EQT Corporation - 10-Q quarterly report FY

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

EQUITABLE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ý  No  o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes  ý  No  o

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

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

PART I. FINANCIAL INFORMATION

Item 1.           Financial Statements

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

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Equitable Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

A.                        Financial Statements

The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Equitable Resources, Inc. and its consolidated subsidiaries. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of Equitable Resources, Inc. and subsidiaries as of September 30, 2005, and the results of its operations and cash flows for the three- and nine-month periods ended September 30, 2005 and 2004.

The balance sheet at December 31, 2004 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.

Due to the seasonal nature of the Company’s natural gas distribution and energy marketing businesses and the volatility of natural gas prices, the interim statements for the three- and nine-month periods ended September 30, 2005 are not necessarily indicative of the results that may be expected for the year ending December 31, 2005.

For further information, refer to the consolidated financial statements and footnotes thereto included in Equitable Resources’ Annual Report on Form 10-K for the year ended December 31, 2004, as well as in “Information Regarding Forward Looking Statements” on page 16 of this document.

B.                        Segment Information

The Company reports its operations in three segments, which reflect its lines of business. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income and earnings from nonconsolidated investments. Interest expense and income taxes are managed on a consolidated basis.

Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in the United States.

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C.                                    Derivative Instruments

Natural Gas Hedging Instruments

The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Exchange-traded instruments are generally settled with offsetting positions. Over the Counter (OTC) arrangements require settlement in cash. The fair value of these derivative commodity instruments was a $146.0 million asset and a $1.5 billion liability as of September 30, 2005, and a $26.8 million asset and a $350.4 million liability as of December 31, 2004. These amounts are included in the Condensed Consolidated Balance Sheets as derivative instruments, at fair value. The net amount of derivative instruments, at fair value, changed from a net liability of $323.6 million at December 31, 2004 to a net liability of $1.4 billion at September 30, 2005, primarily as a result of the increase in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 436.0 Bcf and 432.6 Bcf as of September 30, 2005 and December 31, 2004, respectively, and primarily related to natural gas swaps. The open positions at September 30, 2005 had maturities extending through December 2012.

The Company deferred net losses of $839.9 million and $197.3 million in accumulated other comprehensive loss, net of tax, as of September 30, 2005 and December 31, 2004, respectively, associated with the effective portion of the change in fair value of its derivative instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $387.5 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of September 30, 2005 will be recognized in earnings during the next twelve months. This recognition occurs through a reduction in the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.

For the three months ended September 30, 2005, ineffectiveness associated with the Company’s derivative instruments designated as cash flow hedges increased earnings by approximately $0.5 million while it decreased earnings by approximately $0.4 million for the three months ended September 30, 2004. These amounts are included in operating revenues in the Statements of Consolidated Income.

The Company conducts trading activities through its unregulated marketing group. The function of the Company’s trading business is to contribute to the Company’s earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy.

The absolute notional quantities of the futures and swaps held for trading purposes at September 30, 2005 totaled 14.4 Bcf and 54.3 Bcf, respectively.

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Below is a summary of the activity of the fair value of the Company’s derivative commodity contracts with third parties held for trading purposes during the nine months ended September 30, 2005 (in thousands).

The following table presents maturities and the fair valuation source for the Company’s derivative commodity instruments that are held for trading purposes as of September 30, 2005.

Net Fair Value of Third Party Contract (Liabilities) Assets at Period-End

(1) Contracts include futures and fixed price swaps

(2) Contracts include basis swaps

When the net fair value of any of the swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company recorded such deposits in the amount of $382.7 million as accounts receivable in its Condensed Consolidated Balance Sheet as of September 30, 2005.

When the Company enters into exchange-traded natural gas contracts, exchanges require participants, including the Company, to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related contract and are subject to change at the exchanges’ discretion. The Company recorded such margin deposits in the amount of $167.2 million as accounts receivable in its Condensed Consolidated Balance Sheet as of September 30, 2005.

As part of the purchase of the limited partnership interest in Eastern Seven Partners, L.P. (ESP), as discussed in Note N, the Company assumed derivative liabilities of $47.3 million for the fair value of ESP’s hedges. These hedges were effectively closed out at acquisition by the purchase of offsetting positions. The Company does not treat these derivatives as hedging instruments under Statements of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The fair value of these derivative instruments at September 30, 2005 was a $38.6 million liability. These amounts are included in the Condensed Consolidated Balance Sheet as derivative instruments, at fair value.

