UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

 

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended December  31, 2012

 

OR

 

[ ] 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

 

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NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

 

(716) 857-7000

(Registrant's telephone number, including area code)

 

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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  ¨

 

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  þ   NO  ¨

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting   company”   in   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  ¨   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, par value $1.00 per share, outstanding at January 31, 2013:  83,490,445    shares.

 

 

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GLOSSARY OF TERMS

 

Frequently used abbreviations, acronyms, or terms used in this report:

 

National Fuel Gas Companies

 

Regulatory Agencies 

 

Other

 

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•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.

 

 

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Part I.  Financial Information

 

Item 1.  Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)

 

 

 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

 

 

 

 

 

 

 

 

See Notes to Condensed Consolidated Financial Statements

 

 

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

Note 1 - Summary of Significant Accounting Policies

 

Principles of Consolidation.  The Company consolidates all entities in which it has a controlling financial interest.  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.

 

Reclassifications and Revisions.  Certain prior year amounts have been reclassified to conform with current year presentation.

 

Revisions were made on the Consolidated Statement of Cash Flows for the quarter ended December 31, 2011 to reflect non-cash investing activities embedded in Accounts Payable on the Consolidated Balance Sheets at December 31, 2011 and September 30, 2011.  These revisions increased the operating cash flows related to the change in Accounts Payable for the quarter ended December 31, 2011 by $16.4 million and decreased investing cash flows related to Capital Expenditures by the same amounts. 

 

In subsequent periods, revisions will be made on the Consolidated Statement of Cash Flows for the six months ended March 31, 2012, the nine months ended June 30, 2012 and the fiscal years ended September 30, 2012 and September 30, 2011 to reflect non-cash investing activities embedded in Accounts Payable on the Consolidated Balance Sheets for the respective periods.  These revisions will increase the operating cash flows related to the six months ended March 31, 2012 and the nine months ended June 30, 2012 by $17.7 million and $32.8 million, respectively, and decrease investing cash flows related to Capital Expenditures by the same amount.  The revision for the fiscal years ended September 30, 2012 and September 30, 2011 will decrease operating cash flows by $1.8 million and $6.6 million, respectively, and increase investing cash flows related to Capital Expenditures by the same amounts.  The revisions in the Consolidated Statement of Cash Flows noted above represent errors that are not deemed material, individually or in the aggregate, to the prior period consolidated financial statements.

 

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, 2012, 2011 and 2010 that are included in the Company's 2012 Form 10-K.  The consolidated financial statements for the year ended September 30, 2013 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, 2012 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2013.  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 debt instruments purchased with a maturity of generally three months or less to be cash equivalents.

 

The Company has accounts payable and accrued liabilities recorded on its Consolidated Balance Sheets that are related to capital expenditures.  These amounts represent non-cash investing activities at the

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balance sheet date.  Accordingly, they are excluded from the Consolidated Statement of Cash Flows when they are recorded as liabilities and included in the Consolidated Statement of Cash Flows when they are paid in the subsequent period.  The following table summarizes the Company’s non-cash capital expenditures recorded as Accounts Payable and Other Accruals and Current Liabilities on the Consolidated Balance Sheet:

 

 

Hedging Collateral Deposits.  This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions.  At December 31, 2012 the Company did not have any hedging collateral deposits, but at September 30, 2012, it had hedging collateral deposits of $0.4 million related to its exchange-traded futures contracts.  In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

 

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 $6.7 million at December 31, 2012, 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.  Such costs amounted to $155.6 million and $146.1 million at December 31, 2012 and September 30, 2012, respectively.  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 prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. 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.  At December 31, 2012, the ceiling exceeded the book value of the oil and gas properties by approximately $7.3 million.

 

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Accumulated Other Comprehensive Loss.  The components of Accumulated Other Comprehensive Loss, net of related tax effect, are as follows (in thousands):

 

 

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):

 

 

Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):

 

 

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 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, SARs and restricted stock units.  The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method.  Stock options, SARs and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share.  There were 422,681 and 191,285 securities excluded as being antidilutive for the quarters ended December 31, 2012 and 2011, respectively. 

