UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2009

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number 1-3880

 

(716) 857-7000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES þ NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES o NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common stock, $1 par value, outstanding at January 31, 2010: 81,109,235 shares.

 

 

INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements (Unaudited)
a. Consolidated Statements of Income and Earnings Reinvested in the Business — Three Months Ended December 31, 2009 and 2008		6
b. Consolidated Balance Sheets — December 31, 2009 and September 30, 2009		7 - 8
c. Consolidated Statements of Cash Flows — Three Months Ended December 31, 2009 and 2008		9
d. Consolidated Statements of Comprehensive Income — Three Months Ended December 31, 2009 and 2008		10
e. Notes to Consolidated Financial Statements		11 - 27
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28 - 47
Item 3. Quantitative and Qualitative Disclosures About Market Risk		47
Item 4. Controls and Procedures		47 - 48
Part II. Other Information
Item 1. Legal Proceedings		48
Item 1 A. Risk Factors		48 - 49
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		49 - 50
Item 3. Defaults Upon Senior Securities		•
Item 4. Submission of Matters to a Vote of Security Holders		•
Item 5. Other Information		•
Item 6. Exhibits		50 - 51
Signatures		52
EX-10.1
EX-10.2
EX-10.3
EX-12
EX-31.1
EX-31.2
EX-32
EX-99

•

The Company has nothing to report under this item.

          Reference to “the Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

          This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions.

Part I. Financial Information

See Notes to Condensed Consolidated Financial Statements

See Notes to Condensed Consolidated Financial Statements

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)

Note 1 — 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 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.

Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation.

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2009, 2008 and 2007 that are included in the Company’s 2009 Form 10-K. The consolidated financial statements for the year ended September 30, 2010 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

     The earnings for the three months ended December 31, 2009 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2010. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 7 – Business Segment Information.

Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid investments purchased with a maturity of generally three months or less to be cash equivalents.

     At December 31, 2009, the Company accrued $15.4 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at December 31, 2009 since it represented a non-cash investing activity at that date.

     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. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2009 and have been included in the Consolidated Statement of Cash Flows at December 31, 2009.

     At December 31, 2008, the Company accrued $51.7 million of capital expenditures in the Exploration and Production segment, the majority of which was for lease acquisitions in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at December 31, 2008 since it represented a non-cash investing activity at that date.

Item 1. Financial Statements (Cont.)

     At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to the construction of the Empire Connector project. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2008 and have been included in the Consolidated Statement of Cash Flows at December 31, 2008.

Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by the Company to serve as collateral for open hedging positions. At December 31, 2009, the Company had hedging collateral deposits of $0.2 million related to its exchange-traded futures contracts and $0.9 million related to its over-the-counter crude oil swap agreements. 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 December 31, 2009 and 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. If no disputes occur, this cash will be released to Ivanhoe Energy.

Gas Stored Underground — Current. In the Utility segment, gas stored underground – current is carried at lower of cost or market, on a LIFO method. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $8.9 million at December 31, 2009, is reduced to zero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment. 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 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 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. The Company’s capitalized costs exceeded the full cost ceiling for the Company’s oil and gas

Earnings Per Common Share. Basic earnings per common share is computed by dividing net income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflect 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 diluted 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 Statement 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 the quarter ended December 31, 2009, there were no stock options and 24,000 stock-settled SARs excluded as being antidilutive. For the quarter ended December 31, 2008, there were 765,000 stock options and 365,000 stock-settled SARs excluded as being antidilutive.

New Authoritative Accounting and Financial Reporting Guidance. In September 2006, the FASB issued authoritative guidance for using fair value to measure assets and liabilities. This 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. This guidance is to be applied whenever assets or liabilities are to be measured at fair value. On 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. The FASB’s authoritative guidance for using fair value to measure nonfinancial assets and nonfinancial liabilities on a nonrecurring basis became effective during the quarter ended December 31, 2009. The Company’s nonfinancial assets and nonfinancial liabilities were not impacted by this guidance during the quarter ended December 31, 2009. The Company has identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of this guidance. The impact of this guidance will be known when the Company performs its annual test for goodwill impairment at the end of the fiscal year; however, at this time, it is not expected to be material. The Company has identified Asset Retirement Obligations as a nonfinancial liability that may be impacted by the adoption of the guidance. The impact of this guidance will be known when the Company recognizes new asset retirement obligations. However, at this time, the Company believes the impact of the guidance will be immaterial.

