EQUITABLE RESOURCES INC /PA/ - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

		FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005

		or

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

		FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-3551

EQUITABLE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

PENNSYLVANIA		25-0464690
(State of incorporation or organization)		(IRS Employer Identification No.)

One Oxford Centre, Suite 3300, 301 Grant Street, Pittsburgh, Pennsylvania 15219

(Address of principal executive offices, including zip code)

Registrant’s telephone number, including area code: (412) 553-5700

NONE

(Former name, former address and former fiscal year, if changed since last report)

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

Class		Outstanding at March 31, 2005

Common stock, no par value		60,912,008 shares

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

	Three Months Ended March 31,
	2005			2004
	(Thousands, except per share amounts)
Operating revenues	$	439,767		$	400,427
Cost of sales	217,293			197,596
Net operating revenues	222,474			202,831

Operating expenses:
Operation and maintenance	23,843			18,698
Production	14,170			10,087
Selling, general and administrative	30,121			32,752
Depreciation, depletion and amortization	23,439			21,767
Total operating expenses	91,573			83,304

Operating income	130,901			119,527

Earnings from nonconsolidated investments:
International investments	1,159			716
Other	108			185
	1,267			901
Other income, net	1,138			—
Minority interest	(439		)	(370		)
Interest expense	13,965			12,259
Income before income taxes	118,902			107,799
Income taxes	42,496			37,729
Net income	$	76,406		$	70,070

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	60,712			62,256
Net income	$	1.26		$	1.13
Diluted:
Weighted average common shares outstanding	62,175			63,531
Net income	$	1.23		$	1.10
Dividends declared per common share	$	0.42		$	0.38

The accompanying notes are an integral part of these condensed consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Condensed Consolidated Cash Flows (Unaudited)

	Three Months Ended March 31,
	2005			2004
	(Thousands)
Cash flows from operating activities:
Net income	$	76,406		$	70,070
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for losses on accounts receivable	5,611			6,481
Depreciation, depletion, and amortization	23,439			21,767
Deferred income taxes	2,624			2,706
Recognition of prepaid forward production revenue	—			(5,182		)
Change in undistributed earnings from nonconsolidated investments	(108		)	(901		)
Decrease in inventory	98,422			83,535
Increase in accounts receivable and unbilled revenues	(137,640		)	(31,492		)
Changes in other assets and liabilities	(33,346		)	(1,421		)
Total adjustments	(40,998		)	75,493
Net cash provided by operating activities	35,408			145,563

Cash flows from investing activities:
Capital expenditures	(43,990		)	(35,870		)
Purchase of interest in Eastern Seven Partners L.P.	(57,500		)	—
Investment in available-for-sale securities	(3,448		)	—
Proceeds from sale of investment interest in Dona Julia	3,000			—
Distributions from nonconsolidated investments	245			498
Net cash used in investing activities	(101,693		)	(35,372		)

Cash flows from financing activities:
Dividends paid	(22,935		)	(18,743		)
Purchase of treasury stock	(17,130		)	(15,076		)
Proceeds from exercises under employee compensation plans	3,038			7,573
Loans against construction contracts	9,743			12,760
Repayments and retirement of long-term debt	(140		)	(10,129		)
Increase (decrease) in short-term loans	96,500			(118,601		)
Net cash provided by (used in) financing activities	69,076			(142,216		)

Net increase (decrease) in cash and cash equivalents	2,791			(32,025		)
Cash and cash equivalents at beginning of period	—			37,334
Cash and cash equivalents at end of period	$	2,791		$	5,309

Cash paid during the period for:
Interest, net of amount capitalized	$	16,968		$	15,280
Income taxes paid, net of refund	$	12,015		$	9

The accompanying notes are an integral part of these condensed consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	March 31, 2005		December 31, 2004
	(Thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	2,791	$	—
Accounts receivable (less accumulated provision for doubtful accounts: March 31, 2005, $38,929; December 31, 2004, $31,336)	376,382		238,560
Unbilled revenues	157,428		149,060
Inventory	105,463		204,585
Derivative instruments, at fair value	76,044		27,585
Prepaid expenses and other	20,083		32,859
Total current assets	738,191		652,649

Equity in nonconsolidated investments	35,650		64,556

Property, plant and equipment	3,108,225		2,967,916

Less accumulated depreciation and depletion	1,109,166		1,088,129

Net property, plant and equipment	1,999,059		1,879,787

Investments, available-for-sale	574,418		426,772

Other assets	172,440		172,782

Total	$	3,519,758	$	3,196,546

The accompanying notes are an integral part of these condensed consolidated financial statements.

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	March 31, 2005			December 31, 2004
	(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	10,596		$	10,582
Short-term loans	391,999			295,499
Accounts payable	168,562			187,797
Derivative instruments, at fair value	865,029			350,382
Current portion of project financing obligations	32,453			31,329
Other current liabilities	106,100			139,728
Total current liabilities	1,574,739			1,015,317

Long-term debt:
Debentures and medium-term notes	617,615			617,769

Deferred and other credits:
Deferred income taxes	369,700			486,241
Deferred investment tax credits	10,776			11,037
Project financing obligations	83,121			73,281
Other credits	114,782			118,229
Total deferred and other credits	578,379			688,788

Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares; shares issued: March 31, 2005 and December 31, 2004, 74,504	361,082			356,892
Treasury stock, shares at cost: March 31, 2005, 13,591; December 31, 2004, 13,473 (net of shares and cost held in trust for deferred compensation of 662, $12,899 and 642, $12,303)	(406,552		)	(389,450		)
Retained earnings	1,141,048			1,087,577
Accumulated other comprehensive loss	(346,553		)	(180,347		)

Total common stockholders’ equity	749,025			874,672

Total	$	3,519,758		$	3,196,546

The accompanying notes are an integral part of these condensed consolidated financial statements.

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 instructions to 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 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 (the Company or Equitable Resources or Equitable) as of March 31, 2005, and the results of its operations and cash flows for the three-month periods ended March 31, 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-month period ended March 31, 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 17 of this document.

B. Segment Information

The Company reports its operations in three segments, which reflect its lines of business. The Equitable Utilities segment’s operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline gathering, transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas, and limited trading activities. The Equitable Supply segment’s activities comprise the development, production, gathering, marketing and sale of natural gas and a small amount of associated oil, and the extraction and sale of natural gas liquids. The NORESCO segment provides an integrated group of energy-related products and services that are designed to reduce its customers’ operating costs and improve their energy efficiency. The segment’s activities comprise performance contracting, energy efficiency programs, combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation.

Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, earnings from nonconsolidated investments, minority interest, and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.

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

	Three Months Ended March 31,
	2005			2004
	(Thousands)
Revenues from external customers:
Equitable Utilities	$	299,068		$	281,374
Equitable Supply	113,275			99,244
NORESCO	38,491			33,926
Less: intersegment revenues (a)	(11,067		)	(14,117		)
Total	$	439,767		$	400,427
Total operating expenses:
Equitable Utilities	$	36,893		$	37,806
Equitable Supply	47,922			37,714
NORESCO	6,224			6,035
Unallocated expenses	534			1,749
Total	$	91,573		$	83,304
Operating income:
Equitable Utilities (b)	$	62,377		$	55,960
Equitable Supply	65,353			61,530
NORESCO	3,705			3,786
Unallocated expenses	(534		)	(1,749		)
Total operating income	$	130,901		$	119,527

Reconciliation of operating income to net income:

Earnings from nonconsolidated investments:
Equitable Supply	$	47		$	143
NORESCO	1,178			720
Unallocated	42			38
Total	$	1,267		$	901
Other income, net:
Unallocated (c)	1,138			—
Total	$	1,138		$	—
Minority interest:
NORESCO	$	(439	)	$	(370	)
Total	$	(439	)	$	(370	)

Interest expense	13,965			12,259
Income taxes	42,496			37,729
Net income	$	76,406		$	70,070

	March 31, 2005		December 31, 2004
	(Thousands)
Segment Assets:
Equitable Utilities	$	1,142,974	$	1,201,400
Equitable Supply	1,904,466		1,514,176
NORESCO (d)	207,793		197,201
Total operating segments	3,255,233		2,912,777
Headquarters assets, including cash and short-term investments	264,525		283,769
Total	$	3,519,758	$	3,196,546

	Three Months Ended March 31,
	2005		2004
	(Thousands)
Depreciation, depletion and amortization:
Equitable Utilities	$	6,632	$	7,326
Equitable Supply	16,385		14,043
NORESCO	249		251
Unallocated	173		147
Total	$	23,439	$	21,767

	Three Months Ended March 31,
	2005		2004
	(Thousands)
Expenditures for segment assets:
Equitable Utilities	$	9,787	$	14,600
Equitable Supply (e)	88,631		21,053
NORESCO	217		28
Unallocated expenditures	2,855		189
Total	$	101,490	$	35,870

(a) Intersegment revenues primarily represent sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities.

(b) For the three months ended March 31, 2004, operating income includes the reduction of a regulatory reserve due to higher than anticipated recoveries from Equitable Gas’ Delinquency Reduction Opportunity Program, which gives incentives to eligible delinquent customers to make payments exceeding their current bill amount and to receive additional credits from Equitable Gas to reduce the customer’s balance.

(c) Unallocated other income, net for the three months ended March 31, 2005 relates to pre-tax dividend income of $1.1 million for the 7.0 million Kerr-McGee Corporation shares held by the Company as of March 31, 2005.

(d) The Company’s goodwill balance as of March 31, 2005 and December 31, 2004 totaled $51.8 million and is entirely related to the NORESCO segment.

(e) Capital expenditures for the three months ended March 31, 2005 include $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners L.P.

C. Contract Receivables

The Company, through its NORESCO segment, enters into construction contracts with governmental and institutional counterparties whereby those counterparties finance the construction directly with the Company at prevailing market interest rates. In order to accelerate cash collections and manage working capital requirements, the Company transfers these contract receivables due from customers to financial institutions. The transfer price of the contract receivables is based on the face value of the executed contract with the financial institution. The gain or loss on the sale of contract receivables is the difference between the existing carrying amount of the financial assets involved in the transfer and the transfer price of the contract with the financial institution.

Certain of these transfers do not immediately qualify as “sales” under Statement of Financial Accounting Standards (SFAS) No. 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” (Statement No. 140). For the contract receivables that are transferred and still controlled by the Company, a liability is established to offset the cash received from the transfer. This liability is recognized until control of the contract receivable has been surrendered in accordance with Statement No. 140, as the cash received by the Company can be called by the financial institution at the time it is determined that control will not be surrendered. The Company de-recognizes the receivables and the corresponding liabilities when control has been surrendered in accordance with the criteria provided in Statement No. 140. The Company does not retain any interests in the contract receivables once the sale is complete. As of March 31, 2005, the Company had recorded a current liability of $32.5 million classified as current portion of project financing obligations and a long-term liability of $83.1 million classified as project financing obligations on the Condensed Consolidated Balance Sheets. The current portion of project financing obligations represents transfers for which control is expected to be surrendered, and cash could be called, within one year. The related assets are classified as unbilled revenues as construction progresses and as other assets upon completion of construction.

For the three months ended March 31, 2005, there were no contract receivables that met the criteria for sales treatment, and as a result, there were no receivables de-recognized in the first quarter of 2005.

D. Derivative Instruments

Accounting Policy

Derivatives are held as part of a formally documented risk management program. The Company’s risk management activities are subject to the management, direction and control of the Company’s Corporate Risk Committee (CRC). The CRC reports to the Audit Committee of the Board of Directors and is comprised of the chief executive officer, the executive vice-president of finance and administration, the chief financial officer and other officers and employees.