 

Stock-Based Compensation.  During the quarter ended December 31, 2012, the Company granted 412,970 non-performance based SARs having a weighted average exercise price of $53.05 per share.  The weighted average grant date fair value of these SARs was $10.66 per share.  These SARs may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company.  These SARs are considered equity awards under the current authoritative guidance for stock-based compensation.  The accounting for those SARs is the same as the accounting for stock options.  The non-performance based SARs granted during the quarter ended December 31, 2012 vest and become exercisable annually in one-third increments.  The weighted average grant date fair value of these non-performance based SARs granted during the quarter ended December 31,

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2012 was estimated on the date of grant using the same accounting treatment that is applied for stock options.  There were no stock options granted during the quarter ended December 31, 2012. 

 

The Company granted 210,206 performance based restricted stock units during the quarter ended December 31, 2012. The weighted average fair value of such performance based restricted stock units was $48.49 per share for the quarter ended December 31, 2012. The performance based restricted stock units granted during the quarter ended December 31, 2012 must meet a performance condition over the performance cycle of October 1, 2012 to September 30, 2015.  The performance condition over the performance cycle, generally stated, is the Company’s total return on capital as compared to the same metric for companies in the Natural Gas Distribution and Integrated Natural Gas Companies group as calculated and reported in the Monthly Utility Reports of AUS, Inc., a leading industry consultant.  The number of performance based restricted stock units that will vest will depend upon the Company’s performance relative to the report group and not upon the absolute level of return achieved by the Company.  The Company also granted 26,100 non-performance based restricted stock units during the quarter ended December 31, 2012.  The weighted average fair value of such non-performance based restricted stock units was $47.20 per share for the quarter ended December 31, 2012.  Restricted stock units, both performance based and non-performance based, represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The performance based and non-performance based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for performance based and non-performance based restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award. There were no restricted share awards granted during the quarter ended December 31, 2012. 

 

New Authoritative Accounting and Financial Reporting Guidance.  In June 2011, the FASB issued authoritative guidance regarding the presentation of comprehensive income.  The new guidance allows companies only two choices for presenting net income and other comprehensive income: in a single continuous statement, or in two separate, but consecutive, statements.  The guidance eliminates the option to report other comprehensive income and its components in the statement of changes in equity.  This authoritative guidance became effective for the quarter ended December 31, 2012.  The Company has updated its financial statements to reflect the new guidance. 

 

            In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities.  Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement.  This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2014 and is not expected to have a significant impact on the Company’s financial statements.

   

 

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 can 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 table sets 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, 2012 and September 30, 2012.  Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

 

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Derivative Financial Instruments

 

At December 31, 2012 and September 30, 2012, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Company’s Energy Marketing segment.  Hedging collateral deposits of $0.4 million (at September 30, 2012), which are associated with these futures contracts, have been reported in Level 1 as well (there were no hedging collateral deposits at December 31, 2012). The derivative financial instruments reported in Level 2 at December 31, 2012 and September 30, 2012 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments and some of the crude oil price swap agreements used in the Company’s Exploration and Production segment.  The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The derivative financial instruments reported in Level 3 consist of the majority of the Company’s Exploration and Production segment’s crude oil price swap agreements at December 31, 2012 and September 30, 2012.  The fair value of the Level 3 crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). 

 

The significant unobservable input used in the fair value measurement of the majority of the Company’s over-the-counter crude oil swaps is the basis differential between Midway Sunset oil and NYMEX contracts.  Significant changes in the assumed basis differential could result in a significant change in value of the derivative financial instruments.  At December 31, 2012, it was assumed that Midway Sunset oil was 109.6% of NYMEX.  This is based on a historical twelve month average of Midway Sunset oil sales verses NYMEX settlements.  During this twelve-month period, the price of Midway Sunset oil ranged from 103.2% to 112.4% of NYMEX.  If the basis differential between Midway Sunset oil and NYMEX contracts used in the fair value measurement calculation at December 31, 2012 had been 10 percentage points lower, the fair value of the Level 3 crude oil price swap agreements would have changed from a net liability of $14.1 million to a net asset of $2.0 million.  If the basis differential between Midway Sunset oil and NYMEX contracts used in the fair value measurement at December 31, 2012 had been 10 percentage points higher, the fair value measurement of the Level 3 crude oil price swap agreements liability would have been approximately $16.1 million higher.  These calculated amounts are based solely on basis differential changes and do not take into account any other changes to the fair value measurement calculation. 