Item 1. Financial Statements (Cont.)

     In December 2007, the FASB revised authoritative guidance that significantly changes 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 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. This authoritative guidance became effective for the Company as of October 1, 2009. The Company will apply this guidance to future business combinations.

     In December 2007, the FASB issued authoritative 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 significantly changed the accounting for transactions with minority interest holders. This authoritative guidance became effective for the Company as of October 1, 2009. This guidance currently does not have an impact on the Company’s consolidated financial statements.

     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. The Company adopted this guidance during the first quarter of fiscal 2010 and determined that its participating securities (restricted stock awards) have an immaterial impact on the Company’s earnings per share calculation. Therefore, the Company has not presented its earnings per share pursuant to the “two class” method.

     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 a 12-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. Additionally, on January 6, 2010, the FASB amended the oil and gas accounting standards to conform to the SEC final rule on Modernization of Oil and Gas Reporting. The revised reporting and disclosure requirements are effective for the Company’s Form 10-K for the period ended September 30, 2010. Early adoption is not permitted. The Company is currently evaluating the impact that adoption of these 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’s Form 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.

     In June 2009, the FASB issued amended authoritative guidance to improve and clarify financial reporting requirements by companies involved with variable interest entities. The new guidance requires a company to perform an analysis to determine whether the company’s variable interest or interests give it a controlling financial interest in a variable interest entity. The analysis also assists in identifying the primary beneficiary of a variable interest entity. This authoritative guidance is effective as of the Company’s first quarter of fiscal 2011. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statements.

Item 1. Financial Statements (Cont.)

Note 2 – Fair Value Measurements

     The FASB authoritative guidance regarding fair value measurements 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 following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of December 31, 2009 and 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.

Cash Equivalents

     The cash equivalents reported in Level 1 consist of SEC registered money market mutual funds.

Derivative Financial Instruments

     At December 31, 2009, the derivative financial instruments reported in Level 1 consist of NYMEX futures contracts used in the Company’s Energy Marketing and Pipeline and Storage segments (at September 30, 2009, the derivative financial instruments reported in Level 1 consist of NYMEX futures used in the Company’s Energy Marketing segment). Hedging collateral deposits of $0.2 million associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments

Item 1. Financial Statements (Cont.)

reported in Level 2 consist of natural gas and some of the crude oil swap agreements used in the Company’s Exploration and Production segment and natural gas swap agreements used in the Energy Marketing segment at December 31, 2009 (at September 30, 2009, the derivative financial instruments reported in Level 2 consist of natural gas swap agreements used in the Company’s Exploration and Production and Energy Marketing segments). The fair value of these swap agreements is based on an internal model that uses observable inputs. At December 31, 2009, the derivative financial instruments reported in Level 3 consist of a majority of the Exploration and Production segment’s crude oil swap agreements (at September 30, 2009, all of the Exploration and Production segment’s crude oil swap agreements were reported as Level 3). The fair value of the crude oil swap agreements is based on an internal model that uses both observable and unobservable inputs. Based on an assessment of the counterparties’ credit risk, the fair market value of the price swap agreements reported as Level 2 and 3 assets have been reduced by $0.2 million and $0.9 million at December 31, 2009 and September 30, 2009, respectively. The fair market value of the price swap agreements reported as Level 2 liabilities at September 30, 2009 has been reduced by less than $0.1 million based on an assessment of the Company’s credit risk. These credit reserves were 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.

     At December 31, 2009, $0.9 million in hedging collateral deposits reported in Level 1 are associated with the Level 3 derivative financial instruments used by the Exploration and Production segment. The Company’s internal model may yield a different fair value than the fair value determined by the Company’s counterparties. The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s 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 tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters ended December 31, 2009 and 2008, respectively.