The Company’s risk management program includes the consideration and, when appropriate, the use of (i) exchange-traded natural gas futures contracts and options and over-the-counter (OTC) natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes, (ii) interest rate swap agreements to hedge exposures to fluctuations in interest rates, and (iii) variable share forward contracts to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee Corporation (Kerr-McGee) shares through the use of collars by effectively purchasing a put option from and selling a call option to a counterparty. At contract inception, the Company designates its derivative instruments as hedging or trading activities.

All derivative instruments are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement No. 133), as amended by SFAS No. 137, “Accounting for Derivative Instruments and Hedging Activities - - Deferral of the Effective Date of Financial Accounting Standards Board Statement No. 133” (Statement No. 137), SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement No. 138) and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (Statement No. 149). As a result, the Company recognizes all derivative instruments as either assets or liabilities and measures the effectiveness of the hedges, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at fair value. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, hedge ineffectiveness is recorded in the income statement. The measurement of fair value is based upon actively quoted market prices when available. In the absence of actively quoted market prices, the Company seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based upon valuation methodologies determined to be appropriate by the Company’s CRC. The Company assesses the effectiveness of hedges both at the inception of the hedge and on an on-going basis. The Company reports all gains and losses on its derivative commodity instruments net on its Statements of Consolidated Income in accordance with Emerging Issues Task Force (EITF) No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10 and 00-17” (EITF No. 02-3).

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. Exchange-traded instruments are generally settled with offsetting positions but may be settled by delivery or receipt of commodities. OTC arrangements require settlement in cash. The fair value of these derivative commodity instruments was a $54.8 million asset and a $694.0 million liability as of March 31, 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 commodity instruments, at fair value, changed from a net liability of $323.6 million at December 31, 2004 to a net liability of $639.2 million at March 31, 2005, primarily the 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 total 428.0 Bcf and 432.6 Bcf as of March 31, 2005 and December 31, 2004, respectively, and primarily relate to natural gas swaps. The open swaps at March 31, 2005 have maturities extending through December 2011.

estimates that approximately $123.4 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of March 31, 2005 will be recognized in earnings during the next twelve months. This recognition occurs through a reduction in the Company’s net operating revenues, which will result in a reduction in the realized sales price.

For each of the three-month periods ended March 31, 2005 and 2004, ineffectiveness associated with the Company’s derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $0.1 million. 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 March 31, 2005 totaled 4.2 Bcf and 55.7 Bcf, respectively.

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 three months ended March 31, 2005 (in thousands).

Fair value of contracts outstanding as of December 31, 2004	$	481
Contracts realized or otherwise settled	(571		)
Other changes in fair value	47
Fair value of contracts outstanding as of March 31, 2005	$	(43	)

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 March 31, 2005.

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

Source of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years		Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
	(Thousands)
Prices actively quoted (NYMEX) (1)	$	(18	)	$	10	$	—	$	—	$	(8	)
Prices provided by other external sources (2)	(73		)	38		—		—		(35		)
Net derivative (liabilities) assets	$	(91	)	$	48	$	—	$	—	$	(43	)

(1) Contracts include futures and fixed price swaps

(2) Contracts include basis swaps

The overall portfolio of the Company’s derivative commodity instruments held for risk management purposes approximates the notional quantity of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity instruments portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the derivative commodity instruments continue to function effectively as hedges of the underlying risk, and as applicable, anticipated transactions occur as expected.

As part of the purchase of the 99% limited partnership interest in Eastern Seven Partners, L.P. (ESP), as more thoroughly discussed in Note L, 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 Statement No. 133. The fair value of these derivative instruments at March 31, 2005 was a $68.3 million liability and a $20.8 million asset. These amounts are included in the Condensed Consolidated Balance Sheet as derivative instruments, at fair value. The settlements of these derivatives will not have any income statement impact but will reduce the net liability that was recorded upon the purchase of ESP.

Variable Share Forward Contracts

In July of 2004, the Company entered into three 7.5 year secured variable share forward transactions. Each transaction has a different counterparty, covers 2.0 million shares of Kerr-McGee common stock, contains a collar and permits receipt of an amount up to the net present value of the floor price prior to maturity. Upon maturity of each transaction, the Company is obligated to deliver to the applicable counterparty, at the Company’s option, no more than 2.0 million Kerr-McGee shares or cash in an equivalent value. The transactions hedge the Company’s cash flow exposure of the forecasted disposal of the Kerr-McGee shares by effectively purchasing a put option from and selling a call option to the counterparty (collectively, a collar). The collars had no net cost for the Company. The collars effectively limit the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares between a blended average floor price per share of $53.06 and a blended average cap price per share of $100.79. Each transaction is secured by the underlying Kerr-McGee shares. A variable portion of the dividends received on the underlying Kerr-McGee shares must be paid to each counterparty depending upon the hedged position of such counterparty. Based on the current hedged position of the counterparties, the Company expects to pay to each counterparty approximately 75% of the next Kerr-McGee dividend. In the first quarter of 2005, the Company recorded pre-tax dividend income, net of payments to the counterparties, of $1.1 million, which is recorded in other income, net on the Statement of Consolidated Income for the three months ended March 31, 2005. At March 31, 2005, the Company owned approximately 7.0 million Kerr-McGee shares, of which approximately 1.0 million shares remained unhedged. The approximately 1.0 million unhedged shares were subsequently sold by the Company in April 2005, as more thoroughly discussed in Note M.

The variable share forward transactions meet the requirements of Statement No. 133 Implementation Issue G20, “Assessing and Measuring the Effectiveness of an Option Used in a Cash Flow Hedge” and have been designated cash flow hedges. Under this guidance, complete hedging effectiveness is assumed and the entire change in fair value of the collars will be recorded in other comprehensive income. Due to the significant Kerr-McGee share price increase in the first quarter of 2005, the fair value of the call components of the collars became much higher than the fair value of the put components of the collars. As a result, the Company recorded the net extrinsic value of the collars as a derivative liability. As of March 31, 2005, a liability of $102.8 million was recorded in derivative instruments, at fair value, and the amount recorded in accumulated other comprehensive loss, net of tax, related to the change in fair value of the collars for the quarter ended March 31, 2005 was $66.8 million. The Kerr-McGee share price was between the floor price and the cap price for each of these transactions so no intrinsic value was recorded.

E. Investments

As of March 31, 2005, the investments classified by the Company as available-for-sale include a $550.5 million investment in Kerr-McGee and $23.9 million of debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures.

In the second quarter of 2004, Westport Resources Corporation (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. As a result of the merger, the Company recognized a gain of $217.2 million on the exchange of the Westport shares for the Kerr-McGee shares in the second quarter of 2004. The Company recorded its book basis in the Kerr-McGee shares at $49.82 per share, which included a discount to the market price for trading restrictions on the securities. The discount was recorded as a reduction to the increase in the book basis of the Kerr-McGee shares and was accreted into other comprehensive income during the third quarter of 2004.

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

Following the Kerr-McGee/Westport merger, the Company entered into three variable share forward transactions in the third quarter of 2004 related to an aggregate of 6.0 million Kerr-McGee shares. See Note D for discussion of these transactions.

On June 30, 2004, the Company irrevocably committed to contribute 357,000 Kerr-McGee shares to Equitable Resources Foundation, Inc., which was established by the Company in 2003 to support development programs in the communities where the Company conducts business. 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. The shares were transferred to this foundation under this commitment during the third quarter of 2004. Charitable contributions of significantly appreciated qualified shares of stock, such as the Kerr-McGee shares, constitute a tax efficient use of the shares.

Any unrealized gains or losses with respect to investments classified as available-for-sale are recognized within the Condensed Consolidated Balance Sheets as a component of equity, accumulated other comprehensive loss. As of December 31, 2004, the Company performed an impairment analysis in accordance with SFAS No. 115 “Accounting for Certain Investments in Debt and Equity Securities” (Statement No. 115) and concluded that all declines below cost were temporary. Factors and considerations the Company used to support this conclusion have not changed in the first quarter of 2005.

F. Comprehensive (Loss) Income

Total comprehensive (loss) income, net of tax, was as follows:

	Three Months Ended March 31,
	2005			2004
	(Thousands)
Net income	$	76,406		$	70,070
Other comprehensive loss:
Net change in cash flow hedges:
Natural gas (Note D)	(193,172		)	(50,825		)
Interest rate	29			(59		)
Unrealized gain on investments, available-for-sale (Note E):
Westport	—			23,454
Kerr-McGee	93,829			—
Other	(100		)	272
Unrealized loss on collars on hedged Kerr-McGee shares (Note D)	(66,792		)	—
Total comprehensive (loss) income	$	(89,800	)	$	42,912

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

	March 31, 2005			December 31, 2004
	(Thousands)
Net unrealized loss from hedging transactions	$	(391,328	)	$	(198,185	)
Unrealized gain on available-for-sale securities	131,258			37,529
Minimum pension liability adjustment	(19,691		)	(19,691		)
Unrealized loss on collars on hedged Kerr-McGee shares	(66,792		)	—
Accumulated other comprehensive loss	$	(346,553	)	$	(180,347	)

G. Stock-Based Compensation

Restricted stock grants in the aggregate amount of 24,250 shares were awarded to various employees during the first quarter of 2005. The related expense recognized during the three-month period ended March 31, 2005 was $0.7 million and is classified as selling, general and administrative expense.

No new stock options were awarded during the three months ended March 31, 2005. The Company applies Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for its stock-based compensation and has consequently not recognized any compensation cost for its stock option awards.

In the first quarter of 2005, the Company paid out the approximately 276,000 stock units that vested December 31, 2004 under the Company’s 2002 Executive Performance Incentive Program. As of March 31, 2005, the Company has two Executive Performance Incentive Programs (the “Plans”) in place, including the 2005 Plan described below, that have been established to provide additional incentive benefits to retain senior executive employees of the Company and to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. The

vesting of these units occurs contingent upon the level of total shareholder return relative to a fixed group of peer companies. The Company anticipates, based on current estimates, that a certain level of performance will be met.

The 2005 Plan was adopted on February 23, 2005 by the Compensation Committee of the Board of Directors. Under the program, a maximum of 600,000 stock units may be granted among a maximum of forty participants. The vesting of these stock units will occur on December 31, 2008, contingent upon a combination of the level of total shareholder return relative to 29 peer companies and the Company’s average absolute return on total capital during the four year performance period. As a result, zero to 1,500,000 units (250% of the units available for grant) may be distributed in cash or stock.

The Company continually monitors its stock price and relative return in order to assess the impact on the ultimate payouts under the Plans. The Company’s share price assumption used to determine the accrual is $62.00 per share at the end of 2005 and $73.00 per share at the end of 2008. The related long-term incentive plan expenses are included in selling, general and administrative expenses in the Statements of Consolidated Income. Additionally, a portion of the long-term incentive plan 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” (Statement No. 123), to its employee stock-based awards.

	Three Months Ended March 31,
	2005			2004
	(Thousands)
Net income, as reported	$	76,406		$	70,070
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	2,516			2,525
Deduct: Total stock-based employee compensation expense determined by the fair value method for all awards, net of related tax effects	(3,220		)	(3,689		)
Pro forma net income	$	75,702		$	68,906
Earnings per share:
Basic, as reported	$	1.26		$	1.13
Basic, pro forma	$	1.25		$	1.11

Diluted, as reported	$	1.23		$	1.10
Diluted, pro forma	$	1.22		$	1.08

H. 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 which 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. The Company currently estimates the annual effective income tax rate to be 35.7%.