 

The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.  At December 31, 2012, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation.  To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty (for an asset) or the Company’s (for a liability) credit default swaps rates.

 

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, 2012 and 2011, respectively. For the quarters ended December 31, 2012 and December 31, 2011, no transfers in or out of Level 1 or Level 2 occurred.  There were no purchases or sales of derivative financial instruments during the periods presented in the tables below.  All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below.

 

 

 

 

 

 

 

 

 

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⁽¹⁾ Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended December 31, 2012. 

⁽²⁾ Derivative Financial Instruments are shown on a net basis.

 

 

⁽¹⁾ Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended December 31, 2011. 

⁽²⁾ Derivative Financial Instruments are shown on a net basis.

 

Note 3 – Financial Instruments

 

Long-Term Debt.  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 ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt.  Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands):

 

 

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. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBOR for the risk free component and company specific credit spread information – generally obtained from recent trade activity in the debt).  As such, the Company considers the debt to be Level 2.

 

Temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2.  Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.

 

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 $56.3 million and $57.0 million at December 31, 2012 and September 30, 2012, respectively. The fair value of the equity mutual fund was $28.6 million at December 31, 2012 and $24.8 million at September 30, 2012. The gross unrealized gain on this equity mutual fund was $2.7 million

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at December 31, 2012 and $2.6 million at September 30, 2012.  The fair value of the stock of an insurance company was $5.4 million at December 31, 2012 and $4.8 million at September 30, 2012. The gross unrealized gain on this stock was $3.0 million at December 31, 2012 and $2.3 million at September 30, 2012. 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 or has used derivative instruments to manage 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 risk associated with forecasted gas purchases, forecasted gas sales, storage of gas, withdrawal of gas from storage to meet customer demand and the potential decline in the value of gas held in storage. The duration of the Company’s hedges does not typically exceed 5 years.

 

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at December 31, 2012 and September 30, 2012.  All of the derivative financial instruments reported on those line items related to commodity contracts as discussed in the paragraph above.

 

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 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, 2012, 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, 2012, 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, when applicable, 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, 2012, the Company’s Exploration and Production segment had $22.2 million ($12.9 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $40.0 million ($23.3 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur.   It is expected that unrealized losses will be reclassified into the Consolidated Statement of Income in subsequent periods as the expected sales of the underlying commodities occur.

 

As of December 31, 2012, the Company’s Energy Marketing segment had $1.0 million ($0.6 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $0.9 million ($0.6 million after tax) of these losses will be reclassified into the Consolidated

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Statement of Income (Loss) within the next 12 months as the expected sales of the underlying commodity occurs.

 

Refer to Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments for the Exploration and Production and Energy Marketing segments.

 

 

(1)  There were no open hedging positions at December 31, 2012 or 2011.

 

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 the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long

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positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of December 31, 2012, the Company’s Energy Marketing segment had fair value hedges covering approximately 9.1 Bcf (8.0 Bcf of fixed price sales commitments (mostly long positions), 0.9 Bcf of fixed price purchase commitments (mostly short positions) and 0.2 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 eleven counterparties of which eight are in a net gain position.   On average, the Company had $4.5 million of credit exposure per counterparty in a gain position at December 31, 2012. The maximum credit exposure per counterparty in a gain position at December 31, 2012 was $11.1 million. As of December 31, 2012, the Company had not received any collateral from the counterparties.  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, nor had the counterparties’ credit ratings declined to levels at which the counterparties were required to post collateral.

