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 JUNE 30, 2004

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 July 31, 2004

Common stock, no par value		61,850,271 shares

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Index

Part I. Financial Information:

Item 1.	Financial Statements (Unaudited):

	Statements of Consolidated Income for the Three and Six Months Ended June 30, 2004 and 2003

	Statements of Condensed Consolidated Cash Flows for the Three and Six Months Ended June 30, 2004 and 2003

	Condensed Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003

	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 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Item 4.	Submission of Matters to a vote of Security Holders

Item 5.	Other Information

Item 6.	Exhibits and Reports on Form 8-K

Signature

Index to Exhibits

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
	2004			2003		2004			2003
	(Thousands, except per share amounts)
Operating revenues	$	240,640		$	218,496	$	641,067		$	560,818
Cost of sales	93,582			86,426		291,178			240,396
Net operating revenues	147,058			132,070		349,889			320,422

Operating expenses:
Operation and maintenance	20,271			18,601		38,969			37,456
Production	11,389			8,624		21,476			17,786
Selling, general and administrative	46,631			28,803		79,383			61,065
Depreciation, depletion and amortization	21,610			19,225		43,377			37,978
Total operating expenses	99,901			75,253		183,205			154,285

Operating income	47,157			56,817		166,684			166,137

Gain on exchange of Westport for Kerr-McGee shares	217,212			—		217,212			—
Charitable foundation contribution	(18,226		)	—		(18,226		)	(9,279		)
Equity (losses) earnings from nonconsolidated investments:
Westport	—			—		—			3,614
Impairment on nonconsolidated investments	(40,251		)	—		(40,251		)	—
Other	594			1,519		1,495			2,751
	(39,657		)	1,519		(38,756		)	6,365
Other income, net	3,600			—		3,600			—
Minority interest	(359		)	—		(729		)	(871		)
Interest charges	11,503			10,782		23,762			23,103
Income from continuing operations before income taxes and cumulative effect of accounting change	198,224			47,554		306,023			139,249
Income taxes	67,397			16,159		105,126			43,375
Income from continuing operations before cumulative effect of accounting change	130,827			31,395		200,897			95,874
Cumulative effect of accounting change, net of tax	—			—		—			(3,556		)
Net income	$	130,827		$	31,395	$	200,897		$	92,318

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	62,019			62,058		62,137			62,056
Income from continuing operations before cumulative effect of accounting change	$	2.11		$	0.51	$	3.23		$	1.55
Cumulative effect of accounting change, net of tax	—			—		—			(0.06		)
Net income	$	2.11		$	0.51	$	3.23		$	1.49
Diluted:
Weighted average common shares outstanding	63,380			63,420		63,464			63,382
Income from continuing operations before cumulative effect of accounting change	$	2.06		$	0.50	$	3.17		$	1.52
Cumulative effect of accounting change, net of tax	—			—		—			(0.06		)
Net income	$	2.06		$	0.50	$	3.17		$	1.46
Dividends declared per common share	$	0.38		$	0.30	$	0.68		$	0.50

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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(Thousands)
Cash flows from operating activities:
Income from continuing operations before cumulative effect of accounting change	$	130,827		$	31,395		$	200,897		$	95,874
Adjustments to reconcile net income to cash provided by operating activities:
Provision for losses on accounts receivable	3,299			1,214			9,780			8,879
Depreciation, depletion, and amortization	21,610			19,225			43,377			37,978
Gain on exchange of Westport for Kerr-McGee shares	(217,212		)	—			(217,212		)	—
Gain on sale of Kerr-McGee shares	(3,024		)	—			(3,024		)	—
Impairment on nonconsolidated investments	40,251			—			40,251			—
Charitable foundation contribution	18,226			—			18,226			9,279
Deferred income taxes	14,429			29,190			17,135			40,309
Recognition of prepaid forward production revenue	(5,181		)	(13,888		)	(10,363		)	(27,624		)
Loss on amendment of prepaid forward contract	5,532			—			5,532			—
Change in undistributed earnings from nonconsolidated investments	(594		)	(1,519		)	(1,495		)	(6,365		)
Amendment of prepaid forward contract	(36,792		)	—			(36,792		)	—
Decrease in accounts receivable and unbilled revenues	48,146			93,174			16,654			33,910
(Increase) decrease in inventory	(55,548		)	(31,979		)	27,987			(21,326		)
Increase (decrease) in accounts payable	8,627			(68,549		)	2,042			(6,651		)
Changes in other assets and liabilities	52,284			9,219			57,448			(18,760		)
Total adjustments	(105,947		)	36,087			(30,454		)	49,629
Net cash provided by operating activities	24,880			67,482			170,443			145,503