In May 2005, the Company sold certain non-core gas properties, as discussed in Note N. As part of this transaction, the Company closed out certain cash flow hedges associated with forecasted production at these locations by purchasing offsetting positions. The Company does not treat these derivatives as hedging instruments under SFAS 133. The fair value of these derivative instruments at September 30, 2005 was a $22.0 million liability. These amounts are included in the Condensed Consolidated Balance Sheet as derivative instruments, at fair value.

D.                                    Investments

In September 2005, the Company sold approximately 0.4 million Kerr-McGee Corporation (Kerr-McGee) shares for total proceeds of $40.6 million. The sale of those shares resulted in a pre-tax gain to the Company of $19.4 million.

As of September 30, 2005, the Company held approximately 0.7 million Kerr-McGee shares, which were held for sale. See Note R.

The Company recorded pre-tax dividend income related to the Kerr-McGee shares of $1.2 million and $1.6 million for the nine months ended September 30, 2005 and 2004, respectively. This dividend income is recorded in other income, net on the Statements of Consolidated Income.

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In April 2005, the Company sold approximately 1.0 million unhedged Kerr-McGee shares for total proceeds of $77.9 million. The sale of these shares resulted in a pre-tax gain to the Company of $26.7 million.

In July 2004, the Company entered into three 7.5 year secured variable share forward transactions in association with the Westport Resources Corporation (Westport)/Kerr-McGee merger, each covering 2.0 million shares of Kerr-McGee common stock. The related collars effectively limited the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares.

In May 2005, the Company terminated the three variable share forward transactions. In connection with the termination, the Company incurred a termination cost of $95.8 million and sold 4.3 million Kerr-McGee shares to its three counterparties to cover its counterparties’ respective hedged positions. The Company received $227.4 million in pre-tax net proceeds from the sale of the Kerr-McGee shares net of the termination cost. In addition, the Company unconditionally tendered 1.7 million Kerr-McGee shares at $85.00 per share to Kerr-McGee in connection with Kerr-McGee’s Dutch auction tender offer to purchase its own shares. Accordingly, as a result of its tender of shares, the Company received approximately $49 million in pre-tax proceeds on the sale of approximately 0.6 million shares.

In the second quarter of 2004, Westport and Kerr-McGee completed a merger. Under the terms of the merger agreement, the Company received 0.71 shares of Kerr-McGee for each Westport share owned, or 8.2 million shares of Kerr-McGee. Accordingly, the Company recognized a gain of $217.2 million on the exchange of the Westport shares for Kerr-McGee shares in the second quarter of 2004.

Subsequent to the Westport/Kerr-McGee merger, the Company sold 800,000 Kerr-McGee shares for proceeds of $42.9 million in the second quarter of 2004. The sale resulted in the Company recognizing a gain of $3.0 million in the second quarter of 2004.

On June 30, 2004, the Company committed to contribute 357,000 Kerr-McGee shares to Equitable Resources Foundation, Inc. This resulted in the Company recording a charitable foundation contribution expense of $18.2 million during the second quarter of 2004, with a corresponding one-time tax benefit of $6.8 million.

As of September 30, 2005, the investments classified by the Company as available-for-sale included a $69.3 million investment in Kerr-McGee and $24.8 million of debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures through a wholly-owned subsidiary.

E.                                      Comprehensive Loss

Total comprehensive loss, net of tax, was as follows:

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The components of accumulated other comprehensive loss, net of tax, are as follows:

F.                                      Stock-Based Compensation

Restricted stock grants in the aggregate amount of 75,400 shares were awarded to various employees during the first nine months of 2005. The related expense recognized during the nine-month period ended September 30, 2005 was $2.5 million and is classified as a selling, general and administrative expense in the Statements of Consolidated Income.