 

As of December 31, 2012, nine of the eleven 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 (applicable debt ratings), 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 (or if the current liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required.  At December 31, 2012, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $23.8 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements).  At December 31, 2012, the fair market value of the

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derivative financial instrument liabilities with a credit-risk related contingency feature was $13.8  million according to the Company’s  internal model  (discussed in Note 2 — Fair Value Measurements).  For its over-the-counter crude oil swap agreements, which were in a liability position, the Company was not required to post any  hedging collateral deposits at December 31, 2012. 

 

For its exchange traded futures contracts, which are in an asset position, the Company was not required to post any hedging collateral deposits as of December 31, 2012. 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 and margin requirements it has with its counterparties.

 

            The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.

 

Note 4 - Income Taxes

 

The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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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 (in thousands):

 

 

Significant components of the Company’s deferred tax liabilities and assets were as follows (in thousands):

 

As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets that arose directly from excess tax deductions related to stock-based compensation. Cumulative tax benefits of $37.5 million and $32.7 million for the periods ending December 31, 2012 and September 30, 2012, respectively, relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax benefits are realized.

 

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 $66.4 million at December 31, 2012 and September 30, 2012.  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 $152.2 million and  $150.9 million at December 31, 2012 and September 30, 2012, respectively. 

 

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The Internal Revenue Service (IRS) is currently conducting examinations of the Company for fiscal 2011 and fiscal 2012 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 2009 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled.  During fiscal 2009, consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property.  Local IRS examiners proposed to disallow most of the tax accounting method change recorded by the Company in fiscal 2009 and fiscal 2010. The Company has filed protests for fiscal 2009 and fiscal 2010 with the IRS Appeals Office disputing the local IRS findings.  The local IRS examiners have again considered this issue to be unresolved for fiscal 2011 and will conduct a post-filing examination of this issue upon the anticipated issuance of IRS guidance addressing this issue for natural gas utilities.

 

The Company is also subject to various routine state income tax examinations.  The Company’s principal subsidiaries operate mainly 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.

 

On January 2, 2013, President Obama signed into law the American Taxpayer Relief Act of 2012 (the Relief Act).  As a result of ongoing IRS examinations, it is uncertain whether the Relief Act will have a material effect on the Company’s financial statements.

                

 

Note 5 - Capitalization

 

Common Stock.  During the three months ended December 31, 2012, the Company issued 342,822 original issue shares of common stock as a result of stock option and SARs exercises.  In addition, the Company issued 60,631 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan.  The Company also issued 4,050 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the three months ended December 31, 2012.  Holders of stock options, SARs 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, 2012, 255,518 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 both December 31, 2012 and September 30, 2012 consisted of $250 million of 5.25% notes that mature in March 2013.    

 

 

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.  In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. An estimated minimum liability for remediation of this site of $14.0 million has been recorded.

 

At December 31, 2012, 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

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plant site discussed above) will be in the range of $16.3 million to $21.9 million.  The minimum estimated liability of $16.3 million, which includes the $14.0 million discussed above, has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at December 31, 2012.  The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 11 years.

 

The Company is currently not aware of any material additional exposure to environmental liabilities.  However, changes in environmental laws and 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 other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

 

Note 7 – Business Segment Information    

 

The Company reports financial results for four segments: Utility, Pipeline and Storage, Exploration and Production, and Energy Marketing.  The division 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 data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts.  As stated in the 2012 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 2012 Form 10-K.  As for segment assets, the significant changes from the segment assets disclosed in the 2012 Form 10-K involve the Exploration and Production, Utility, and Pipeline and Storage segments as well as the All Other category.  Total Exploration and Production segment assets, Utility segment assets and Pipeline and Storage segment assets have increased by $98.3 million, $29.9 million, and $29.0 million, respectively, during the three months ended December 31, 2012. The All Other category assets have increased by $16.4 million during the three months ended December 31, 2012. 

 

 

 

 

 

 

 

 

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Note 8 – Retirement Plan and Other Post-Retirement Benefits

 

Components of Net Periodic Benefit Cost (in thousands):

 

 

⁽¹⁾    The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric

     basis to reflect  the fact that  the Utility segment  experiences higher  throughput of  natural gas in the winter months and lower

     throughput of natural gas in the summer months.