I. Pension and Other Postretirement Benefit Plans

The Company has defined benefit pension and other postretirement benefit plans covering represented members that generally provide benefits of stated amounts for each year of service. Prior to December 31, 2003, the Company provided benefits to certain salaried employees through defined benefit plans that used a benefit formula based upon employee compensation. Effective December 31, 2003, the pension benefits provided through this plan were frozen and the covered salaried employees were converted to a defined contribution plan. Effective December 31, 2004, the Company settled the pension obligation of those non-represented employees whose benefits were frozen as of December 31, 2003. As a result of this settlement, which was accounted for under SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement expense of $13.4 million for the year ended December 31, 2004. The settlement expense that was recognized for these non-represented employees was primarily the result of accelerated recognition of approximately $11.0 million in previously deferred

unrecognized losses. The Company expects to incur additional settlement expense in the second quarter of 2005 when the settlement is fully funded. As part of this settlement, the affected employees were provided the option to either roll over the lump-sum value of their cash balance account to the Company’s defined contribution plan, or to receive an insured monthly annuity benefit at the time they retire. All other non-represented employees are participants in a defined contribution plan.

The Company’s costs related to its defined benefit pension and other postretirement benefit plans for the three months ended March 31, 2005 and 2004 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,
	2005			2004			2005			2004
	(Thousands)
Components of net periodic benefit cost
Service cost	$	225		$	397		$	135		$	121
Interest cost	1,698			1,742			792			819
Expected return on plan assets	(2,106		)	(2,457		)	—			—
Amortization of prior service cost	191			235			(11		)	(11		)
Recognized net actuarial loss	280			186			552			500
Settlement loss	456			476			—			—
Net periodic benefit cost	$	744		$	579		$	1,468		$	1,429

The Company did not make a contribution to its defined benefit plan in 2004. The Company expects to make a cash contribution of approximately $13 million to its pension plan in the second quarter of 2005 to fully fund the cash balance participants portion of the pension plan which was settled effective December 31, 2004.

In May 2004, the FASB issued Staff Position 106-2, “Accounting and Disclosure Requirements Related to Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) which provides guidance on the accounting for the effects of the MPDIM Act. FSP FAS 106-2 also requires that certain disclosures be made regarding the effect of the federal subsidy provided by the MPDIM Act. The regulations identifying how actuarial equivalency is to be determined under the MPDIM Act were issued in January 2005. Based on an analysis of these regulations, the Company determined that its retiree medical programs for certain of its locations were actuarially equivalent to Medicare Part D and thus qualified for the federal subsidy.

As a result of qualifying for the federal subsidy, the Company estimates that its accumulated postretirement benefit obligation will be reduced by approximately $4.6 million. The reduction in annual net periodic postretirement benefit cost is estimated at approximately $0.5 million, of which $0.1 million was recorded in the first quarter of 2005. The $0.5 million annual reduction consists of approximately $0.3 million reduction in interest cost and $0.2 million reduction in amortization of actual experience loss.

J. Recently Issued Accounting Standards

Stock Compensation

On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (Statement No. 123R). This guidance replaced previously existing requirements under SFAS No. 123, “Accounting for Stock-Based Compensation” (Statement No. 123), and APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Statement No. 123R eliminates the ability for an entity to account for share-based compensation transactions using the intrinsic value method permitted under APB No. 25. Under Statement No. 123R, 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.

Statement No. 123R permits public companies to adopt its requirements using one of two methods:

1. A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of Statement No. 123R for all share-based payments granted after the effective date and (b) based on the requirements of Statement No. 123 for all awards granted to employees prior to the effective date of Statement No. 123R that remain unvested on the effective date.

2. A “modified retrospective” method which includes the requirements of the modified prospective method described above but also permits entities to restate its financial statements, based on the amounts previously recognized under Statement No. 123 for purposes of pro forma disclosures, either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

The Company is currently evaluating each of these alternatives in order to determine the most appropriate method of adoption of Statement No. 123R when the guidance becomes effective.

On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued Staff Accounting Bulletin No. 107, “Share-Based Payment” (SAB No. 107), which expressed the SEC staff’s views on Statement No. 123R, but did not modify any of Statement No. 123R’s provisions. The Company is evaluating the views expressed by the SEC in SAB No. 107 in conjunction with its assessment of Statement No. 123R’s impact to the Company.

As originally issued, Statement No. 123R was to become effective for public entities in the first interim or annual period beginning after June 15, 2005 (for the Company, the third quarter of 2005). However, on April 14, 2005, the SEC announced that it would not require registrants to adopt Statement No. 123R until at least the beginning of the first fiscal year beginning after June 15, 2005. Therefore, the Company will be required to adopt Statement No. 123R beginning with its 2006 fiscal year.

While the impact of adoption of Statement No. 123R cannot be determined at this time, the Company will continue to evaluate the impact of this guidance on the Company’s financial position and results of operations. In accordance with Statement 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 Statement No. 123R in prior periods, the impact of that standard on periods presented in these condensed consolidated financial statements would have approximated the impact of Statement No. 123 as described in the disclosure of pro forma net income and earnings per share in Note G.

Asset Retirement Obligations

On March 30, 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 Statement No. 143 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. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, 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. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability, rather than the timing of recognition of the liability, when sufficient information exists. 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.

K. International Investments

Certain NORESCO projects are conducted through nonconsolidated entities that consist of private power generation facilities located in select international locations. 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 generation business. Changes in pricing in the electricity power market in Panama during the second quarter of 2004 negatively impacted the outlook for operations of IGC/ERI Pan Am Thermal Generating Limited (Pan Am), a Panamanian electric generation project. As a result, the Company performed an impairment analysis of its equity interest in this project. This involved preparing a probability-weighted cash flow analysis using the undiscounted future cash flows and comparing this amount to the book value of the equity investment. The probability-weighted cash flows resulted in a lower fair value than the carrying value, and an impairment was deemed necessary. An impairment of $22.1 million was recorded in the second quarter of 2004 and represented the full value of NORESCO’s equity investment in the project.

During the second quarter of 2004, the Company also reviewed its investment in Compania Hidroelectrica Dona Julia, S.D.R. Ltd. (Dona Julia), a Costa Rican electric generation project, as the investment was being actively marketed for sale. Based on the analysis performed on the sales value of the investment, the Company recorded an impairment charge of $2.8 million to write down the investment to its fair value less costs to sell. Following the impairment, the investment in Dona Julia was considered held for sale. The investment was included in equity in nonconsolidated investments on the Condensed Consolidated Balance Sheet at December 31, 2004. In January 2005, the Company sold its interest in Dona Julia to a third party purchaser and recorded a slight gain on the sale.

Additional impairment charges of $14.7 million were also recorded in 2004 for total impairment charges of $39.6 million. The additional charges related to various costs and obligations related to exiting NORESCO’s investments in international power plant projects. Included in these charges was a liability for loan guarantees in the amount of $5.8 million in support of Pan Am. These various costs and obligations were reviewed during the first quarter of 2005 and were reduced by $0.5 million. Also during the first quarter of 2005, NORESCO received a partnership distribution in the amount of $0.5 million related to Petroelectrica de Panama LDC, an independent power plant in Panama. This distribution was the result of the dismantling of the plant and subsequent sale of assets. The Company expects final closure to be completed sometime during the remainder of 2005.

After an extended period of troubled operations, ERI JAM, LLC (ERI JAM), a subsidiary that holds the Company’s interest in EAL/ERI Cogeneration Partners LP, an international infrastructure project located in Jamaica, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. In the third quarter of 2003, ERI JAM transferred control of the international infrastructure project under the partnership agreement to the other non-affiliate general partner. In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM as Debtor-in-Possession in the Chapter 11 case. EAL, an affiliate of JBG, is a limited partner in EAL/ERI Cogeneration Partners LP. In October 2003, JBG and EAL also filed a multi-count complaint seeking damages against Equitable and certain of its affiliates in U.S. District Court (Western District of Pennsylvania) alleging breach of contract, tortious interference with contractual relations, negligence and a variety of related claims with respect to the operation and management of EAL/ERI Cogeneration Partners LP. On March 2, 2005, the Company entered into a settlement agreement with EAL and JBG pursuant to which, among other things, (a) the parties mutually released one another, (b) ERI JAM and its non-operating holding company will be transferred to an affiliate of JBG, and (c) EAL and JBG are responsible for settling ERI JAM’s bankruptcy case and have delivered to the Company broad releases from the more significant trade creditors and the project lender.

L. Other Events

In January 2005, the Company purchased the 99% limited partnership interest in Eastern Seven Partners L.P. for cash of $57.5 million and assumed liabilities of $47.3 million. The purchase added approximately 30 Bcfe of reserves.

In the third quarter of 2003, the Company entered into a long-term lease with Continental Real Estate Companies (Continental) to occupy office space in a building at the North Shore in Pittsburgh. This action will help consolidate the Company’s administrative operations. Continental is constructing and will own the office building, with completion of the building expected during the second quarter of 2005. Relocation operations began late in the first quarter of 2005 and will continue through the second quarter of 2005. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company recognized a loss on disposal of assets of approximately $0.5 million, recorded in selling, general and administrative expense, during the first quarter of 2005 related to its relocation activities. The Company continues to evaluate its lease requirements and depending on a final determination of these requirements, expects to incur additional costs in the second quarter of 2005 between approximately $6 million and $8 million related to the relocation of its administrative operations for its Utilities and Headquarters personnel.

M. Subsequent Events

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

In April 2005, the Company entered into a definitive sale agreement for the sale of certain Ohio and Pennsylvania oil and gas properties. This transaction is in line with management’s strategic objective to focus on the Company’s core natural gas producing properties. The sale, which is subject to certain conditions, is expected to close in the second quarter of 2005. In accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” this sale of only a portion of the gas properties may be treated as a normal retirement with no gain or loss recognized if doing so does not significantly affect the unit of production amortization rate. Given the size of the transaction, the Company believes that no gain or loss will be recorded upon the closing of this transaction.

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 specifically include the expectations of future plans, objectives, cost savings, growth and anticipated financial and operational performance of the Company and its subsidiaries, including statements regarding the Company’s hedging strategy, including the impact on earnings of a change in NYMEX and the amount of unrealized losses on derivative commodity instruments expected to be recognized in earnings; the Company’s identification of growth opportunities and its ability to execute its operational strategies in competitive environments; the belief that environmental expenditures will not be significantly different in nature or amount in the future and will not have a material effect on the Company’s financial position; the adequacy of legal reserves and availability of insurance and therefore the belief that the ultimate outcome of any matter currently pending will not materially affect the Company’s financial position; the amount of future dividends; the belief that the Company has sources of liquidity sufficient to meet its needs; the possible impact of inflation and the effect of changing prices; the Company’s approach to compensation, including the expense and funding of the Executive Performance Incentive Programs which are based in part upon an expected price per share; the expected timing and amount of pension expense and pension funding obligations; the possibility of a reduction in certain post-retirement benefit costs resulting from the Medicare Prescription, Drug, Improvement and Modernization Act of 2003; the timing and amount of expenses to be incurred as a consequence of relocation to new office space and of the increased efficiencies resulting from the relocation; the estimated annual effective income tax rate for 2005; the ultimate outcome of pending and anticipated rate cases, regulatory reviews and audits and other regulatory action, including the amounts that the Company expects to recover or incur as a consequence of such events; the change in strategy and related operational matters at the Supply segment, including the anticipated number of wells to be drilled, the number of drilling locations on unproved properties, the effectiveness of infrastructure improvement projects, anticipated volumes, the Company’s ability to raise gathering rates and the impact of the expected sale of certain non-core producing properties; the expected amount, timing, and source of payment for, plugging and abandonment obligations; the ability to divest international projects; the pace at which the performance contracting business can be resumed; the anticipated future disposal of the Company’s investment in Kerr-McGee Corporation and the financial impact of the variable share forward transactions, including the amount of any dividend pass-through; the other estimates incorporated into the Company’s critical accounting estimates and the expected impact of new accounting pronouncements.