The Company continually monitors its stock price and relative return in order to assess the impact on the projected payout under each Executive Performance Incentive Program (the “Programs”). The Company’s share price assumptions used to determine the accrual for the Programs are $39.06 per share at the end of 2005 (for the 2003 Program) and $40.00 per share at the end of 2008 (for the 2005 Program). As a result of the Company’s significant stock appreciation during the second and third quarters of 2005, the Company recognized an expense of $15.3 million for the three months ended September 30, 2005 and an expense of $29.9 million for the nine months ended September 30, 2005 associated with the Programs. The related long-term incentive expenses are included in selling, general and administrative expenses in the Statements of Consolidated Income. A portion of the long-term incentive expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note B.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock Based Compensation” (SFAS No. 123) to its employee stock-based awards.

G.                                    Income Taxes

The Company estimates an annual effective income tax rate based on projected results for the year and applies this rate to income before taxes to calculate income tax expense. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period. Separate effective income tax rates are calculated for net income from continuing operations and any other separately reported net income items, such as discontinued operations, extraordinary items and cumulative effects of accounting changes.

Congress passed the American Jobs Creation Act of 2004, which the President signed into law on October 22, 2004. On September 29, 2005, the Treasury Department and the Internal Revenue Service issued proposed regulations providing deferred compensation guidance under the new legislation. During the third quarter of 2005, the Company continued its review of the legislation’s impact on its executive compensation plans. In anticipation that the Company’s executive compensation plans are expected to be changed by the Compensation Committee of the Board of Directors by

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December 31, 2005, the Company adjusted its valuation allowance against the deferred tax benefit associated with the projected payout of these programs to $10.3 million.

The $10.3 million valuation allowance is included in the annual income tax expense related to continuing operations. The effective tax rate for the nine months ended September 30, 2005 was therefore 37.2%. The Company currently estimates the annual effective income tax rate to be approximately 36.4%, or 33.8% excluding the $10.3 million charge. The estimated annual effective income tax rate as of September 30, 2004 was 34.3%.

H.                                    Pension and Other Postretirement Benefit Plans

The Company has defined benefit pension and other postretirement benefit plans covering represented employees that generally provide benefits of stated amounts for each year of service. During the third quarter of 2005, the Company settled its pension obligation with the United Steelworkers of America, Local Union 12050 representing 182 employees. As a result of this settlement, which was accounted for under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement expense of $12.7 million during the three months ended September 30, 2005. The settlement expense was primarily the result of accelerated recognition of unrecognized losses. As part of this settlement, the affected employees were provided the option to either roll over the lump-sum value of their pension benefit to the Company’s defined contribution plan or to receive an insured monthly annuity benefit at the time they retire. Additionally, this pension settlement expense is a selling, general and administrative expense included within operating expense of the Equitable Utilities business segment (see Note B). The Company’s ongoing pension obligation decreased by approximately $12.9 million as a result of the settlement.

The Company made a cash contribution of approximately $11.1 million to the pension plan in the second quarter of 2005 to fully fund the participants’ cash balance portion of the pension plan which was settled effective December 31, 2004. The Company made an additional contribution of approximately $1.5 million during the third quarter of 2005 in order to purchase annuities for participants choosing to receive benefits under an insurance contract. The Company expects to make a cash contribution of approximately $8.6 million to its pension plan during the fourth quarter of 2005 to fully fund the previously discussed settlement of the United Steelworkers of America, Local Union 12050 obligation.

The Company’s costs related to its defined benefit pension and other postretirement benefit plans for the three and nine months ended September 30, 2005 and 2004 were as follows:

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I.                                         Recently Issued Accounting Standards

Stock Compensation

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123R). This guidance replaced previously existing requirements under SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB Opinion No. 25). Under SFAS No. 123(R), an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The compensation cost of the award would generally be measured based on the grant-date fair value of the award. The Company will be required to adopt SFAS No. 123(R) beginning with its 2006 fiscal year.

The Company has determined that the impact of SFAS No. 123(R) will not be material to its financial statements. In accordance with SFAS No. 123, the Company has historically disclosed the impact on the Company’s net income and earnings per share had the fair value based method been adopted.  Had the Company adopted SFAS No. 123(R) in prior periods, the impact of that standard on periods presented in these Condensed Consolidated Financial Statements would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in Note F.

Asset Retirement Obligations

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47). This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN No. 47 will be effective for the Company at the end of the fiscal year ended December 31, 2005. FIN No. 47 is not expected to have a significant impact on the Company’s financial position or results of operations.