 

Employer Contributions.  During the three months ended December 31, 2012, the Company contributed $12.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $4.3 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2013, the Company expects to contribute between $28.0 million and $32.0 million to the Retirement Plan.  Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2013 in order to be in compliance with the Pension Protection Act of 2006 (as impacted by the Moving Ahead for Progress in the 21^st Century Act).  In July 2012, the Surface Transportation Extension Act, which is also referred to as the Moving Ahead for Progress in the 21^st Century Act (the Act), was passed by Congress and signed by the President.  The Act included pension funding stabilization provisions.  The Company is currently in the process of evaluating its future contributions in light of the provisions of the Act. In the remainder of 2013, the Company expects to contribute between $11.0 million and $15.0 million to its VEBA trusts and 401(h) accounts.

 

   

 

 

 

 

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

 

OVERVIEW

 

Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.

 

The Company is a diversified energy holding company that owns a number of subsidiary operating companies, and reports financial results in four reportable business segments. For the quarter ended December 31, 2012 compared to the quarter ended December 31, 2011, the Company experienced an increase in earnings of $7.2 million.  The earnings increase for the quarter is primarily due to higher earnings in the Pipeline and Storage segment and Utility segment, partially offset by lower earnings in the Exploration and Production segment.  For further discussion of the Company’s earnings, refer to the Results of Operations section below. 

 

The Company’s natural gas reserve base has grown substantially in recent years due to its development of reserves in the Marcellus Shale, a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.  The Company controls the natural gas interests associated with approximately 775,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations.  Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 607 Bcf at September 30, 2011 to 925 Bcf at September 30, 2012.  The Company has spent significant amounts of capital in this region related to the development of such reserves. For the three months ended December 31, 2012, the Company’s Exploration and Production segment had capital expenditures of $109.0 million in the Appalachian region, of which $102.3 million was spent towards the development of the Marcellus Shale.  The Company’s fiscal 2013 estimated capital expenditures in the Appalachian region are expected to be approximately $425.0 million, up from the previously reported estimated capital expenditures in the Appalachian region of $405.3 million.

 

The Company’s Pipeline and Storage segment has been spending significant amounts to build pipeline gathering and transmission facilities to connect Marcellus Shale production with existing pipelines in the region. One such project, the Northern Access expansion project, began initial service on November 1, 2012, with full service implemented on January 16, 2013. The Northern Access expansion project is discussed further in the Investing Cash Flow section that follows. 

 

From a capital resources perspective, the Company has largely been able to meet its capital expenditure needs for all of the above projects by using cash from operations as well as both short and long-term debt.  Going forward, the Company plans to continue its use of short-term debt and expects to issue long-term debt in the near term to replace long-term debt that matures in March 2013 and reduce short-term borrowings. 

 

The well completion technology referred to as hydraulic fracturing used in conjunction with horizontal drilling continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Company’s experience, one that the Company believes has little negative impact to the environment. Nonetheless, the potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale.    Please refer to the Risk Factors section of the Company’s 2012 Form 10-K for further discussion.

 

CRITICAL ACCOUNTING ESTIMATES

 

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2012 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.

 

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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 an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (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 exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling.  At December 31, 2012, the ceiling exceeded the book value of the oil and gas properties by approximately $7.3 million.  The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended December 31, 2012, based on posted Midway Sunset prices, was $103.05 per Bbl.  The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2012, based on the quoted Henry Hub spot price for natural gas, was $2.76 per MMBtu.  (Note – Because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended December 31, 2012.)  If natural gas average prices used in the ceiling test calculation at December 31, 2012 had been $1 per MMBtu lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $219.8 million, which would have resulted in an impairment charge.  If crude oil average prices used in the ceiling test calculation at December 31, 2012 had been $5 per Bbl lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $38.9 million, which would have resulted in an impairment charge.  If both natural gas and crude oil average prices used in the ceiling test calculation at December 31, 2012 were lower by $1 per MMBtu and $5 per Bbl, respectively, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $265.7 million, which would have resulted in an impairment charge.  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 2012 Form 10-K.