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: weather conditions, commodity prices for natural gas and crude oil and associated hedging activities, availability and cost of financing, changes in interest rates, the needs of the Company with respect to liquidity, implementation and execution of operational enhancements and cost restructuring initiatives, curtailments or disruptions in production, the substance, timing and availability of regulatory and legislative action, timing and extent of the Company’s success in acquiring utility companies and natural gas and crude oil properties, the ability of the Company to discover, develop and produce reserves, the ability of the Company to acquire and apply technology to its operations, the impact of competitive factors on profit margins in various markets in which the Company competes, the ability of the Company to negotiate satisfactory collective bargaining agreements with its union employees, 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.

OVERVIEW

In this report, Equitable (which includes Equitable Resources, Inc. and unless the context otherwise requires, all of its subsidiaries) is at times referred to as “the Company.”

Equitable Resources’ consolidated net income for the quarter ended March 31, 2005 totaled $76.4 million, or $1.23 per diluted share, compared to $70.1 million, or $1.10 per diluted share, reported for the same period a year ago. This 9% increase in net income from 2004 to 2005 was due to several factors, including increased margins from operations in Equitable Utilities’ Energy Marketing group, as increased price volatility in the natural gas market presented more valuable storage asset optimization opportunities. Net income also increased due to an increase in sales volumes from production related to the acquisition of the 99% limited partnership interest in Eastern Seven Partners L.P. (ESP) and an increase in average natural gas prices. These factors were partially offset by additional expenses related to the operation of ESP as well as increased operating costs resulting from higher natural gas prices during the first quarter of 2005.

The effective tax rate for the three months ended March 31, 2005 and 2004 was 35.7% and 35.0%, respectively.

Business segment operating results are presented in the segment discussions and financial tables on the following pages. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, earnings from nonconsolidated investments, minority interest and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.

The Company has reconciled the segments’ operating income, earnings from nonconsolidated investments, minority interest, and other income, net to the Company’s consolidated operating income, earnings from nonconsolidated investments, minority interest and other income, net totals in Note B to the condensed consolidated financial statements. Additionally, these subtotals are reconciled to the Company’s consolidated net income in Note B. The Company has also reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. Equitable’s management believes that presentation of this information provides useful information to management and investors regarding the financial condition, operations and trends of each of Equitable’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest and income taxes. In addition, management uses these measures for budget planning purposes.

RESULTS OF OPERATIONS

EQUITABLE UTILITIES

Equitable Utilities’ operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline gathering, transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas, and limited trading activities.

	Three Months Ended March 31,
	2005			2004

OPERATIONAL DATA

Total operating expenses as a% of net operating revenues	37.16		%	40.32		%
Capital expenditures (thousands)	$	9,787		$	14,600

FINANCIAL DATA (Thousands)

Utility revenues (regulated)	$	216,582		$	195,689
Marketing revenues	82,486			85,685
Total operating revenues	299,068			281,374
Utility purchased gas costs (regulated)	133,324			112,368
Marketing purchased gas costs	66,474			75,240
Net operating revenues	99,270			93,766
Operating expenses:
Operating and maintenance	13,946			12,117
Selling, general and administrative	16,315			18,363
Depreciation, depletion and amortization (DD&A)	6,632			7,326
Total operating expenses	36,893			37,806
Operating income	$	62,377		$	55,960

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

Net operating revenues for the three months ended March 31, 2005 were $99.3 million compared to $93.8 million for the same quarter in 2004. The 6% increase in net operating revenues is mainly due to a $5.6 million increase in margins from operations in the Energy Marketing group related to more valuable storage asset optimization opportunities as a result of increased volatility in the natural gas market. Additionally, Equitable Utilities’ Distribution operations experienced a $1.1 million increase in margins related to commercial and industrial customers and increased gathering revenues of $0.5 million. Equitable Utilities’ Pipeline operations also increased gathering revenues by $0.4 million. These increases were offset by a reduction in net operating revenues of $2.1 million due to 3% warmer weather in the first quarter of 2005 versus 2004.

Total operating expenses for the quarter decreased by $0.9 million from $37.8 million in 2004 to $36.9 million in 2005. Decreases in provisions for insurance losses of $1.0 million, bad debt expense of $0.9 million and DD&A of $0.7 million were offset by increases in fringe benefits of $0.9 million, outside contractor costs of $0.5 million, and increases in maintenance and staffing costs.

Capital expenditures decreased $4.8 million to $9.8 million for the first quarter of 2005 from $14.6 million in 2004. The decrease is due to lower pipeline replacement spending in both distribution and transmission operations and lower expenditures for storage enhancements.

Distribution Operations

Rates and Regulatory Matters

Equitable Utilities’ distribution operations are carried out by Equitable Gas, a division of the Company. The service territory for Equitable Gas includes southwestern Pennsylvania, municipalities in northern West Virginia and field line sales (also referred to as “farm tap” service as the customer is served directly from a well or gathering pipeline) in eastern Kentucky and in West Virginia. The distribution operations provide natural gas services to approximately 277,000 customers, comprising 258,000 residential customers and 19,000 commercial and industrial customers. Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky. Equitable Gas also operates a small gathering system in Pennsylvania.

Pennsylvania law requires that local distribution companies develop and implement programs to assist low-income customers with paying their gas bills. Ostensibly the costs of these programs are recovered through rates charged to other residential customers. Equitable Gas has several such programs. In August 2003, Equitable Gas submitted revisions to those programs for Pennsylvania Public Utility Commission (PA PUC) approval. The revisions were designed to make participation in the low-income programs more accessible and thereby improving participants’ ability to pay their bills. In October 2003, the PA PUC approved Equitable Gas’ revised programs and instructed the various stakeholders to ascertain whether additional funding was necessary to implement the revised programs. Ultimately, consensus was reached to allow the Company to collect an additional $0.30 per Mcf to fund the programs. Based on recent billing volumes, this would equate to approximately $7.0 million in additional annual revenue. By PA PUC Order of April 1, 2004, the funding mechanism was approved for all residential consumption beginning April 2, 2004, and will remain in place until Equitable Gas seeks authority to change the funding mechanism. Through the remainder of 2005 and thereafter, it is expected that this mechanism will be a key component in the Company’s efforts to reduce bad debt expense.

On November 30, 2004, Pennsylvania Governor Edward G. Rendell signed into law the Responsible Utility Customer Protection Act (Act 201). Act 201, which became effective on December 14, 2004, established new procedures for utilities regarding collection activities with respect to deposits, payment plans and terminations for residential customers and is intended to help utility companies collect amounts due from customers. As a result of Act 201, the Company is permitted to send winter termination notices to customers whose household income exceeds 250% of the federal poverty level and to complete customer terminations without approval from the PA PUC. During the first quarter of 2005, the Company sent 11,000 termination notices, resulting in collections of approximately $4.0 million. Other regulatory changes mandated by Act 201 will become effective later in 2005 and beyond and will be implemented by the Company as appropriate.

Equitable Gas 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. In 2001, Equitable Gas received approval from the PA PUC to implement a performance-based purchased gas cost credit incentive that provides to customers a purchased gas cost credit which is fixed in amount, while enabling Equitable Gas to retain all revenues in excess of the credit through more effective management of upstream interstate pipeline capacity. This performance-based incentive provides an opportunity for Equitable Gas to make short-term releases of unutilized pipeline capacity for a fee and 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. These revenues are aggregated for reporting purposes within Equitable Utilities’ non-jurisdictional Energy Marketing operations. Equitable Gas’ performance-based purchased gas cost credit incentive is available through September 2005. There is also a performance-based incentive that allows Equitable Gas to retain 25% of any revenue generated from services designed to increase the recovery of capacity costs from transportation customers. This initiative also runs through September 2005. In addition, a third PA PUC-approved performance-based initiative related to balancing services is available through September 2005. Equitable will seek to extend these performance-based initiatives or seek new performance-based initiatives.

Equitable Gas submits quarterly purchased gas cost filings to the PA PUC that are subject to quarterly reviews and an annual audit for prudency by the PA PUC Staff. The PA PUC’s Bureau of Audits also reviews the accuracy of the Company’s accounting of purchased gas costs and the Company’s reconciliation of gas costs charged to customers. The PA PUC Staff has provided its final prudency review through 2003 in which no material issues were

noted. The PA PUC Bureau of Audits commenced a purchased gas cost audit for the 2002-2003 period in the third quarter of 2004. On February 24, 2005, the Company received a copy of the Bureau of Audits draft audit report for the 2002-2003 period. The draft report contained no significant findings. A final audit report will be submitted to the PA PUC for approval during the second quarter of 2005.

Other

Equitable Gas’ collective bargaining agreement with United Steelworkers of America, Local Union 12050 representing 189 employees expired on April 15, 2003. The union has continued to work under the terms and conditions of the expired contract while negotiating a new contract.

	Three Months Ended March 31,
	2005		2004
OPERATIONAL DATA

Heating Degree days (30 year normal YTD average – 2,930) (a)	2,834		2,925
O&M per customer (b)	$	83.94	$	85.10
Volumes (MMcf):
Residential sales and transportation	12,373		13,080
Commercial and industrial	10,783		11,666
Total throughput	23,156		24,746

FINANCIAL DATA (Thousands)

Net operating revenues:
Residential net operating revenues	$	43,161	$	44,966
Commercial and industrial net operating revenues	21,242		20,773
Other net operating revenues	2,389		1,564
Total net operating revenues	66,792		67,303
Operating expenses (total operating expenses excluding depreciation, depletion and amortization)	23,901		24,065
Depreciation, depletion and amortization (DD&A)	4,564		5,319
Operating income	$	38,327	$	37,919

(a) A heating degree day is computed by taking the average temperature on a given day in the operating region and subtracting it from 65 degrees Fahrenheit. Each degree by which the average daily temperature falls below 65 degrees represents one heating degree day.

(b) O&M is defined for this calculation as the sum of operating expenses (total operating expenses excluding depreciation, depletion and amortization) less other taxes. Other taxes for the three months ended March 31, 2005 and 2004 totaled $0.7 million and $0.6 million, respectively. As of March 31, 2005 and 2004, Equitable Gas had approximately 277,000 customers and 275,500 customers, respectively.

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

Net operating revenues decreased $0.5 million in the first quarter of 2005 compared to the first quarter of 2004. Weather, which was 3% warmer in 2005, resulted in a decrease of $2.1 million. The weather impact was offset by an increase in commercial and industrial margins of $1.1 million combined with an increase of $0.5 million related to further utilization of gathering assets transferred from the Pipeline operations to the Distribution operations during the first quarter of 2004.

Operating expenses excluding DD&A decreased $0.2 million from 2004 to 2005. A decrease in operating expenses of $1.9 million was due to a decrease in the provision for insurance losses of $1.0 combined with a $0.9 million decrease in bad debt expense. The decrease in bad debt expense is primarily attributable to the funding mechanism approved by the PA PUC discussed under “Rates and Regulatory Matters” above. These reductions were offset by an increase of $0.8 million in employee fringe benefits and an $0.8 million increase in outside contracting and staffing costs. DD&A decreased $0.7 million primarily due to increases in the estimated useful lives for Equitable Gas’ main lines and services lines resulting from a PA PUC mandated asset service life study finalized in October 2004.

