | | | | | |
Year Ended September 30, 2007 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Uncollectible Accounts | | $ | 31,427 | | | $ | 27,652 | | | $ | 1,414 | | | $ | 31,839 | | | $ | 28,654 | | | $ | 31,427 | | | $ | 27,652 | | | $ | 1,414 | | | $ | 31,839 | | | $ | 28,654 | |
| | | | | | | | | | | | | | | | | | | | | | |
Year Ended September 30, 2006 | | | | | | | | | | | | | | | | | | | | | |
Allowance for Uncollectible Accounts | | $ | 26,940 | | | $ | 29,088 | | | $ | 907 | | | $ | 25,508 | | | $ | 31,427 | | |
Deferred Tax Valuation Allowance | | $ | 2,877 | | | $ | (2,877 | ) | | $ | — | | | $ | — | | | $ | — | | |
| | | | | | | | | | | | |
| | |
(1) | | Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement. |
|
(2) | | Amounts represent net accounts receivable written-off. |
115
124
| |
Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None
| |
Item 9A | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
The term “disclosure controls and procedures” is defined inRules 13a-15(e) and15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2008.2009.
Management’s Annual Report on Internal Control over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined inRules 13a-15(f) and15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008.2009. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control — Integrated Framework.Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, 2008.2009.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report onForm 10-K, has issued aan attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, 2008.2009. The report appears in Part II, Item 8 of this Annual Report onForm 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 20082009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
| |
Item 9B | Other Information |
None
PART III
| |
Item 10 | Directors, Executive Officers and Corporate Governance |
The information required by this item concerning the directors of the Company and corporate governance is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010
116125
Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning directors iswill be set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in 2013,” “Directors Whose Terms Expire in 2012,” “Directors Whose Terms Expire in 2011,” “Directors Whose Terms Expire in 2010,” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated herein by reference. The information concerning corporate governance is set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.
The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the Company’s Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.
The Company intends to satisfy the disclosure requirement under Item 5.05 ofForm 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’sRegulation S-K, by posting such information on its website, www.nationalfuelgas.com.
| |
Item 11 | Executive Compensation |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning executive compensation iswill be set forth in the definitive Proxy Statement under the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee,” is incorporated herein by reference.
| |
Item 12 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Equity Compensation Plan Information
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The equity compensation plan information iswill be set forth in the definitive Proxy Statement under the heading “Equity Compensation Plan Information” and is incorporated herein by reference.
Security Ownership and Changes in Control
| |
(a) | Security Ownership of Certain Beneficial Owners |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning security ownership of certain beneficial owners iswill be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
| |
(b) | Security Ownership of Management |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning security ownership of
117126
management iswill be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
None
| |
Item 13 | Certain Relationships and Related Transactions, and Director Independence |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information regarding certain relationships and related transactions iswill be set forth in the definitive Proxy Statement under the headings “Compensation Committee Interlocks and Insider Participation” and “Related Person Transactions” and is incorporated herein by reference. The information regarding director independence is set forth in the definitive Proxy Statement under the heading “Director Independence” and is incorporated herein by reference.
| |
Item 14 | Principal Accountant Fees and Services |
The information required by this item is omitted pursuant to Instruction G ofForm 10-K since the Company’s definitive Proxy Statement for its 20092010 Annual Meeting of Stockholders will be filed with the SEC not later than 120 days after September 30, 2008.2009. The information concerning principal accountant fees and services iswill be set forth in the definitive Proxy Statement under the heading “Audit Fees” and is incorporated herein by reference.
PART IV
| |
Item 15 | Exhibits and Financial Statement Schedules |
(a)1. Financial Statements
Financial statements filed as part of this report are listed in the index included in Item 8 of thisForm 10-K, and reference is made thereto.
(a)2. Financial Statement Schedules
Financial statement schedules filed as part of this report are listed in the index included in Item 8 of thisForm 10-K, and reference is made thereto.