 

RESULTS OF OPERATIONS

 

Earnings

 

The Company’s earnings were $67.9 million for the quarter ended December 31, 2012 compared with earnings of $60.7 million for the quarter ended December 31, 2011.  The increase in earnings of $7.2 million is primarily a result of higher earnings in the Pipeline and Storage segment and Utility segment.  Lower earnings in the Exploration and Production segment partially offset these increases.    

 

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.

 

 

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Utility

 

Utility Operating Revenues

 

Utility Throughput

 

Degree Days

 

⁽¹⁾  Percents compare actual 2012 degree days to normal degree days and actual 2012 degree days to actual 2011 degree days.

 

2012 Compared with 2011

 

Operating revenues for the Utility segment decreased $0.3 million for the quarter ended December 31, 2012 as compared with the quarter ended December 31, 2011.  This decrease resulted from a $1.8 million decrease in retail gas sales revenues, a $0.4 million decrease in off-system sales revenue (due to lower volumes), and a $0.4 million decrease in other revenue (largely due to lower capacity release revenues).  These were partially offset by a $2.3 million increase in transportation revenue.  The decrease in retail gas sales revenues was primarily due to the recovery of lower gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues) and was partially offset by the impact of a 0.8 Bcf increase in throughput (the result of colder weather, which more than offset the impact of migration of customers from retail sales to transportation services).  The recovery of lower gas costs resulted from a lower cost of purchased gas.  The Utility segment’s average cost of purchased gas, including the cost of transportation and storage, was $5.37 per Mcf for the three months ended December 31, 2012, a decrease of 7.1% from the average cost of $5.78 per Mcf for the three months ended December 31, 2011. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there is not a material impact to margins.  The increase in transportation revenues of $2.3 million was primarily due to a

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1.7 Bcf increase in transportation throughput, largely the result of colder weather and the migration of customers from retail sales to transportation services. 

 

The Utility segment’s earnings for the quarter ended December 31, 2012 were $22.9 million, an increase of $3.5 million when compared with earnings of $19.4 million for the quarter ended December 31, 2011.  The increase in earnings is due to lower operating expenses ($1.3 million), colder weather ($1.4 million) and lower income tax expense ($0.5 million).  The decrease in operating expenses was due to lower personnel costs. 

 

The impact of weather variations on earnings in the Utility segment’s New York rate jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC).  The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction.  In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers.  For the quarter ended December 31, 2012, the WNC preserved earnings of approximately $0.6 million, as the weather was warmer than normal.  For the quarter ended December 31, 2011, the WNC preserved earnings of approximately $1.4 million, as the weather was warmer than normal.  

 

Pipeline and Storage

 

Pipeline and Storage Operating Revenues

 

Pipeline and Storage Throughput

 

2012 Compared with 2011

 

Operating revenues for the Pipeline and Storage segment increased $10.0 million in the quarter ended December 31, 2012 as compared with the quarter ended December 31, 2011.  The increase was primarily due to an increase in transportation revenues of $7.6 million and an increase in storage revenues of $0.9 million.  The increase in transportation revenues was largely due to demand charges on new contracts for transportation service on Supply Corporation’s Line N 2012 Expansion Project, which was placed fully in service in November 2012, Supply Corporation’s Northern Access expansion project, which was partially placed in service in November 2012 and Empire’s Tioga County Extension Project, which was placed in service in November 2011.  These projects provide pipeline capacity for Marcellus Shale production. The Line N 2012 Expansion Project and the Northern Access expansion project are discussed in the Investing Cash Flow section that follows.  Additionally, effective May 2012, both transportation and storage revenues increased due to an overall net increase in tariff rates as a result of the implementation of Supply Corporation’s rate case settlement which was approved by FERC on August 6, 2012.  In addition to these increases, there was an increase in cashout revenues of $0.8 million (reported as a part of other revenue in the table above).  Cashout revenues are completely offset by purchased gas expense and as a result have no impact on earnings.  A gain of $0.6 million resulting from the sale of efficiency gas inventory (i.e., shipper-supplied gas retained in excess of operational needs) during the quarter ended December 31, 2012 also contributed to the increase in other revenue as shown in the table above.  This gain related to the sale of efficiency gas retained as inventory prior to May 1, 2012.  In accordance with Supply Corporation’s rate case settlement, shipper-supplied gas retained subsequent to May 1, 2012 is subject to a tracking mechanism that