Cash flows from investing activities:
Capital expenditures	(44,665		)	(57,785		)	(80,535		)	(90,635		)
Purchase of minority interest in Appalachian Basin Partners, LP	—			—			—			(44,200		)
Proceeds from sale of property	—			—			—			6,550
Distributions from nonconsolidated investments	381			—			879			—
Net cash used in investing activities	(44,284		)	(57,785		)	(79,656		)	(128,285		)

Cash flows from financing activities:
Issuance of long-term debt	—			—			—			200,000
Dividends paid	(23,628		)	(12,262		)	(42,371		)	(22,847		)
Proceeds from exercises under employee compensation plans	13,093			9,744			20,666			18,527
Purchase of treasury stock	(48,459		)	(18,651		)	(63,535		)	(34,831		)
Loans against construction contracts	9,441			6,301			22,201			10,270
Repayments and retirement of long-term debt	(10,631		)	—			(20,760		)	(15,167		)
Redemption of Trust Preferred Capital Securities	—			(125,000		)	—			(125,000		)
Increase (decrease) in short-term loans	79,000			7,206			(39,601		)	(42,800		)
Net cash provided by (used in) financing activities	18,816			(132,662		)	(123,400		)	(11,848		)

Net (decrease) increase in cash and cash equivalents	(588		)	(122,965		)	(32,613		)	5,370
Cash and cash equivalents at beginning of period	5,309			146,083			37,334			17,748
Cash and cash equivalents at end of period	$	4,721		$	23,118		$	4,721		$	23,118

Cash paid during the period for:
Interest, net of amount capitalized	$	8,860		$	10,495		$	24,140		$	22,482
Income taxes paid, net of refund	$	3,394		$	8,942		$	3,403		$	10,045

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

ASSETS	June 30, 2004		December 31, 2003
	(Thousands)
Current assets:
Cash and cash equivalents	$	4,721	$	37,334
Accounts receivable (less accumulated provision for doubtful accounts: 2004, $36,704; 2003, $18,041)	202,946		176,574
Unbilled revenues	112,411		129,758
Inventory	131,050		162,090
Derivative commodity instruments, at fair value	49,262		34,657
Prepaid expenses and other	5,980		9,648
Total current assets	506,370		550,061

Equity in nonconsolidated investments	65,117		89,175

Property, plant and equipment	2,857,844		2,791,799

Less accumulated depreciation and depletion	1,058,972		1,025,017

Net property, plant and equipment	1,798,872		1,766,782

Investments, available-for-sale	384,960		363,280

Other assets	179,624		170,594

Total	$	2,934,943	$	2,939,892

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

LIABILITIES AND STOCKHOLDERS’ EQUITY	June 30, 2004			December 31, 2003
	(Thousands)
Current liabilities:

Current portion of long-term debt	$	10,557		$	21,267
Short-term loans	159,999			199,600
Accounts payable	148,005			146,086
Prepaid gas forward sale	—			20,840
Derivative commodity instruments, at fair value	256,710			137,636
Current portion of project financing obligations	60,345			56,368
Other current liabilities	95,190			121,030
Total current liabilities	730,806			702,827

Long-term debt:
Debentures and medium-term notes	618,067			632,147

Deferred and other credits:
Deferred income taxes	500,410			459,877
Deferred investment tax credits	11,584			12,125
Prepaid gas forward sale	—			20,783
Project financing obligations	47,903			48,972
Other credits	116,041			97,821
Total deferred and other credits	675,938			639,578

Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares; shares issued: June 30, 2004 and December 31, 2003, 74,504	348,537			348,133
Treasury stock, shares at cost: June 30, 2004, 12,694; December 31, 2003, 12,137 (net of shares and cost held in trust for deferred compensation of 635, $12,100 and 636, $12,111)	(338,921		)	(295,145		)
Retained earnings	1,055,613			897,087
Accumulated other comprehensive (loss) income	(155,097		)	15,265

Total common stockholders’ equity	910,132			965,340

Total	$	2,934,943		$	2,939,892

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 June 30, 2004, and the results of its operations and cash flows for the three and six-month periods ended June 30, 2004 and 2003.

The balance sheet at December 31, 2003 has been derived from the audited financial statements at that date, but does not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.

Due to the seasonal nature of the Company’s natural gas distribution and energy marketing businesses and the volatility of natural gas prices, the interim statements for the three and six-month periods ended June 30, 2004 are not necessarily indicative of the results that may be expected for the year ending December 31, 2004.

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, 2003, as well as in “Information Regarding Forward Looking Statements” on page 19 of this document.

B. Segment Information

The Company reports its operations in three segments, which reflect its lines of business. Equitable Utilities’ operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline 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 are comprised of 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’s activities are comprised of an integrated group of energy-related products and services that are designed to reduce its customers’ operating costs and improve their energy efficiency, including 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, equity in earnings of nonconsolidated investments, excluding Westport Resources Corporation (Westport), and minority interest. Interest charges 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 continuing operations and assets are generated or located in the United States.

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(Thousands)
Revenues from external customers:
Equitable Utilities	$	138,577		$	115,620		$	419,951		$	351,729
Equitable Supply	92,509			79,385			191,753			161,082
NORESCO	35,700			42,580			69,626			88,098
Less: intersegment revenues (a)	(26,146		)	(19,089		)	(40,263		)	(40,091		)
Total	$	240,640		$	218,496		$	641,067		$	560,818
Depreciation, depletion and amortization:
Equitable Utilities	$	7,424		$	6,789		$	14,750		$	13,524
Equitable Supply	13,789			12,019			27,832			23,601
NORESCO	250			341			501			690
Headquarters	147			76			294			163
Total	$	21,610		$	19,225		$	43,377		$	37,978
Operating income:
Equitable Utilities	$	11,040		$	12,728		$	67,000		$	71,755
Equitable Supply	52,726			45,767			114,256			94,180
NORESCO	3,467			2,432			7,253			6,353
Unallocated expenses	(20,076		)	(4,110		)	(21,825		)	(6,151		)
Total operating income	$	47,157		$	56,817		$	166,684		$	166,137

Reconciliation of operating income to net income:

Equity (losses) earnings from nonconsolidated investments, excluding Westport:
Equitable Supply	$	137		$	24		$	280		$	262
NORESCO (b)	(39,835		)	1,452			(39,115		)	2,389
Unallocated earnings	41			43			79			100
Total	$	(39,657	)	$	1,519		$	(38,756	)	$	2,751

Minority interest:
Equitable Supply	$	—		$	—		$	—		$	(871	)
NORESCO	(359		)	—			(729		)	—
Total	$	(359	)	$	—		$	(729	)	$	(871	)

Gain on exchange of Westport for Kerr-McGee shares	217,212			—			217,212			—
Charitable foundation contribution	(18,226		)	—			(18,226		)	(9,279		)
Westport equity earnings	—			—			—			3,614
Other income, net	3,600			—			3,600			—
Interest charges	11,503			10,782			23,762			23,103
Income tax expense	67,397			16,159			105,126			43,375
Income from continuing operations before cumulative effect of accounting change	130,827			31,395			200,897			95,874

Cumulative effect of accounting change, net of tax (c)	—			—			—			(3,556		)