Pipeline Operations

Interstate Pipeline

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 by August 1, 2003. In April 2003, Equitrans filed with the FERC for deferral of its August 1, 2003 filing requirement until April 2005. On July 1, 2003, Equitrans received an order from the FERC denying the request for deferral. However, the FERC ultimately agreed that Equitrans could postpone its rate case filing obligation until December 1, 2003.

Equitrans timely filed its rate case application on December 1, 2003. On December 31, 2003, in accordance with the Natural Gas Act, the FERC issued an order accepting in part and rejecting in part Equitrans’ general rate application. Certain of Equitrans’ proposed tariff sheets were accepted subject to a 5-month suspension period, but Equitrans’ requests for revenue relief were denied. The increase was rejected in large part because Equitrans did not provide cost and revenue data for one of its rate districts for which rate relief was not being requested. Equitrans filed a rehearing request on January 30, 2004, seeking reconsideration of the FERC’s December 31, 2003 order, including the FERC’s order requiring a certificate filing to replenish certain storage base gas volumes.

Equitrans re-filed its rate case application on March 1, 2004, complete with cost and revenue data for the previously omitted operations. Consistent with the Company’s original December 1, 2003 filing, Equitrans’ rate case application addressed 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. On March 31, 2004, in accordance with the Natural Gas Act, the FERC issued an order accepting Equitrans’ rate application, suspending its tariff sheets until September 1, 2004, and establishing certain procedural parameters for the case. Equitrans began charging the proposed rates for its core services, subject to refund, on September 1, 2004. The proposed rates for Equitrans’ non-core services were moved into effect, subject to refund, on December 1, 2004, pursuant to Commission orders issued on November 23, 2004 and December 30, 2004. Accordingly, Equitrans has set up a reserve believed by management to be prudent, which will be adjusted upon ultimate resolution of the rate case. The Commission’s November 23, 2004 order also denied Equitrans’ January 30, 2004 rehearing request. On January 21, 2005, the Company requested judicial review of this order but intends to address the replenishment of the storage base gas volumes in conjunction with the resolution of its pending 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 March 4, 2005, Equitrans requested consolidation of its January 28, 2005 rate application with the December 1, 2003 and March 1, 2004 rate case filings discussed above. On March 9, 2005, the FERC approved consolidation of the proceedings and set hearings for the fourth quarter of 2005. Equitrans will continue to explore and evaluate settlement options throughout the pendency of the proceeding.

Other

Equitrans’ collective bargaining agreement with Paper, Allied-Industrial, Chemical and Energy Workers Industrial Union Local 5-0843 representing 26 employees expired April 19, 2004. The union has continued to work under the terms and conditions of the expired contract while negotiating a new contract.

	Three Months Ended March 31,
	2005		2004
OPERATIONAL DATA

Transportation throughput (Bbtu)	16,461		18,961

FINANCIAL DATA (Thousands)

Net operating revenues	$	16,466	$	16,018
Operating expenses (total operating expenses excluding depreciation, depletion and amortization)	5,998		5,398
Depreciation, depletion and amortization (DD&A)	2,049		1,965
Operating income	$	8,419	$	8,655

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

Total transportation throughput decreased 2.5 million MMbtu, or 13% over the prior year quarter primarily due to a decrease in Equitable Gas volumes. Because the margin from these firm transportation contracts is generally derived from fixed monthly fees, regardless of the volumes transported, the decreased throughput did not negatively impact net operating revenues.

Net operating revenues increased $0.5 million, or 3% over the first quarter of 2004. Gathering revenues increased $0.4 million due to an increase in volumes over the prior year quarter. Storage revenues increased $0.3 million due to an increase in interruptible storage services as a result of lower firm customer delivery demands compared to the prior year quarter. These increases were partially offset by a slight decrease in both firm and interruptible transmission delivery revenues.

Operating expenses excluding DD&A increased from $5.4 million in 2004 to $6.0 million in 2005 as a result of increased maintenance expenses of $0.5 million primarily in the gathering operations and increased fringe expenses of $0.1 million related to higher pension and health care costs.

Energy Marketing

Equitable Utilities’ energy marketing includes the non-jurisdictional marketing of natural gas at Equitable Gas, marketing and risk management activities at Equitable Energy, and the sale of energy-related products and services by Equitable Homeworks. Equitable Energy provides commodity procurement and delivery, risk management and customer services to energy consumers including large industrial, utility, commercial and institutional end-users. Equitable Energy’s primary focus is to provide products and services in those areas where the Company has a strategic marketing advantage, usually due to geographic coverage and ownership of physical or contractual assets.

	Three Months Ended March 31,
	2005		2004

FINANCIAL DATA (Thousands)

Net operating revenues	$	16,012	$	10,445
Operating expenses (total operating expenses excluding depreciation, depletion and amortization)	362		1,017
Depreciation, depletion and amortization (DD&A)	19		42
Operating income	$	15,631	$	9,386

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

Net operating revenues increased $5.6 million, or 54%, from $10.4 million in 2004 to $16.0 million in 2005. Increased volatility in the natural gas market presented more valuable storage asset optimization opportunities in the current year.

Operating expenses excluding DD&A decreased by approximately $0.6 million from the first quarter of 2004 to the first quarter of 2005. Operating expenses in the first quarter of 2004 were higher than the current year quarter as a result of costs incurred for legal claims and reserves in the prior year.

EQUITABLE SUPPLY

Equitable Supply consists of two activities, production and gathering, with operations in the Appalachian Basin region of the United States. Equitable Production develops, produces and sells natural gas and minor amounts of associated crude oil and its associated by-products. Equitable Gathering engages in natural gas gathering and the processing and sale of natural gas liquids.

Purchase of Eastern Seven Partners L.P.

In January 2005, the Company purchased the 99% limited partnership interest in Eastern Seven Partners L.P. (ESP) for cash of $57.5 million and assumed liabilities of $47.3 million. The purchase added approximately 30 Bcfe of reserves.

Subsequent Event

In April 2005, the Company entered into a definitive sale agreement for the sale of certain Ohio and Pennsylvania oil and gas properties. This transaction is in line with management’s strategic objective to focus on the Company’s core natural gas producing properties. The sale, which is subject to certain conditions, is expected to close in the second quarter of 2005. In accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Activities,” this sale of only a portion of the gas properties may be treated as a normal retirement with no gain or loss recognized if doing so does not significantly affect the unit of production amortization rate. Given the size of the transaction, the Company believes that no gain or loss will be recorded upon the closing of the transaction.

Other

Equitable Supply implemented a significant change to its business model in late 2004. Previously, Equitable Supply attempted to optimize profits by focusing primarily on operating cost minimization and secondarily on a moderate drilling program to maximize profits. This strategy was based on low price assumptions. To assume low prices, however, in spite of current market conditions, limits opportunities. The Company's new strategy recognizes that, in the current price environment, profit maximization is better achieved by primarily focusing on developing new opportunities, and secondarily focusing on cost control. The margin leverage from realizable gas prices outweighs the increase in unit cost structure necessary to utilize this strategy. In 2004, the Company reduced the number of wells drilled compared to prior years in order to focus on infrastructure improvement. This change was intended to accelerate sales from existing wells, to reduce the Company’s long-term requirement for maintenance capital with respect to these wells, and to provide a platform for higher drilling levels prospectively. With the significant and sustained increase in NYMEX natural gas prices during the past year, the Company re-evaluated its growth strategy. By providing for a stable base infrastructure for the current natural gas wells, the Company can benefit from the higher gas prices by obtaining accelerated volumes from the current wells and by increasing the number of wells it intends to drill in 2005 and beyond. The Company expects to drill 440 wells in 2005 compared to 314 in 2004. At a NYMEX price of $6.00, in addition to its 1,441 net proved undeveloped drilling locations, the Company believes that it has available on acreage it controls, at least 7,000 additional net drilling locations on unproved properties. The execution of this new model

will be challenging and will result in higher operating expense, but the Company is committed to improving outcomes through actions such as: (1) significantly increasing the Company’s focus on well performance by lowering bottom-hole pressure; (2) accelerating implementation and installation of compressor stations and facilities to lower surface pressure; (3) reducing internal and external curtailments of gas sales; (4) reducing “lost” gas to the minimum level that can be justified economically and not accepting “unaccounted for” gas; and (5) increasing accountability, ownership and attention to detail in the field and engineering areas.

Relocation of certain employees of Equitable Supply’s operations to the Company’s new office building occurred during the first quarter of 2005. As a result, Equitable Supply recorded a loss on disposal of assets of approximately $0.5 million as selling, general and administrative expense during the first quarter of 2005 related to these relocation activities.

	Three Months Ended March 31,
	2005		2004
OPERATIONAL DATA

Total sales volumes (MMcfe)	18,328		17,042
Capital expenditures (thousands) (a)	$	88,631	$	21,053

FINANCIAL DATA (Thousands)

Production revenues	$	89,104	$	79,429
Gathering revenues	24,171		19,815
Total net operating revenues	113,275		99,244
Operating expenses:
Lease operating expenses, excluding production taxes	6,235		4,254
Production taxes (b)	7,935		5,833
Gathering and compression (operation and maintenance)	9,896		6,587
Selling, general and administrative (SG&A)	7,471		6,997
Depreciation, depletion and amortization (DD&A)	16,385		14,043
Total operating expenses	47,922		37,714
Operating income	$	65,353	$	61,530

Earnings from nonconsolidated investments	$	47	$	143

(a) Capital expenditures for the three months ended March 31, 2005 include $57.5 million for the acquisition of the 99% limited partnership interest in ESP which was separately approved by the Board of Directors of the Company in addition to the total amount originally authorized for the 2005 capital budget program.

(b) Production taxes include severance and production-related ad valorem taxes.

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

Equitable Supply’s operating income for the 2005 first quarter totaled $65.4 million, 6% higher than the $61.5 million earned in the same period last year. Total net operating revenues were $113.3 million, $14.1 million higher than the previous year’s total net operating revenues of $99.2 million. Production revenues increased $9.7 million quarter over quarter to $89.1 million in 2005 from $79.4 million in 2004. The increase is primarily due to increased sales as a result of the purchase of ESP and a higher average well-head sales price partially offset by reduced base sales volumes. Gathering revenues were $4.4 million higher at $24.2 million, compared with $19.8 million in 2004. The increased gathering revenue was primarily due to an increase in gathering rates and increased volumes.

Total operating expenses for the 2005 first quarter totaled $47.9 million compared to $37.7 million in the 2004 first quarter. A significant reason for this increase was additional costs of $3.4 million resulting from the purchase of ESP. Excluding the ESP costs, the increase in total operating expenses was primarily due to increases of $3.0

Equitable Production

	Three Months Ended March 31,
	2005			2004
OPERATIONAL DATA

Total sales volumes (MMcfe)	18,328			17,042
Average (well-head) sales price ($/Mcfe)	$	4.74		$	4.50

Company usage, line loss (MMcfe)	1,231			1,199

Natural gas inventory usage, net (MMcfe)	(51		)	(112		)

Natural gas and oil production (MMcfe) (a)	19,508			18,129

Lease operating expense, excluding production taxes ($/Mcfe)	$	0.32		$	0.23
Production taxes ($/Mcfe)	$	0.41		$	0.32
Production depletion ($/Mcfe)	$	0.62		$	0.54

Depreciation, depletion and amortization (in thousands):
Production depletion	$	12,059		$	9,822
Other depreciation, depletion and amortization	661			574
Total depreciation, depletion and amortization	$	12,720		$	10,396

(a) Natural gas and oil production represents the Company’s interest in gas and oil production measured at the well-head. It is equal to the sum of total sales volumes, Company usage, line loss, and natural gas inventory.