Fair Value Measurements Using Unobservable Inputs (Level 3)

Other Investments. 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 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 $53.9 million at December 31, 2009 and $54.2 million at September 30, 2009. The fair value of the equity mutual fund was $16.4 million at December 31, 2009 and $15.8 million at September 30, 2009. The gross unrealized loss on this equity mutual fund was $0.7 million at December 31, 2009 and $1.0 million at September 30, 2009. Management does not consider this investment to be other than temporarily impaired. The fair value of the stock of an insurance company was $7.2 million at December 31, 2009 and $8.3 million at September 30, 2009. The gross unrealized gain on this stock was $4.8 million at December 31, 2009 and $5.9 million at September 30, 2009. 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 is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk in the Exploration and Production, Energy Marketing and Pipeline and Storage segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the

Item 1.		Financial Statements (Cont.)

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 Sheets at December 31, 2009 and September 30, 2009 as shown in the table below.

Fair Values of Derivative Instruments

(Dollar Amounts in Thousands)

Asset Derivatives

Liability Derivatives

Derivatives

Designated as

Consolidated

Consolidated

Hedging

Balance Sheet

Balance Sheet

Instruments

Location

Fair Value

Location

Fair Value

Commodity Contracts — at December 31, 2009

Fair Value of Derivative Financial Instruments

$

19,791

Fair Value of Derivative Financial Instruments

$

—

Commodity Contracts — at September 30, 2009

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 Sheets at December 31, 2009 and September 30, 2009.

Derivatives		Fair Values of Derivative Instruments
Designated as		(Dollar Amounts in Thousands)
Hedging		Gross Asset Derivatives				Gross Liability Derivatives
Instruments		Fair Value				Fair Value
Commodity Contracts — at December 31, 2009		$	61,465			$	41,674
Commodity Contracts — at September 30, 2009		$	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 (loss) 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 December 31, 2009, the Company’s Exploration and Production segment had the following commodity derivative contracts (swaps) outstanding to hedge forecasted sales (where the Company uses short positions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):

     As of December 31, 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):

     As of December 31, 2009, the Company’s Pipeline and Storage segment have the following commodity derivative contracts (futures contracts) 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):

Commodity		Units
Natural Gas		0.3 Bcf (all short positions)

     As of December 31, 2009, the Company’s Exploration and Production segment had $16.3 million ($9.6 million after tax) of gains included in the accumulated other comprehensive loss balance. It is expected that $17.7 million ($10.4 million after tax) of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales of the underlying commodities are expected to occur. See Note 1, under Accumulated Other Comprehensive Loss, for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

     As of December 31, 2009, the Company’s Energy Marketing segment had $1.7 million ($1.0 million after tax) of losses included in the accumulated other comprehensive loss balance. It is expected that $1.8 million ($1.1 million after tax) of these losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Loss, for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

     As of December 31, 2009, the Company’s Pipeline and Storage segment had less than $0.1 million of gains included in the accumulated other comprehensive loss balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales with underlying commodities are expected to occur. See Note 1, under Accumulated Other Comprehensive Loss, for the after-tax gain pertaining to derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

Fair value hedges

     The Company’s Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and commitments related to the injection 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 increases (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 December 31, 2009, the Company’s Energy Marketing segment had fair value hedges covering approximately 9.3 Bcf (7.6 Bcf of fixed price sales commitments (all long positions), 1.1 Bcf of fixed price purchase commitments (all short positions), and 0.6 Bcf of commitments related to the withdrawal of storage gas (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the 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 current earnings, as shown below.

     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 a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with ten counterparties. On average, the Company has $1.7 million of credit exposure per counterparty. The Company had not received any collateral from the counterparties at December 31, 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 December 31, 2009, eight of the ten counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-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 December 31, 2009, the fair market value of the derivative financial instrument assets related to these eight counterparties was $14.2 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). The Company’s internal model may yield a different fair value than the fair value determined by the Company’s counterparties. The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties. For its over-the-counter crude oil swap agreements, the Company was required to pay $0.9 million in hedging collateral deposits at December 31, 2009. This is discussed in Note 1 under Hedging Collateral Deposits.