Accounting for Uncertain Tax Positions

In July 2005, the FASB issued an exposure draft of a proposed Interpretation, “Accounting for Uncertain Tax Positions – an Interpretation of FASB Statement No. 109.”   The proposed Interpretation would apply to all open tax positions accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes,” including those acquired in business combinations, and was proposed to be effective for the Company for the fiscal year ending December 31, 2005. The final interpretation has not been issued yet and may therefore not be effective for the fiscal year ending December 31, 2005. The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final interpretation is issued.

J.                                      International Investments

During the second quarter of 2004, several negative circumstances caused the Company to revisit its international investments for additional impairments and to accelerate its plans to exit the international power generation business. As a result, the Company performed an impairment analysis of its equity interests in international projects during the second quarter of 2004. The Company recorded impairment charges totaling $40.2 million in the second quarter of 2004.

These charges included various costs and obligations related to exiting NORESCO’s investments in international power plant projects. These various costs and obligations were reviewed during the first nine months of 2005 and were reduced by $7.2 million primarily as a result of bringing the remaining power plant located in Panama into compliance with local noise restrictions without incurring costs that had previously been expected, the financial condition of the project, and the elimination of liquidity support.

The Company recorded earnings on its international investments in the amount of $1.5 million during the third quarter of 2005, due to the award of a new contract to sell electricity that has provided for improved forecasted cash flows for the power plant project in Panama.

K.                                    Prepaid Natural Gas Forward Contract

In 2000, the Company entered into two prepaid natural gas sales contracts pursuant to which the Company was required to sell and deliver natural gas during the term of the contracts. The first contract was for five years; the

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second contract was for three years and was completed at the end of 2003. These contracts were recorded as prepaid forward sales and were recognized in income as deliveries occurred.

In June 2004, the Company amended the remaining prepaid natural gas contract, which was viewed as debt by the rating agencies. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. The Company repaid the counterparty $36.8 million, removed the prepaid forward sale from the balance sheet and recorded a loss of $5.5 million in other income, net in the Statements of Consolidated Income for the nine months ended September 30, 2004, reflecting the difference between the net present value of the underlying quantities and the remaining unamortized balance recorded as deferred revenue.

L.                                     Insurance Settlement

On April 14, 2004, the Company settled a disputed property insurance coverage claim involving the Kentucky West Virginia unit of the Supply segment. As a result of the settlement, the Company recognized income of approximately $6.1 million for the nine months ended September 30, 2004. The insurance proceeds are included in other income, net, in the Statements of Consolidated Income.

M.                                  Office Consolidation / Impairment Charges

In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The relocation resulted in the early termination of several operating leases and the early retirement of assets and leasehold improvements at several locations. In accordance with SFAS No. 146, “Accounting for Costs associated with Exit or Disposal Activities,” the Company recognized a loss of $5.3 million on the early termination of operating leases during the second quarter of 2005 for facilities deemed to have no economic benefit to the Company. The Company also recognized a loss on impairment of assets of $2.5 million during the nine months ended September 30, 2005 in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” associated with the office consolidations.

N.                                    Other Events

The Company retained Lincoln Partners LLC to assist it in considering strategic alternatives for its NORESCO segment, including but not limited to a sale, merger or other business combination.

On September 30, 2005, the Company issued $150 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015. The notes were approved by the Pennsylvania Public Utility Commission (PA PUC) on October 27, 2005. The effective annual interest rate on the $150 million of notes is 5.06%.

On August 11, 2005, the Company entered into a $650 million, 5-year revolving credit agreement, which may be used for working capital, capital expenditures, share repurchases and other lawful purposes including support of the Company’s commercial paper program. This agreement replaces the Company’s previous $500 million, three-year revolving credit agreement. Subject to certain terms and conditions the Company may on a one-time basis request that the lenders’ commitments be increased to an aggregate amount of up to $1 billion. The new facility has a maturity date of August 10, 2010 upon satisfaction of certain requirements relating to approval of the facility by the PA PUC which was received on October 27, 2005. Additionally, the Company may request two one-year extensions of the maturity date.

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for approximately $147 million. The proceeds were subject to $5.7 million of purchase price adjustments. The sale resulted in a decrease of 59 Bcf of proved developed reserves and 7 Bcf of proved undeveloped reserves.

In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million. The purchase added approximately 30 Bcfe of reserves.