	Three Months Ended March 31,
	2005		2004
FINANCIAL DATA (Thousands)

Production revenues	$	86,940	$	76,648
Other revenues	2,164		2,781
Total production revenues	89,104		79,429

Operating expenses:
Lease operating expense, excluding production taxes	6,235		4,254
Production taxes	7,935		5,833
Selling, general and administrative (SG&A)	4,931		4,618
Depreciation, depletion and amortization (DD&A)	12,720		10,396
Total operating expenses	31,821		25,101

Operating income	$	57,283	$	54,328

Earnings from nonconsolidated investments	$	47	$	143

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

Equitable Production’s revenues, which are derived primarily from the sale of produced natural gas, increased $9.7 million from the first quarter of 2004 to the first quarter of 2005. The increase is primarily due to increased sales volumes resulting from the purchase of ESP ($9.4 million) and a higher average well-head sales price ($4.2 million)

partially offset by reduced base sales volumes ($3.9 million). Sales volumes increased 2.0 Bcf in the first quarter of 2005 related to the purchase of ESP. The average well-head sales price was $4.74 per Mcfe in the first quarter of 2005 compared to $4.50 per Mcfe in the same period of the prior year.

Operating expenses increased $6.7 million or 27% over the prior year from $25.1 million to $31.8 million. This increase was primarily due to increased DD&A ($2.3 million), increased production taxes ($2.1 million), increased lease operating expenses ($1.9 million) and increased SG&A ($0.3 million). The increase in DD&A is due to an $0.08 per Mcf increase in the unit depletion rate excluding ESP ($1.4 million) and increased volumes related to the ESP purchase ($1.3 million) partially offset by decreased base production volumes ($0.4 million). The $0.08 per Mcf increase in the unit depletion rate is primarily the result of the net development capital additions in 2004 on a relatively consistent proved reserve base and the purchase of ESP. The increase in production taxes is a result of increased property taxes ($1.4 million) and increased severance taxes ($0.7 million). The increase in property taxes that the Company experienced is a direct result of increased prices and sales in prior years, as property taxes in several of the taxing jurisdictions where the Company’s wells are located are calculated based on prior year’s gas commodity prices and sales volumes. The increase in severance taxes (a production tax directly imposed on the value of gas extracted) is primarily attributable to higher gas commodity prices and sales volumes in the various taxing jurisdictions that impose such taxes. The increase in lease operating expenses is primarily the result of an increase in well maintenance and well surveillance costs ($0.8 million), expenses related to the operations of the interest acquired in ESP ($0.8 million) and liability insurance premiums ($0.4 million). The increase in well maintenance costs is the result of the Company’s strategy to focus on current infrastructure as well as increased costs from vendors relative to higher gas prices.

Equitable Gathering

	Three Months Ended March 31,
	2005		2004
OPERATIONAL DATA

Gathered volumes (MMcfe)	33,152		32,568
Average gathering fee ($/Mcfe) (a)	$	0.73	$	0.61
Gathering and compression expense ($/Mcfe)	$	0.30	$	0.20
Gathering and compression depreciation ($/Mcfe)	$	0.10	$	0.10

Depreciation, depletion and amortization (in thousands):
Gathering and compression depreciation	$	3,324	$	3,352
Other depreciation, depletion and amortization	341		295
Total depreciation, depletion and amortization	$	3,665	$	3,647

FINANCIAL DATA (Thousands)

Gathering revenues	$	24,171	$	19,815

Operating expenses:
Gathering and compression expense	9,896		6,587
Selling, general and administrative	2,540		2,379
Depreciation, depletion and amortization	3,665		3,647
Total operating expenses	16,101		12,613

Operating income	$	8,070	$	7,202

(a) Revenues associated with the use of pipelines and other equipment to collect, process and deliver natural gas from the field where it is produced, to the trunk or main transmission line. Many contracts are for a blended gas commodity and gathering price, in which case the Company utilizes standard measures in order to split the price into its two components.

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

Equitable Gathering’s revenues increased $4.4 million, or 22%, from $19.8 million in the first quarter of 2004 to $24.2 million in the first quarter of 2005. The increase was primarily attributable to a $0.12 per Mcfe increase in the average gathering fee and a 0.6 Bcf increase in gathered volumes. The 20% rise in the average gathering fee in 2005 is related to Equitable Gathering’s implementation of a model where costs incurred by the gathering business, both operating and capital, are expected to be recovered in rates associated with transporting gas on the gathering systems.

Total operating expenses increased $3.5 million to $16.1 million in the 2005 first quarter from $12.6 million in the same quarter last year. The increase resulted primarily from a 50% increase in gathering and compression costs. The $3.3 million increase in gathering and compression costs is primarily attributable to an increase in field labor and related employment costs, compressor station operations and repair costs and compressor electricity charges resulting from newly installed electric compressors. The increase in field labor and related employment costs was due to an increase in headcount related to Equitable Gathering’s current strategy to utilize more of its resources to aggressively tend to the improvement of base infrastructure. Measures taken to support this strategy, such as the installation of compressor stations and facilities to reduce surface pressure and efforts related to reducing the internal curtailment of gas sales, have increased costs from the levels experienced in the first quarter of 2004. Additionally, horsepower has increased more than 20% from the first quarter of 2004 to the first quarter of 2005. Equitable Gathering continues to pursue recovery of these increased costs to provide gathering services through the rates it charges to its customers.

NORESCO

NORESCO provides an integrated group of energy-related products and services that are designed to reduce its customers’ operating costs and improve their energy efficiency. The segment’s activities comprise performance contracting, energy efficiency programs, combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation. NORESCO’s customers include governmental, military, institutional, commercial and industrial end-users.

	Three Months Ended March 31,
	2005			2004
OPERATIONAL DATA

Revenue backlog, end of period (thousands)	$	82,511		$	118,261
Gross profit margin	25.8		%	28.9		%
SG&A as a% of revenue	15.5		%	17.0		%

Capital expenditures (thousands)	$	217		$	28

FINANCIAL DATA (Thousands)

Energy service contract revenues	$	38,491		$	33,926
Energy service contract costs	28,562			24,105
Net operating revenue (gross profit margin)	9,929			9,821

Operating expenses:
Selling, general and administrative	5,975			5,784
Depreciation, depletion and amortization	249			251
Total operating expenses	6,224			6,035

Operating income	$	3,705		$	3,786

Earnings from nonconsolidated investments:
International investments	$	1,159		$	716
Other	$	19		$	4
Minority interest	$	(439	)	$	(370	)

Three Months Ended March 31, 2005
vs. Three Months Ended March 31, 2004

NORESCO’s total revenues for the first quarter of 2005 increased $4.6 million to $38.5 million from $33.9 million in the first quarter of 2004, primarily due to increased construction activity of energy infrastructure projects versus the prior year. NORESCO’s gross profit margin increased to $9.9 million for the first quarter of 2005 compared to $9.8 million during the first quarter of 2004. Gross profit margin as a percentage of revenue decreased from 28.9% in the first quarter of 2004 to 25.8% in the first quarter of 2005 reflecting a change in the mix of projects constructed during those three-month periods.

NORESCO’s operating income was $3.7 million in the first quarter of 2005 compared to $3.8 million in the same period in 2004, a decrease of $0.1 million. The decrease was primarily due to an increase in SG&A expense of $0.2 million partially offset by an increase in net operating revenues of $0.1 million. The increase in SG&A expense was due in part to a decrease in bad debt reserve in the first quarter of 2004 as a result of collections on past due receivables.

During the first quarter of 2005, NORESCO received a partnership distribution in the amount of $0.5 million related to Petroelectrica de Panama LDC, an international investment which was entirely written off through impairment charges during the second quarter of 2004. This distribution was the result of the dismantling of the plant and subsequent sale of assets. NORESCO also reduced future obligations for exiting the international market by $0.5 million and recorded a gain on the sale of Compania Hidroelectrica Dona Julia, S.D.R. Ltd. of $0.2 million. These items are included in earnings from nonconsolidated investments in the table above.

Revenue backlog decreased $35.8 million from $118.3 million on March 31, 2004 to $82.5 million on March 31, 2005. This decrease in backlog was primarily due to a higher number of federal government contracts awarded in the third quarter of 2003 and the inability to contract with the federal government for the twelve month period October 2003 to October 2004 due to the lapse of enabling legislation regarding performance contracting. On October 28, 2004, the President signed legislation extending the contracting period for performance contracting at federal government facilities through October 2006 but NORESCO has yet to realize significant increases in contracting activity from this legislation.

EQUITY IN NONCONSOLIDATED INVESTMENTS

In 2000, Equitable Supply sold an interest in oil and gas properties to a trust, Appalachian Natural Gas Trust (ANGT). The Company retained a 1% interest in profits of ANGT and has separately negotiated arms-length, market-based rates with ANGT for gathering, marketing, and operating fees to deliver its natural gas to market. At March 31, 2005, the Company has a receivable recorded from ANGT totaling $1.4 million. This receivable resulted from inadvertent overpayments to ANGT for more than the amount due under the Net Profits Interest Agreement. Under the terms of the agreement, the Company will deduct the overpayment from future payments to ANGT over an extended period of time.

CAPITAL RESOURCES AND LIQUIDITY

Operating Activities

Cash flows provided by operating activities in the first quarter of 2005 totaled $35.4 million, a $110.2 million decrease from the $145.6 million recorded in the prior year period. The decrease is primarily the result of a larger increase in accounts receivable and unbilled revenues during the three months ended March 31, 2005 than during the three months ended March 31, 2004. A significant portion ($131.0 million) of the increase in accounts receivable and unbilled revenues is the result of increased cash remittances to financial institutions for margin deposit requirements on the Company’s natural gas swap agreements. A portion of these increased remittances was funded during the first quarter of 2005 through increased borrowings under the Company’s commercial paper program, as discussed below in “Financing Activities.” Due to continued increases in natural gas prices and resulting increases in the Company’s net liability position under its natural gas swap agreements, the Company has borrowed additional amounts through its commercial paper program to fund its margin deposits under its exchange-traded natural gas swap agreements. 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. These threshold amounts are subject to adjustment as defined in the agreements with the counterparties based on factors including changes in the Company’s debt ratings and net worth. The margin deposits are remitted back to the Company in part or in full when the excess of the derivative liability over the agreed-upon threshold is reduced below the amount deposited. The Company has recorded such deposits in the amount of $167.0 million as accounts receivable in its Condensed Consolidated Balance Sheet as of March 31, 2005.

Other significant cash flow uses from operations during the first quarter of 2005 included the payout of the stock units that vested December 31, 2004 under the Company’s 2002 Executive Performance Incentive Program.

These net cash flow uses were partially offset by significant reductions in inventory, as the Company made large withdrawals from storage in the first quarter of 2005, as is typical during the winter months of January through March.

Investing Activities

Cash flows used in investing activities in the first three months of 2005 were $101.7 million compared to $35.4 million in the prior year. The change from the prior year is primarily attributable to $57.5 million in capital expenditures for the acquisition of the 99% limited partnership interest in Eastern Seven Partners L.P. Other significant investing activities that occurred during the first quarter of 2005 include $44.0 million in other capital expenditures, an increase of $8.1 million over the first quarter of 2004 under the Company’s 2005 capital budget which contemplates increased expenditures during this year, $3.4 million expended for investment in debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures and $3.0 million of proceeds received from the sale of the Company’s investment interest in Dona Julia to a third party purchaser in the first quarter of 2005.