(a)3. Exhibits
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| 3(i) | | | Articles of Incorporation: |
| • | | | Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880) |
| • | | | Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 3(ii),Form 8-K dated March 14, 2005 in FileNo. 1-3880) |
| 3(ii) | | | By-Laws: |
| • | | | National Fuel Gas Company By-Laws as amended June 11, 2008 (Exhibit 3.1,Form 8-K dated June 16, 2008 in FileNo. 1-3880) |
| 4 | | | Instruments Defining the Rights of Security Holders, Including Indentures: |
| • | | | Indenture, dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in FileNo. 2-51796) |
118
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| • | | | Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in FileNo. 33-49401) |
| • | | | Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b),Form 8-K dated February 14, 1992 in FileNo. 1-3880) |
| • | | | Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c),Form 8-K dated June 18, 1992 in FileNo. 1-3880) |
| • | | | Thirteenth Supplemental Indenture, dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in FileNo. 33-49401) |
| • | | | Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in FileNo. 1-3880) |
| • | | | Fifteenth Supplemental Indenture, dated as of September 1, 1996, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| • | | | Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4,Form 10-Q for the quarterly period ended March 31, 2003 in FileNo. 1-3880) |
| • | | | Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008 (Exhibit 4.1,Form 10-Q for the quarterly period ended June 30, 2008 in FileNo. 1-3880) |
| • | | | Amended and Restated Rights Agreement, dated as of July 11, 2008, between the Company and The Bank of New York, as rights agent (Exhibit 4.1,Form 8-K dated July 15, 2008 in FileNo. 1-3880) |
| 10 | | | Material Contracts: |
| • | | | Credit Agreement, dated as of August 19, 2005, among the Company, the Lenders Party Thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
| • | | | Form of Indemnification Agreement, dated September 2006, between the Company and each Director (Exhibit 10.1,Form 8-K dated September 18, 2006 in FileNo. 1-3880) |
| • | | | Settlement Agreement dated January 24, 2008 among the Company, New Mountain Vantage GP, L.L.C. (“Vantage”) and certain of Vantage’s affiliates (Exhibit 10.1,Form 8-K dated January 24, 2008 in FileNo. 1-3880) |
| • | | | Director Services Agreement, dated as of June 1, 2008, between the Company and Philip C. Ackerman (Exhibit 99,Form 8-K dated June 16, 2008 in FileNo. 1-3880) |
| • | | | Resolutions adopted by the National Fuel Gas Company Board of Directors on February 21, 2008 regarding director stock ownership guidelines (Exhibit 10.5,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| 10 | .1 | | Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and each of Karen M. Camiolo, Carl M. Carlotti, Anna Marie Cellino, Paula M. Ciprich, Donna L. DeCarolis, John R. Pustulka, James D. Ramsdell, David F. Smith and Ronald J. Tanski |
| 10 | .2 | | Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, Seneca Resources Corporation and Matthew D. Cabell |
| • | | | Letter Agreement between the Company and Matthew D. Cabell, dated November 17, 2006 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
119
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| • | | | National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1993 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 1996 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company 1993 Award and Option Plan, amended through June 14, 2001 (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2001 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company 1993 Award and Option Plan, amended through September 8, 2005 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
| • | | | Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company 1997 Award and Option Plan, as amended and restated as of July 23, 2007 (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| • | | | Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated March 28, 2005 in FileNo. 1-3880) |
| • | | | Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated May 16, 2006 in FileNo. 1-3880) |
| • | | | Form of Restricted Stock Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| • | | | Form of Stock Option Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| • | | | Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2008 inFile No. 1-3880) |
| • | | | Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
| 10 | .3 | | Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program |
| • | | | Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.8,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| • | | | Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2007 in FileNo. 1-3880) |
| 10 | .4 | | National Fuel Gas Company Executive Annual Cash Incentive Program |
| • | | | Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective February 20, 2008 (Exhibit 10.3,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 1994 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
120127
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| • | | | Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in FileNo. 33-49401) |
| • | | | Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b),Form 8-K dated February 14, 1992 in FileNo. 1-3880) |
| • | | | Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c),Form 8-K dated June 18, 1992 in FileNo. 1-3880) |
| • | | | Thirteenth Supplemental Indenture, dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(14) in FileNo. 33-49401) |
| • | | | Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in FileNo. 1-3880) |
| • | | | Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4,Form 10-Q for the quarterly period ended March 31, 2003 in FileNo. 1-3880) |
| • | | | Officer’s Certificate establishing 6.50% Notes due 2018, dated April 11, 2008 (Exhibit 4.1,Form 10-Q for the quarterly period ended June 30, 2008 in FileNo. 1-3880) |
| • | | | Officer’s Certificate establishing 8.75% Notes due 2019, dated April 6, 2009 (Exhibit 4.4,Form 8-K dated April 6, 2009 in FileNo. 1-3880) |
| • | | | Amended and Restated Rights Agreement, dated as of December 4, 2008, between the Company and The Bank of New York, as rights agent (Exhibit 4.1,Form 8-K dated December 4, 2008 in FileNo. 1-3880) |
| 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) |
| • | | | Agreement to Extend Duration of Director Services Agreement, dated June 1, 2009, between the Company and Philip C. Ackerman (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2009 in FileNo. 1-3880) |
| • | | | Resolutions adopted by the National Fuel Gas Company Board of Directors on February 21, 2008 regarding director stock ownership guidelines (Exhibit 10.5,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| | | | Management Contracts and Compensatory Plans and Arrangements: |
128
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| • | | | Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and each of Karen M. Camiolo, Carl M. Carlotti, Anna Marie Cellino, Paula M. Ciprich, Donna L. DeCarolis, John R. Pustulka, James D. Ramsdell, David F. Smith and Ronald J. Tanski (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| • | | | Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, Seneca Resources Corporation and Matthew D. Cabell (Exhibit 10.2,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| • | | | Letter Agreement between the Company and Matthew D. Cabell, dated November 17, 2006 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| 10 | .1 | | Description of September 17, 2009 restricted stock award |
| 10 | .2 | | Description of post-employment medical and prescription drug benefits |
| • | | | National Fuel Gas Company 1997 Award and Option Plan, as amended and restated as of July 23, 2007 (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| • | | | Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated March 28, 2005 in FileNo. 1-3880) |
| • | | | Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated May 16, 2006 in FileNo. 1-3880) |
| • | | | Form of Restricted Stock Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| • | | | Form of Stock Option Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| • | | | Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| • | | | Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880) |
| • | | | Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
| • | | | Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program (Exhibit 10.3,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| • | | | Description of performance goals for certain executive officers under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2007 in FileNo. 1-3880) |
| • | | | Description of performance goals for certain executive officers under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Executive Annual Cash Incentive Program (Exhibit 10.4,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| • | | | Description of performance goals for an executive officer under the Company’s Executive Annual Cash Incentive Program (Exhibit 10.3,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880) |
| • | | | Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective February 20, 2008 (Exhibit 10.3,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 1994 in FileNo. 1-3880) |
129
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| • | | | Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880) |
| • | | | Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1999 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 2001 in FileNo. 1-3880) |
| • | | | Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21, 2005 (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
| • | | | Form of Letter Regarding Deferred Compensation Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.6,Form 10-K for fiscal year ended September 30, 2005 in FileFile No. 1-3880) |
| • | | | National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10,Form 10-Q for the quarterly period ended June 30, 1997 in FileNo. 1-3880) |
| • | | | Amendment No. 1 to National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 1998 in FileNo. 1-3880) |
| • | | | Amendment No. 2 to National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 1998 in FileNo. 1-3880) |
| • | | | Form of Letter Regarding Tophat Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.7,Form 10-K for fiscal year ended September 30, 2005 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Tophat Plan, Amended and Restated December 7, 2005 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2005 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Tophat Plan, as amended September 20, 2007 (Exhibit 10.3,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880) |
| • | | | Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and Philip C. Ackerman (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| • | | | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Life Insurance Premium Agreement, dated September 17, 2009, between the Company and David F. Smith (Exhibit 10.1,Form 8-K dated September 23, 2009 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1995 in FileNo. 1-3880) |
130