O.                                   Stock Split

On July 13, 2005, the Board of Directors of the Company declared a two-for-one stock split payable September 1, 2005, to shareholders of record on August 12, 2005. In connection with the stock split, the Company amended its articles of incorporation to reflect the increased number of authorized shares of common stock. All share and per share information has been retroactively adjusted to reflect the stock split.

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P.                                     Share Repurchase Authorization Increase

On July 13, 2005, the Board of Directors of the Company increased the Company’s share repurchase authorization by 6.4 million shares to 50.0 million shares.

Q.                                   Reclassification

Certain previously reported amounts have been reclassified to conform to the 2005 presentation. These reclassifications did not affect reported net income or cash flows.

R.                                    Subsequent Events

In October 2005, the Company sold approximately 0.7 million Kerr-McGee shares for total proceeds of $65.6 million. The sale of these shares resulted in a pre-tax gain of $30.0 million. Following this sale, the Company has no further interest or ownership in any Kerr-McGee shares.

In October 2005, the Board of Directors of the Company authorized an increase in the Company’s short term borrowing authorization from $650 million to $1.0 billion.

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Equitable Resources, Inc. and Subsidiaries

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

INFORMATION REGARDING FORWARD LOOKING STATEMENTS

Disclosures in this Quarterly Report on Form 10-Q contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “should,” “anticipate,” “estimate,” “forecasts,” “approximate,” “expect,” “may,” “will,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned “Outlook” in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s drilling program, production volumes, and earnings. A variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, the following:

•       the impact of adverse weather conditions on commodity prices, Equitable Utilities’ operations, and Equitable Supply’s  well drilling program

•       the volatility of the price of natural gas and the effect of changing prices on the Company’s revenues, hedging, well drilling activities, production taxes, and collections

•       the need for, and availability and cost of, financing, including changes to the Company’s debt ratings by S&P and Moody’s

•       the implementation and execution of operational enhancements and cost control initiatives

•       the effect of curtailments or other disruptions in production and gathering

•       the substance, timing and availability of regulatory and legislative actions, initiatives and proceedings

•       the Company’s success in implementing acquisition or divestiture activities

•       the ability of the Company to develop, produce, gather, and market reserves, including its ability to substantially increase well drilling activity

•       the inherent uncertainty of estimating gas reserves and projecting future rates of production and reserve development

•       the ability of the Company to acquire and apply technology to its operations

•       the impact of competitive factors, including consolidation in the utility industry

•       the ability of the Company to maintain good working relations with its represented employees and to retain its key personnel

•       changes in the market price of the common stock of Equitable Resources, Inc. and its peer group

•       general economic and political conditions

•       changes in accounting rules or their interpretation, and

•       other factors discussed in other reports filed by the Company from time to time.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.

CORPORATE OVERVIEW

Three Months Ended September 30, 2005
vs. Three Months Ended September 30, 2004

Equitable Resources’ consolidated net income for the three months ended September 30, 2005 totaled $46.5 million, or $0.38 per diluted share, compared to $35.7 million, or $0.28 per diluted share, reported for the same period a year ago. In the third quarter of 2005, the Company sold 0.4 million Kerr-McGee shares for a gain of $19.4 million.

Operating income for the quarter decreased to $58.0 million in 2005 from $64.5 million in 2004 primarily due to increased long-term incentive expenses associated with the Company’s Executive Performance Incentive Programs and a charge for the termination and settlement of a defined benefit pension plan for employees in the Equitable Utilities segment. For further discussion of the Company’s long-term incentive expense, see the “Incentive Compensation” section in the Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The impact of these items was offset somewhat by an increase in average natural gas prices and an increase in sales volumes from production primarily related to the acquisition of the limited partnership interest in ESP.

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Three Months Ended September 30, 2005
vs. Three Months Ended September 30, 2004

Equitable Utilities’ incurred an operating loss of $7.5 million for the three months ended September 30, 2005 compared to operating income of $3.7 million for the three months ended September 30, 2004. The net change in operating income was primarily a result of a $12.7 million charge in the current quarter for the termination and settlement of a defined benefit pension plan.