Financing Activities

Cash flows provided by financing activities during the first three months of 2005 were $69.1 million compared to $142.2 million used in financing activities in the prior year period. The increase in cash provided by financing activities is primarily the result of additional borrowings during the first quarter of 2005 under the Company’s commercial paper program due to increased margin deposit requirements on its natural gas swap agreements, compared to decreases in the Company’s outstanding short-term loans in the first quarter of 2004.

Other significant financing activities that occurred during the first quarter of 2005 included dividend payments of $22.9 million, a $4.2 million increase as compared to the first quarter of 2004, and the repurchase of 0.3 million shares of the Company’s outstanding common stock for $17.1 million.

The Company believes that it has adequate borrowing capacity to meet its financing requirements. Bank loans and commercial paper, supported by available credit, are used to meet short-term financing requirements. The Company maintains, with a group of banks, a three-year revolving credit agreement providing $500 million of available credit that expires in October 2006. The credit agreement may be used for, among other things, credit support for the Company’s commercial paper program. As of March 31, 2005, the Company has the authority to arrange for a commercial paper program up to $650 million. The amount of commercial paper outstanding at March 31, 2005 is $392.0 million.

In July of 2004, the Company entered into three 7.5 year secured variable share forward transactions to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee Corporation (Kerr-McGee) shares (see Note D to the condensed consolidated financial statements). Each transaction permits receipt of an amount up to the net present value of the floor price prior to maturity. The economic characteristics of any receipt would be considered that of a borrowing.

Fluctuations in Natural Gas Prices

Due to the nature of the Company’s operations, fluctuations in natural gas prices can significantly impact its operating cash flows, and consequently, the availability of funds for use in both investing and financing activities. As a result of the higher than average natural gas prices during the past several months, the Company’s liquidity position could be negatively affected by further price increases. The increase in natural gas prices may be accompanied by or result in increased well drilling costs, as the demand for well drilling operations continues to increase; increased deferral of purchased gas costs for the Distribution operations (however, purchased gas costs are subsequently recoverable from utility customers in future months through gas cost adjustment clauses included in the Distribution operation’s filed rate tariffs); increased severance and property taxes, as the Company is subject to higher taxes due to increased volumes of gas extracted from the wells combined with increased value of the gas extracted from the wells; increased lease operating expenses due to increased demand for lease operating services; and increased exposure to credit losses resulting from potential increases in uncollectible accounts receivable from the Distribution operation’s customers. The Company’s risk management program and available borrowing capacity currently in place provide means for the Company to manage these risks. Furthermore, the inventory owned by the Company as reserves or in storage increases in value, thus increasing the creditworthiness of the Company and facilitating its ability to access the credit markets for additional liquidity if needed.

Commodity Risk Management

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and over-the-counter (OTC) natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes.

The fair value of these derivative commodity instruments was a $54.8 million asset and a $694.0 million liability as of March 31, 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 commodity instruments, at fair value, increased from a net liability of $323.6 million at December 31, 2004 to a net liability of $639.2 million at March 31, 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 total 428.0 Bcf and 432.6 Bcf as of March 31, 2005 and December 31, 2004, respectively, and primarily relate to natural gas swaps. The open swaps at March 31, 2005 have maturities extending through 2011.

The approximate volumes and prices of the Company’s hedges and fixed price contracts for 2005 through 2007 are:

	2005**		2006		2007
Volume (Bcf)	47		62		59
Average Price per Mcf (NYMEX)*	$	4.82	$	4.73	$	4.75

* The above price is based on a conversion rate of 1.05 MMbtu/Mcf

** April through December

The Company deferred net losses of $390.5 million and $197.3 million in accumulated other comprehensive loss, net of tax, as of March 31, 2005 and December 31, 2004, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $123.4 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of March 31, 2005 will be recognized in earnings during the next twelve months. This recognition occurs through a reduction in the Company’s net operating revenues, which will result in a reduction in the realized sales price.

With respect to hedging the Company’s exposure to changes in natural gas commodity prices, the Company’s current hedged position provides price protection for a substantial portion of expected production for the years 2005 through 2008, and for over 30% of expected equity production for the years 2009 through 2011. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is less than $0.01 per diluted share for the remainder of 2005 and approximately $0.01 to $0.03 per diluted share per year for 2006 through 2008. The preponderance of derivative commodity instruments utilized by the Company tends to be fixed price swaps or NYMEX-traded forwards. This approach avoids the higher cost of option instruments but limits the upside potential. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices.

Commitments and Contingencies

The Company has annual commitments of approximately $30.7 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to approximately eleven years, as of March 31, 2005, which relate to natural gas distribution and production operations. However, approximately $19.6 million of these costs are recoverable in customer rates.

In the third quarter of 2003, the Company entered into a long-term lease with Continental Real Estate Companies (Continental) to occupy office space in a building at the North Shore in Pittsburgh. This action will help consolidate the Company’s administrative operations. Continental is constructing and will own the office building, with completion of the building expected during the second quarter of 2005. Relocation operations began late in the first quarter of 2005 and will continue through the second quarter of 2005. The relocation operations may result in the early termination of several current operating leases and the early retirement of assets and leasehold improvements at several of these locations. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company recognized a loss on disposal of assets of approximately $0.5 million, recorded in selling, general and administrative expense, during the first quarter of 2005 related to its relocation activities. The Company continues to evaluate its lease requirements and depending on a final determination of these requirements, expects to incur additional costs in the second quarter of 2005 between approximately $6 million and $8 million related to the relocation of its administrative operations for its Utilities and Headquarters personnel.

In the ordinary course of business, various legal claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves for pending litigation, which it believes are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company.

bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. In the third quarter of 2003, ERI JAM transferred control of the international infrastructure project under the partnership agreement to the other non-affiliate general partner. In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM as Debtor-in-Possession in the Chapter 11 case. EAL, an affiliate of JBG, is a limited partner in EAL/ERI Cogeneration Partners LP. In October 2003, JBG and EAL also filed a multi-count complaint seeking damages against Equitable and certain of its affiliates in U.S. District Court (Western District of Pennsylvania) alleging breach of contract, tortious interference with contractual relations, negligence and a variety of related claims with respect to the operation and management of EAL/ERI Cogeneration Partners LP. On March 2, 2005, the Company entered into a settlement agreement with EAL and JBG pursuant to which, among other things, (a) the parties mutually released one another, (b) ERI JAM and its non-operating holding company will be transferred to an affiliate of JBG, and (c) EAL and JBG are responsible for settling ERI JAM’s bankruptcy case and have delivered to the Company broad releases from the more significant trade creditors and the project lender.

The various regulatory authorities that oversee Equitable’s operations will, from time to time, make inquiries or investigations into the activities of the Company. It is the Company’s policy to comply with applicable laws and cooperate when regulatory bodies make requests.

The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position or results of operations.

In the second quarter of 2004, the Company established a liability for a guarantee in the amount of $5.8 million in support of a 50% owned non-recourse financed energy project in Panama. The guarantee covers a project loan debt service requirement.

Investment in Kerr-McGee Corporation

In the second quarter of 2004, Westport Resources Corporation (Westport) and Kerr-McGee completed a merger. As a result of the transaction, the Company received 0.71 shares of Kerr-McGee for each Westport share owned. Prior to the merger, the Company owned 11.53 million shares, or 17%, of Westport, resulting in the Company receiving 8.2 million shares of Kerr-McGee. The Company accounted for the merger transaction in accordance with Emerging Issues Task Force No. 91-5, “Nonmonetary Exchange of Cost-Method Investments” (EITF 91-5). EITF 91-5 states that an investor in an acquired company that accounts for the investment under the cost-method shall record the transaction at fair value, resulting in a new basis and recognition of gains or losses in the income statement. 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. The Company recorded its book basis in the Kerr-McGee shares at $49.82 per share, which included a discount to the market price for trading restrictions on the securities. The discount was accreted into other comprehensive income during the third quarter of 2004.

Subsequent to the Kerr-McGee/Westport merger, the Company sold 800,000 Kerr-McGee shares for $42.8 million, thus resulting in a realized gain of $3.0 million in the second quarter of 2004. Additionally, on June 30, 2004, the Company irrevocably committed to contribute 357,000 Kerr-McGee shares to Equitable Resources Foundation, Inc. This resulted in the Company recording a community-giving foundation contribution expense of $18.2 million during the second quarter of 2004. The shares were transferred to this foundation in the third quarter of 2004.

In the third quarter of 2004, the Company entered into three variable share forward contracts to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee shares (See Note D to the Company’s condensed consolidated financial statements). The variable share forward contracts, which contain collars, meet the requirements of SFAS No. 133 Implementation Issue G20, “Assessing and Measuring the Effectiveness of an Option used in a Cash Flow Hedge” and have been designated cash flow hedges. Under this guidance, complete hedging effectiveness is assumed and the entire fair value of the collar is recorded in other comprehensive income.

These variable share forward contracts provide for limited downside in the underlying Kerr-McGee shares while continuing to maintain considerable exposure to potential upside in the value of Kerr-McGee. The collars effectively limit the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares between a blended average floor price per share of $53.06 and a blended average cap price per share of $100.79. The three tranches of contracts were allocated among three different counterparties in a bidding process designed to maximize the pricing of the collars while providing an opportunity to minimize any counterparty credit exposure. Due to the significant Kerr-McGee share price increase in the first quarter of 2005, the fair value of the call components of the collars became much higher than the fair value of the put components of the collars. As a result, the Company recorded the net extrinsic value of the collars as a derivative liability. As of March 31, 2005, a liability of $102.8 million was recorded in derivative instruments, at fair value, and the amount recorded in accumulated other comprehensive loss, net of tax, related to the change in fair value of the collars for the quarter ended March 31, 2005 was $66.8 million. The Kerr-McGee share price was between the floor price and the cap price for each of these transactions so no intrinsic value was recorded.

A variable portion of the dividends received on the underlying Kerr-McGee shares must be paid to each counterparty depending upon the hedged position of such counterparty. Based on the current hedged position of the counterparties, the Company expects to pay to each counterparty approximately 75% of the next Kerr-McGee dividend. In the first quarter of 2005, the Company recorded pre-tax dividend income, net of payments to the counterparties, of $1.1 million, which is recorded in other income, net on the Statement of Consolidated Income for the three months ended March 31, 2005. At March 31, 2005, the Company owned approximately 7.0 million Kerr-McGee shares, of which approximately 1.0 million shares remained unhedged. In April 2005, the Company sold the remaining approximately 1.0 million unhedged Kerr-McGee shares for total proceeds of $77.9 million. The sale of these shares resulted in a total gain to the Company of $26.7 million. The sale of these shares was determined by the Company to constitute the best use of this asset.

In April 2005, Kerr-McGee announced a planned $4.0 billion offer to buy back shares of its own common stock. In conjunction with this announcement, Kerr-McGee also announced that it expects to lower the quarterly dividend on its common stock to 5 cents per share, compared with the 45 cents per share dividend declared during the three months ended March 31, 2005. The dividend is expected to be reduced beginning in the quarter ending June 30, 2005.