     For its exchange traded futures contracts, which are in an asset position, the Company had paid $0.2 million in hedging collateral as of December 31, 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 1 under Hedging Collateral Deposits.

     Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes. The following is a reconciliation of this difference (in thousands):

     As of September 30, 2009, the Company recorded a deferred tax asset relating to a federal net operating loss carryover of $25.1 million, of which $24.7 million remains at December 31, 2009. 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 $67.1 million and $67.0 million at December 31, 2009 and September 30, 2009, 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 $138.4 million at December 31, 2009 and September 30, 2009.

     The Company files federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2009 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 2006 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled.

     The 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 date of filing of the income tax return.

Item 1.		Financial Statements (Cont.)

Note 5 — Capitalization

Common Stock. During the three months ended December 31, 2009, the Company issued 728,523 original issue shares of common stock as a result of stock option exercises. The Company also issued 3,200 original issue shares of 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 the directors’ services during the three months ended December 31, 2009. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the three months ended December 31, 2009, 249,705 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.

Current Portion of Long-Term Debt. Current Portion of Long-Term Debt at December 31, 2009 consists of $200 million of 7.50% medium-term notes that mature in November 2010.

Note 6 — Commitments and Contingencies

Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.

     The Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has received approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated minimum liability for remediation of this site of $15.2 million.

     At December 31, 2009, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $18.1 million to $22.3 million. The minimum estimated liability of $18.1 million, which includes the $15.2 million discussed above, has been recorded on the Consolidated Balance Sheet at December 31, 2009. The Company expects to recover its environmental clean-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.

     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.

Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations 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 quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, or have a material adverse effect on the financial condition of the Company.

Item 1.		Financial Statements (Cont.)

Note 7 — Business Segment Information

     The Company has four reportable segments: Utility, Pipeline and Storage, Exploration and Production and Energy Marketing. The division of the Company’s operations into the reported segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

     The data presented in the tables below reflect the reported segments and reconciliations to consolidated amounts. As stated in the 2009 Form 10-K, 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. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2009 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2009 Form 10-K.

Quarter Ended December 31, 2009 (Thousands)

     The gross carrying amount of intangible assets subject to amortization at December 31, 2009 remained unchanged from September 30, 2009. The only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the long-term transportation contracts is estimated to be $0.3 million for the remainder of 2010 and $0.4 million annually for 2011, 2012, 2013 and 2014. Amortization expense for the long-term gas purchase contracts is estimated to be $1.1 million for the remainder of 2010 and $1.4 million annually for 2011, 2012, 2013 and 2014.

Note 9 — Retirement Plan and Other Post-Retirement Benefits

     Components of Net Periodic Benefit Cost (in thousands):

Item 1.		Financial Statements (Cont.)

     Prior to the adoption of authoritative guidance related to accounting for defined benefit pension and other postretirement plans, 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 during fiscal 2009. As allowed by the authoritative guidance, these costs were calculated using June 30, 2008 measurement date data. Three of those months pertained to the period of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for that period amounted to $3.8 million and were recorded by the Company during the quarter ended December 31, 2008 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 quarter ended December 31, 2008 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.

Employer Contributions. During the three months ended December 31, 2009, the Company contributed $20.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $6.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2010, the Company does not expect to contribute to the Retirement Plan. It is likely that the Company will have to fund larger amounts to the Retirement Plan subsequent to fiscal 2010 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2010, the Company expects to contribute in the range of $19.0 million to $20.0 million to its VEBA trusts and 401(h) accounts.