Net operating revenues were $36.2 million for the three months ended September 30, 2005 compared to $35.0 million for the three months ended September 30, 2004. The $1.2 million increase in net operating revenues was due to a $3.2 million increase in energy marketing revenues, including the recognition of certain amounts previously deferred, and a $0.3 million increase in gathering revenues, offset somewhat by decreases of $1.2 million in Distribution Operations’ revenues and $0.8 million in Pipeline Operations revenues. Distribution Operations’ residential sales and transportation volumes decreased 204 MMcf from the three months ended September 30, 2004 to the three months ended September 30, 2005 primarily due to warmer September weather and a slight decrease in baseload usage. Distribution Operations’ commercial and industrial volumes decreased 1,222 MMcf from the three months ended September 30, 2004 to the three months ended September 30, 2005 primarily due to decreased purchases by two large industrial end use customers. Because these industrial sales generate small margins, the decreased volumes did not  significantly impact net operating revenues. Pipeline Operations’ total transportation throughput decreased 2,695 Bbtu from the three months ended September 30, 2004 to the three months ended September 30, 2005 primarily due to a reduction in firm transportation volumes resulting from the expiration of certain capacity contracts in the second quarter of 2005. The available capacity was remarketed by Pipeline Operations as lending and parking services. Revenue will be recognized when physical delivery occurs on these lending and parking services.

Operating expenses totaled $43.6 million for the three months ended September 30, 2005 compared to $31.3 million for the three months ended September 30, 2004. Operating expenses increased by $12.3 million primarily due to the $12.7 million pension charge described previously. SG&A expenses increased by $11.3 million primarily due to the $12.7 million pension charge offset by a $1.3 million reduction in bad debt expense, due to improved collections. DD&A expense decreased $0.5 million due to increases in the estimated useful lives for Equitable Gas’ main lines and service lines based on a PA PUC mandated asset service life study approved in the fourth quarter of 2004. Offsetting these improvements, a $1.5 million increase in O&M expense was primarily due to increased costs for fringe benefits ($0.5 million), pipeline gathering operations ($0.4 million), distribution customer collections ($0.3 million), and increased vehicle operation and maintenance costs in both the Distribution Operations and Pipeline Operations ($0.4 million).

Capital expenditures totaled $18.7 million for the three months ended September 30, 2005 compared to $13.9 million for the three months ended September 30, 2004. This $4.8 million increase was primarily due to the current year implementation of automated meter reading equipment on residential and commercial meters. This $17.5 million project commenced in the second quarter of 2005 and is expected to be completed in 2006.

Nine Months Ended September 30, 2005
vs. Nine Months Ended September 30, 2004

Equitable Utilities’ operating income totaled $60.6 million for the nine months ended September 30, 2005 compared to $70.7 million for the nine months ended September 30, 2004. The net change in operating income was primarily a result of the $12.7 million pension settlement expense and $3.8 million impairment charge in connection with the Company’s office consolidation incurred in the second quarter of 2005 offset by increased energy marketing revenues and reduced bad debt expense.

Net operating revenues were $177.5 million for the nine months ended September 30, 2005 compared to $173.6 million for the nine months ended September 30, 2004. The $3.9 million increase in net operating revenues was due to increased energy marketing and gathering revenues, partially offset by reductions in residential and industrial sales and pipeline transportation volumes. Heating degree days were 3,465 for the nine months ended September 30, 2005, which was substantially the same as the 3,533 heating degree days for the nine months ended September 30, 2004. Distributions Operations’ residential sales and transportation volumes decreased 1,454 MMcf from the nine months ended September 30, 2004 to the nine months ended September 30, 2005 primarily due to the slightly warmer weather and a small decrease in baseload usage. Distributions Operations’ commercial and industrial volumes decreased 3,872 MMcf from the nine months ended September 30, 2004 to the nine months ended September 30, 2005 primarily due to decreased demand from large industrial customers. Pipeline Operations’ total transportation throughput decreased 8,423 Bbtu from the nine months ended September 30, 2004 to the nine months ended September 30, 2005 primarily due to the expiration of certain firm transportation contracts. Revenue will be recognized when physical delivery occurs on these lending and parking services.