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| • | | | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| • | | | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 1998 in FileNo. 1-3880) |
| • | | | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4,Form 10-K/A for fiscal year ended September 30, 2001, in FileNo. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of January 1, 2007 (Exhibit 10.5,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 20, 2007 (Exhibit 10.4,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008 (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2008 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement(I), dated September 1, 2003 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in FileNo. 1-3880) |
| • | | | Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2009 in FileNo. 1-3880) |
| • | | | Amended and Restated Retirement Benefit Agreement for David F. Smith, dated September 20, 2007, among the Company, National Fuel Gas Supply Corporation and David F. Smith (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880) |
| • | | | Description of assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880) |
| • | | | Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| • | | | Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 2008 in FileNo. 1-3880) |
| • | | | Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880) |
| • | | | Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2006 in FileNo. 1-3880) |
121131
| | | | |
Exhibit
| | Description of
|
Number | | Exhibits |
|
| • | | | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15,Form 10-K for fiscal year ended September 30, 1999 in FileNo. 1-3880) |
| • | | | Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4,Form 10-K/A for fiscal year ended September 30, 2001, in FileNo. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of January 1, 2007 (Exhibit 10.5,Form 10-Q for the quarterly period ended December 31, 2006 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 20, 2007 (Exhibit 10.4,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880) |
| 10 | .5 | | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008 |
| • | | | National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2004 in FileNo. 1-3880) |
| • | | | National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in FileNo. 1-3880) |
| • | | | Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in FileNo. 1-3880) |
| • | | | Amended and Restated Retirement Benefit Agreement for David F. Smith, dated September 20, 2007, among the Company, National Fuel Gas Supply Corporation and David F. Smith (Exhibit 10.5,Form 10-K for the fiscal year ended September 30, 2007 in FileNo. 1-3880) |
| • | | | Description of assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880) |
| • | | | Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.7,Form 10-Q for the quarterly period ended December 31, 2006 inFile No. 1-3880) |
| • | | | Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2008 in FileNo. 1-3880) |
| • | | | Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3,Form 10-Q for the quarterly period ended June 30, 2006 in FileNo. 1-3880) |
| • | | | Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.1,Form 10-K for the fiscal year ended September 30, 2006 in FileNo. 1-3880) |
| 12 | | | Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2004 through 2008 |
| 21 | | | Subsidiaries of the Registrant |
| 23 | | | Consents of Experts: |
| 23 | .1 | | Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation |
| 23 | .2 | | Consent of Independent Registered Public Accounting Firm |
| 31 | | | Rule 13a-14(a)/15d-14(a) Certifications: |
| 31 | .1 | | Written statements of Chief Executive Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act |
122
| | | | | | | | |
Exhibit
| Exhibit
| | Description of
| Exhibit
| | Description of
|
Number | Number | | Exhibits | Number | | Exhibits |
|
| 31 | .2 | | Written statements of Principal Financial Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act | 12 | | | Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2005 through 2009 |
| 32 | | | Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | 21 | | | Subsidiaries of the Registrant |
| 99 | | | Additional Exhibits: | 23 | | | Consents of Experts: |
| 99 | .1 | | Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation | 23 | .1 | | Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation |
| 99 | .2 | | Company Maps | 23 | .2 | | Consent of Independent Registered Public Accounting Firm |
| • | | | Incorporated herein by reference as indicated. | 31 | | | Rule 13a-14(a)/15d-14(a) Certifications: |
| | | | All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report onForm 10-K | 31 | .1 | | Written statements of Chief Executive Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act |
| •• | | | In accordance with Item 601(b)(32)(ii) ofRegulation S-K and SEC Release Nos.33-8238 and34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference | 31 | .2 | | Written statements of Principal Financial Officer pursuant toRule 13a-14(a)/15d-14(a) of the Exchange Act |
| | 32 | | | Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
| | 99 | | | Additional Exhibits: |
| | 99 | .1 | | Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Corporation |
| | 99 | .2 | | Company Maps |
| | • | | | Incorporated herein by reference as indicated. |
| | | | | All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report onForm 10-K |
| | •• | | | In accordance with Item 601(b)(32)(ii) ofRegulation S-K and SEC Release Nos.33-8238 and34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference |
123132