Benefit Plans

In the fourth quarter of 2003, the Company froze the pension benefit provided through a defined benefit plan to approximately 340 salaried employees. Effective December 31, 2004, the Company settled the pension obligation of those non-represented employees whose benefits were frozen as of December 31, 2003. As a result of this settlement, which was accounted for under SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement expense of $13.4 million for the year ended December 31, 2004. The settlement expense that was recognized for these non-represented employees was primarily the result of accelerated recognition of approximately $11.0 million in previously deferred unrecognized losses. The Company expects to incur additional settlement expense in the second quarter of 2005 when the settlement is fully funded. As part of this settlement, the affected employees were provided the option to either roll over the lump-sum value of their cash balance account to the Company’s defined contribution plan, or to receive an insured monthly annuity benefit at the time they retire. The Company now provides benefits to these employees under a defined contribution plan that covers all other non-represented employees of the Company. The Company’s pension expense, exclusive of any special termination benefits and curtailment losses, totaled $0.7 million and $0.6 million for the three months ended March 31, 2005 and 2004, respectively.

The Company expects to make a cash contribution of approximately $13 million to its defined benefit plan during 2005 to fully fund the cash balance participants portion of the defined benefit plan which was settled effective December 31, 2004. The Company did not make a contribution to its defined benefit plan in 2004. Although the Company has previously made significant changes to reduce its exposure to market risk from its defined benefit plan, the Company continues to evaluate its exposure and expects to make additional changes to its defined benefit plan in the second quarter of 2005.

Incentive Compensation

The Company continues to shift its compensation focus from stock options to performance-based stock units and time-restricted stock awards. Management and the Board of Directors believe that such an incentive compensation

The Company recorded the following incentive compensation expense for the periods indicated below:

	Three Months Ended March 31,
	2005		2004
	(Millions)
Short-term incentive compensation expense	$	3.1	$	3.0
Long-term incentive compensation expense	3.9		3.9
Total incentive compensation expense	$	7.0	$	6.9

On February 23, 2005, the Compensation Committee of the Board of Directors adopted the 2005 Executive Performance Incentive Program (2005 Program) under the 1999 Long Term Incentive Plan. The 2005 Program was established to provide additional incentive benefits to retain executive officers and certain other employees of the Company to further align the interests of the persons primarily responsible for the success of the Company with the interests of the shareholders. Under the program a maximum of 600,000 stock units may be granted among a maximum of forty participants. The vesting of these stock units will occur on December 31, 2008, contingent upon a combination of the level of total shareholder return relative to 29 peer companies and the Company’s average absolute return on total capital during the four year performance period. As a result, zero to 1,500,000 units (250% of the units available for grant) may be distributed in cash or stock. The 2005 program is being accounted for as a variable plan and is being expensed over the four year performance period based on anticipated stock price and expected level of performance.

The Company applies Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for its stock-based compensation and has consequently not recognized any compensation cost for its stock option awards. Had compensation cost been determined based upon the fair value at the grant date for the prior years’ stock option grants consistent with the methodology prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation,” net income and diluted earnings per share for the three months ended March 31, 2005 would have been reduced by an estimated $0.7 million or $0.01 per diluted share. The estimate of compensation cost is based upon the use of the Black-Scholes option pricing model. The Black-Scholes model is considered a “theoretical” or probability model used to estimate what an option would sell for in the market today. The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.

The Company continually monitors its stock price and relative return in order to assess the impact on the ultimate payouts under its Executive Performance Incentive Programs (the “Plans”). These long-term incentive plan expenses are included in selling, general and administrative expenses in the Statements of Consolidated Income. Additionally, the long-term incentive plan expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note G to the condensed consolidated financial statements for further discussion of the Plans.

Federal Legislation

During October 2004, Congress passed the American Jobs Creation Act of 2004 (the Jobs Creation Act), which the President signed into law on October 22, 2004. The Jobs Creation Act is the first major corporate tax act in a number of years. Some of the key provisions of the Jobs Creation Act include a new domestic manufacturing deduction, a temporary incentive for U.S. multinationals to repatriate foreign earnings, oil and gas producer incentives (not an extension of the nonconventional fuels tax credit), new tax shelter penalties, restrictions on deferred compensation and numerous other issue-specific provisions aimed at specific transactions. The only item in this legislation that impacted the Company’s consolidated financial statements during 2004 was the temporary incentive to repatriate foreign earnings. During the second quarter of 2005, the Company anticipates completing a review of the legislation’s impact on the future deductibility of the Company’s executive compensation programs and any tax benefit that may be generated by the legislation’s domestic manufacturing deduction.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of the Company through the Equitable Supply segment and the unregulated marketing group within the Equitable Utilities segment. The Company’s use of derivatives to reduce the effect of this volatility is described in Note D to the condensed consolidated financial statements and under the caption “Commodity Risk Management” in Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The Company uses simple, non-leveraged derivative commodity instruments that are placed with major institutions whose creditworthiness is continually monitored. The Company also enters into energy trading contracts to leverage its assets and limit the exposure to shifts in market prices. The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.

For derivative commodity instruments used to hedge the Company’s forecasted production, the Company sets policy limits relative to the expected production and sales levels, which are exposed to price risk. The financial instruments currently utilized by the Company include forward contracts and swap agreements, which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers options and other contractual agreements in determining its commodity hedging strategy. Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. In general, the Company’s strategy is to hedge production at prices considered to be favorable to the Company. The Company attempts to take advantage of price fluctuations by hedging more aggressively when market prices move above recent historical averages and by taking more price risk when prices are significantly below these levels. The goal of these actions is to earn a return above the cost of capital and to lower the cost of capital by reducing cash flow volatility.

For derivative commodity instruments held for trading positions, the marketing group will engage in financial transactions also subject to policies that limit the net positions to specific value at risk limits. The financial instruments currently utilized by the Company include forward contracts and swap agreements, which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers options and other contractual agreements in determining its commodity hedging strategy.

With respect to the derivative commodity instruments held by the Company for purposes other than trading as of March 31, 2005, the Company continued to execute its hedging strategy by utilizing price swaps of approximately 303.7 Bcf of natural gas. These derivatives have hedged a portion of expected equity production through 2011. See the “Commodity Risk Management” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q for further discussion. A decrease of 10% in the market price of natural gas from the March 31, 2005 levels would increase the fair value of natural gas instruments by approximately $217.1 million. An increase of 10% in the market price of natural gas would decrease the fair value by the same amount.

With respect to the derivative commodity instruments held by the Company for trading purposes as of March 31, 2005, a decrease of 10% in the market price of natural gas from the March 31, 2005 levels would increase the fair value by approximately $0.2 million. An increase of 10% in the market price would decrease the fair value by the same amount.

The Company determined the change in the fair value of the derivative commodity instruments using a method similar to its normal change in fair value as described in Note D to the condensed consolidated financial statements. The Company assumed a 10% change in the price of natural gas from its levels at March 31, 2005. The price change was then applied to the derivative commodity instruments recorded on the Company’s Condensed Consolidated Balance Sheet, resulting in the change in fair value.

In the third quarter of 2004, the Company entered into variable share forward contracts to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee shares. The variable share forward contracts, which contain collars, meet the requirements of SFAS No. 133 Implementation Issue G20, “Assessing and Measuring the

Effectiveness of an Option used in a Cash Flow Hedge” and have been designated as cash flow hedges. Under this guidance, complete hedging effectiveness is assumed and the entire fair value of the collar is recorded in other comprehensive income. These variable share forward contracts provide tax efficient monetization alternatives for the now limited downside in the underlying Kerr-McGee shares while continuing to maintain considerable exposure to potential upside in the value of Kerr-McGee.

The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative commodity contracts. This credit exposure is limited to derivative commodity instruments with a positive fair value. NYMEX traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative commodity instruments by limiting dealings to those counterparties who meet the Company’s criteria for credit and liquidity strength.

See Note D regarding Derivative Instruments in the notes to the condensed consolidated financial statements and the “Commodity Risk Management” section contained in the Capital Resources and Liquidity section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for further information.

See “Fluctuations in Natural Gas Prices” in Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion on impact of fluctuations in natural gas prices on the Company’s operations.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Executive Vice President, Finance and Administration conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as defined in Exchange Act Rule 13a-15(e) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Executive Vice President, Finance and Administration concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.

Changes in Internal Control over Financial Reporting

There were no changes in internal controls over financial reporting that occurred during the first quarter of 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended March 31, 2005.

Period	Total number of shares (or units) purchased (a)	Average price paid per share (or unit)		Total number of shares (or units) purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs (a), (b)

January 2005
(January 1 – January 31)	—	$	—	—	2,776,700

February 2005
(February 1 – February 28)	140,682	$	58.26	130,000	2,646,700

March 2005
(March 1 – March 31)	244,271	$	59.56	160,000	2,486,700

Total	384,953			290,000

(a) Includes 94,953 shares delivered in exchange for the exercise of stock options and restricted share awards to cover award cost and tax withholding. All other purchases were open market purchases made pursuant to the Company’s publicly disclosed repurchase program. The Company routinely enters into “10b5-1 plans,” or trading plans, to facilitate continuity of its share repurchase program through earnings blackout periods.

(b) Equitable’s Board of Directors has authorized a share repurchase program with a current maximum of 21.8 million shares and no expiration date. The program was initially publicly announced on October 7, 1998 with subsequent amendments announced on November 12, 1999, July 20, 2000 and April 15, 2004.

INDEX TO EXHIBITS

Exhibit No.	Document Description

3.01	Bylaws of the Company (amended through January 12, 2005 and approved February 4, 2005)	Filed as Exhibit 3.01 to Form 8-K filed on February 10, 2005

10.01	Equitable Resources, Inc. 2005 Executive Performance Incentive Program	Filed as Exhibit 10.01 to Form 8-K filed on March 1, 2005

10.02	Form of Participant Award Agreement under the Equitable Resources, Inc. 2005 Executive Performance Incentive Program	Filed as Exhibit 10.02 to Form 8-K filed on March 1, 2005

10.03	2005 Directors’ Compensation and Retirement Program	Filed Herewith

31.1	Certification by Murry S. Gerber pursuant to Rule 13a-14(a) or Rule 15d-14(a)	Filed Herewith

31.2	Certification by David L. Porges pursuant to Rule 13a-14(a) or Rule 15d-14(a)	Filed Herewith

32	Certification by Murry S. Gerber, David L. Porges, and Philip P. Conti pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed Herewith

Part I. Financial Information:

Item 1.	Financial Statements (Unaudited):

	Statements of Consolidated Income for the Three Months Ended March 31, 2005 and 2004

	Statements of Condensed Consolidated Cash Flows for the Three Months Ended March 31, 2005 and 2004

	Condensed Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004

	Notes to Condensed Consolidated Financial Statements

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Item 4.	Controls and Procedures

Part II. Other Information:

Item 1.	Legal Proceedings

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds

Item 6.	Exhibits

Signature

Index to Exhibits

(a)	Exhibits:

	3.01	Bylaws of the Company (amended through January 12, 2005 and approved February 4, 2005)

	10.01	Equitable Resources, Inc. 2005 Executive Performance Incentive Program

	10.02	Form of Participant Award Agreement under the Equitable Resources, Inc. 2005 Executive Performance Incentive Program

	10.03	2005 Directors’ Compensation and Retirement Program

	31.1	Certification by Murry S. Gerber pursuant to Rule 13a-14(a) or Rule 15d-14(a)

	31.2	Certification by David L. Porges pursuant to Rule 13a-14(a) or Rule 15d-14(a)

	32	Certification by Murry S. Gerber, David L. Porges, and Philip P. Conti pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	EQUITABLE RESOURCES, INC.
	(Registrant)


	/s/ David L. Porges
	David L. Porges
	Vice Chairman and Executive Vice President,
	Finance and Administration