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Operating expenses totaled $116.9 million for the nine months ended September 30, 2005 compared to $102.9 million for the nine months ended September 30, 2004. Operating expenses increased by $14.0 million primarily due to the pension settlement expense of $12.7 million and the office consolidation impairment charge of $3.8 million, both described previously. SG&A expenses increased $6.5 million primarily due to the $12.7 million pension charge and the $3.8 million office consolidation impairment charge offset by a $5.9 million reduction in bad debt expense, of which $2.0 million was attributable to an above normal reserve rate in the second quarter of 2004, with the balance a result of progress made on collections. The $1.9 million decrease in DD&A was primarily due to increased asset lives, from the mandated asset study described previously. These expense reductions over the nine month period are partially offset by a $5.6 million increase in O&M, primarily due to increases in fringe benefit rates ($2.1 million), customer collections expenses ($1.4 million), field gathering expenses ($0.8 million), and vehicle maintenance expenses ($0.6 million).

OUTLOOK

The interstate pipeline operations of Equitrans, L.P. (Equitrans) are subject to rate regulation by the Federal Energy Regulatory Commission (FERC). As a condition of Equitrans’ last FERC-approved rate settlement, the Company was obligated to file a rate case. The rate case applications filed to meet Equitrans’ filing obligation address several issues including establishing an appropriate return on the Company’s capital investments, the Company’s pension funding levels and accruing for post-retirement benefits other than pensions. The Company’s filed request for rate relief was for an aggregate annual amount of approximately $17.2 million.

Equitrans began charging the proposed rates, subject to refund, for its core services on September 1, 2004, and for its non-core services on December 1, 2004, consistent with orders issued by the FERC. Accordingly, Equitrans has set up a reserve, which will be adjusted upon ultimate resolution of the rate case.

Effective January 1, 2005, the Company reorganized its gathering business, subject to receipt of applicable approvals. This reorganization is consistent with the Company’s initiative to separate its production and gathering businesses in order to ensure that all gathering costs are appropriately captured and gathering rates charged to customers include a proper return. As a result, Equitrans effectively acquired certain gathering assets located in West Virginia from its affiliate, Equitable Field Services, LLC. The assets acquired by Equitrans overlap and are interconnected with gathering assets already owned and operated by Equitrans. The majority of the volumes that flow on these gathering assets are delivered to Equitrans’ transmission system. On January 28, 2005, Equitrans filed a limited rate case application with the FERC to consolidate the rates and operations of the Company’s interconnected and overlapping gathering facilities located in West Virginia and southern Pennsylvania, including the assets acquired on January 1, 2005. On February 28, 2005, in accordance with the Natural Gas Act, the FERC accepted and suspended the Company’s filing with the consolidated gathering rates to be effective August 1, 2005, subject to refund and to the outcome of a hearing. On August 1, 2005, Equitrans placed its suspended rates into effect as per the FERC’s order issued February 28, 2005.

On March 4, 2005, Equitrans requested and received approval to consolidate all of its rate applications pending before the FERC. Throughout the second and third quarters of 2005, numerous settlement conferences have been held with all active parties to the case, including the FERC’s staff, and given the progress made during these negotiations, multiple extensions to the procedural schedule (including the testimony filing and hearing dates) have been sought and obtained by Equitrans. On September 21, 2005, an agreement in principle was achieved with all but one of Equitrans’ storage and transmission customers (leaving only the issues associated with Equitrans’ gathering rates outstanding). Negotiations on gathering rate issues have been ongoing and are nearing completion. Equitrans is continuing to advance settlement discussions in this proceeding with the goal of achieving a comprehensive resolution of these cases.

Equitable Gas Company, the Company’s regulated distribution operation, continues to work with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based rate making. Performance-based incentives provide an opportunity for Equitable Gas to make short-term releases of unutilized pipeline capacity, i.e. “capacity releases,” for a fee or to participate in the bundling of gas supply and pipeline capacity for “off-system” sales. An “off-system” sale involves the purchase and delivery of gas to a customer at mutually agreed-upon points on facilities not owned by the Company. Equitable Gas’ performance-based purchased gas cost credit incentive and a second PA PUC approved performance-based initiative related to balancing services were available through September 2005. Effective September 30, 2005, an Opinion and Order issued by the PA PUC modified the performance-based purchased gas cost credit design on a prospective basis, providing Equitable Gas with a 25% sharing level of capacity releases and off-system sales, and terminating the Company’s balancing service performance-based incentive. Equitable Gas has filed a petition for reconsideration and clarification with the PA PUC and is awaiting a final Order.

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