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will adjust fuel retention rates annually to reflect actual experience, thus eliminating any future revenue and earnings impact to Supply Corporation.

 

Transportation volumes for the quarter ended December 31, 2012 increased by 40.2 Bcf from the prior year’s quarter.  The large increase in transportation volumes for the quarter primarily reflects the impact of the above mentioned expansion projects being placed in service.  Volume fluctuations generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

 

The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2012 were $16.9 million,  an increase of $6.9 million when compared with earnings of $10.0 million for the quarter ended December 31, 2011.  The increase in earnings is primarily due to the earnings impact of higher transportation and storage revenues of $5.5 million and the earnings impact associated with the sale of efficiency gas inventory ($0.4 million), as discussed above, combined with a decrease in depreciation expense ($1.0 million) and an increase in the allowance for funds used during construction (equity component) of $0.3 million.  The decrease in depreciation expense primarily reflects a decrease in depreciation rates as specified in Supply Corporation’s rate case settlement offset slightly by incremental depreciation expense related to the projects that were placed in service within the last year.  The increase in the allowance for funds used during construction is mainly due to construction during the quarter ended December 31, 2012 on Supply Corporation’s Northern Access and Line N 2012 expansion projects.

 

Exploration and Production

 

Exploration and Production Operating Revenues

 

⁽¹⁾    Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging)” in the table above that was sold to the gas processing plant shown in the table above.  An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense.

 

Production Volumes

 

 

 

 

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Average Prices

   

2012 Compared with 2011

 

Operating revenues for the Exploration and Production segment increased $19.5 million for the quarter ended December 31, 2012 as compared with the quarter ended December 31, 2011.  Gas production revenue after hedging increased $16.3 million, due to an increase in production which was partially offset by a $0.69 per Mcf decrease in the weighted average price of natural gas after hedging.  The increase in Appalachian production was primarily due to increased development within the Marcellus Shale formation, mainly in Lycoming County, Pennsylvania with additional Marcellus Shale production from Tioga County, Pennsylvania.  Oil production revenue after hedging increased $3.4 million, due to a $5.31 per Bbl increase in the weighted average price of crude oil after hedging as production was flat quarter over quarter.

 

The Exploration and Production segment's earnings for the quarter ended December 31, 2012 were $26.7 million, a decrease of $3.6 million when compared with earnings of $30.3 million for the quarter ended December 31, 2011.  Higher natural gas production and higher realized crude oil prices (after hedging) increased earnings by $19.6 million and $2.5 million, respectively.  However, these items were more than offset by lower natural gas prices after hedging ($9.0 million), higher depletion expense ($6.8 million), higher lease operating expenses ($4.6 million), higher general, administrative and other operating expenses ($3.0 million), higher interest expense ($2.2 million), and lower crude oil production ($0.3 million).  The increase in depletion expense is primarily due to an increase in the depletable base (due to increased capital spending in the Appalachian region within the last few years) and higher production.  The increase in lease operating expense is largely attributable to higher transportation, compression, and water disposal costs in the Appalachian region coupled with higher well repair, maintenance, and labor costs in the West Coast region.  The increase in general, administrative and other operating expenses was largely due to the termination of a lease for a drilling rig as part of the Company’s overall plan to reduce future Appalachian capital expenditures in light of lower natural gas prices.  The increase in interest expense was attributable to an increase in the weighted average amount of debt (due to the Exploration and Production segment’s share ($470 million) of the $500 million long-term debt issuance in December 2011).  

 

Energy Marketing

 

Energy Marketing Operating Revenues