Note 10 — Subsequent Events

     In accordance with the authoritative guidance for subsequent events, the Company has evaluated subsequent events through February 5, 2010, which represents the filing date of this Form 10-Q with the SEC, in order to ensure that this Form 10-Q includes appropriate disclosure of events both recognized in the financial statements as of December 31, 2009, and events which occurred subsequent to December 31, 2009 but were not recognized in the financial statements. As of February 5, 2010, there were no subsequent events which required recognition or disclosure.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

     The Company is a diversified energy company consisting of four reportable business segments. For the quarter ended December 31, 2009 compared to the quarter ended December 31, 2008, the Company experienced an increase in earnings of $107.2 million, primarily due to higher earnings in the Exploration and Production segment. During the quarter ended December 31, 2008, the Company recorded an impairment charge of $182.8 million ($108.2 million after tax) that did not recur during the quarter ended December 31, 2009. 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. Such costs are subject to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. At December 31, 2008, due to significant declines in crude oil and natural gas commodity prices, the book value of the Company’s oil and gas properties exceeded the ceiling, resulting in the impairment charge mentioned above. For further discussion of the ceiling test results at December 31, 2009 and a sensitivity analysis to changes in crude oil and natural gas commodity prices, refer to the Critical Accounting Estimates section below. For further discussion of the Company’s earnings, refer to the Results of Operations section below.

     From a capital resources and liquidity perspective, the Company spent $67.7 million on capital expenditures during the three months ended December 31, 2009, with approximately 70% being spent in the Exploration and Production segment. Approximately 82% of the Exploration and Production segment capital expenditures were spent in the Appalachian region, where the Company continues to emphasize the development of its acreage in the Marcellus Shale. The Company was recently the high bidder on two tracts of land in the Appalachian region of Pennsylvania at approximately $71.8 million. This transaction is expected to close in March 2010. With this expenditure and other factors, it is expected that Exploration and Production segment capital expenditures in 2010 will be $345 million, compared to the previously reported amount of $255 million. The emphasis on Marcellus Shale development will carry over into the Pipeline and Storage segment, which is anticipating the need for pipeline and storage capacity as Marcellus Shale production comes on line. While capital expenditures in the Pipeline and Storage segment were only $7.0 million during the three months ended December 31, 2009, the Company continues to see strong interest for pipeline and storage capacity in the Marcellus Shale region. If such projects in the Pipeline and Storage segment are to go forward, the most significant expenditures are expected to occur in 2011 and 2012. For further discussion of the Company’s capital expenditures, refer to the Capital Resources and Liquidity section below.

CRITICAL ACCOUNTING ESTIMATES

     For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 2009 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company’s oil and gas reserves based on current market prices (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. If the book value of the oil and gas properties in any country exceeds the ceiling, a non-cash charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At December 31, 2009, the ceiling exceeded the book value of the oil and gas properties by approximately $417 million. The quoted Cushing, Oklahoma spot price for West Texas Intermediate oil at December 31, 2009 was $79.39. The quoted Henry Hub spot price for natural gas at December 31, 2009 was $5.79. (Note – Because actual pricing of the Company’s various producing properties varies depending on their location, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Cushing oil and Henry Hub prices, which are only indicative of current prices.) If natural gas prices used in the ceiling test calculation at December 31, 2009 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $360 million. If crude oil prices used in the ceiling test calculation at

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

December 31, 2009 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $366 million. If both natural gas and crude oil prices used in the ceiling test calculation at December 31, 2009 were lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $309 million. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation. For a more complete discussion of the full cost method of accounting, refer to “Oil and Gas Exploration and Development Costs” under “Critical Accounting Estimates” in Item 7 of the Company’s 2009 Form 10-K.

RESULTS OF OPERATIONS

Earnings

     The Company earnings were $64.5 million for the quarter ended December 31, 2009 compared to a loss of $42.7 million for the quarter ended December 31, 2008. The increase in earnings of $107.2 million is primarily the result of higher earnings in the Exploration and Production segment. Higher earnings in the Utility and Energy Marketing segments as well as the All Other category also contributed to the increase. Lower earnings in the Pipeline and Storage segment and a loss in the Corporate category slightly offset these increases. The Company’s loss for the quarter ended December 31, 2008 includes a non-cash $182.8 million impairment charge ($108.2 million after tax) for the Exploration and Production segment’s oil and gas producing properties.

     Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.