Net income	$	130,827		$	31,395		$	200,897		$	92,318

	June 30, 2004		December 31, 2003
	(Thousands)
Segment Assets:
Equitable Utilities	$	1,009,247	$	1,120,708
Equitable Supply	1,435,453		1,338,702
NORESCO (d)	201,043		323,569
Total operating segments	2,645,743		2,782,979
Headquarters assets, including cash and short-term investments	289,200		156,913
Total	$	2,934,943	$	2,939,892

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
	(Thousands)
Expenditures for segment assets:
Equitable Utilities	$	14,970	$	14,708	$	29,570	$	23,376
Equitable Supply (e)	29,329		42,767		50,382		110,505
NORESCO	164		98		192		146
Unallocated expenditures	202		212		391		808
Total	$	44,665	$	57,785	$	80,535	$	134,835

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

(b) Equity losses in nonconsolidated investments for the three and six months ended June 30, 2004 include a $40.2 million impairment charge of NORESCO’s international investments. See Note M for further discussion.

(c) Net income for the six months ended June 30, 2003 has been adjusted to reflect the cumulative effect of accounting change related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” See Note K.

(d) The Company’s goodwill balance as of June 30, 2004 and December 31, 2003 totaled $51.7 million and is entirely related to the NORESCO segment.

(e) For the six months ended June 30, 2003, expenditures include $44.2 million for the acquisition of the remaining 31% limited partner interest in Appalachian Basin Partners, LP. See Note H.

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 has been surrendered in accordance with Statement No. 140, as the cash received by the Company can be called by the financial institution at any time until the Company’s ongoing involvement in the receivables concludes. The Company de-recognizes the receivables and the liabilities when control has been surrendered in accordance with the criteria provided in Statement No. 140. The Company does not retain any interests in or obligation with respect to the contract receivables once the sale is complete. As of June 30, 2004 the Company had recorded current liabilities of $60.3 million classified as current portion of project financing obligations and long-term liabilities of $47.9 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, or cash could be called, within one year. The related assets are classified as unbilled revenues while construction progresses and as other assets upon completion of construction.

For the three months ended June 30, 2004, approximately $17.2 million of the contract receivables met the criteria for sales treatment, generating a gain of $0.4 million. The de-recognition of the $17.2 million in receivables and the related liabilities is a non-cash transaction and is consequently not reflected in the Statements of Condensed Consolidated Cash Flows.

D. Derivative Commodity 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 Company’s Board of Directors and is comprised of the chief executive officer, the chief financial officer and other officers and employees of the Company.

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 contracts) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The Company’s risk management program also includes the use of interest rate swap agreements to hedge exposures to fluctuations in interest rates. Additionally, the Company’s risk management program also includes the use of variable share forward contracts to hedge cash flow exposure associated with the forecasted future disposal of Kerr-McGee shares by purchasing a put option and selling a counterparty a call option on the shares. 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. 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 reports all gains and losses on its energy trading contracts 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). The variable share forward contracts 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, perfect hedge effectiveness is assumed and the entire fair value of the collar is recorded in other comprehensive income.

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 $49.5 million asset and a $256.7 million liability as of June 30, 2004, and a $34.5 million asset and a $137.6 million liability as of December 31, 2003. These amounts are classified in the Condensed Consolidated Balance Sheets as derivative commodity instruments, at fair value. The decrease in the net amount of derivative commodity instruments, at fair value, from December 31, 2003 to June 30, 2004 is 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 422.8 Bcf and 347.2 Bcf as of June 30, 2004 and December 31, 2003, respectively, and primarily relate to natural gas swaps. The open swaps at June 30, 2004 have maturities extending through December 2011.

The Company deferred net losses of $127.3 million and $58.4 million in accumulated other comprehensive loss, net of tax, as of June 30, 2004 and December 31, 2003, 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 $58.5 million of unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of June 30, 2004 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions.

For the three months ended June 30, 2004 and 2003, ineffectiveness associated with the Company’s derivative commodity instruments designated as cash flow hedges decreased earnings by approximately $1.1 million and $1.7 million, respectively. 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.

At June 30, 2004, the absolute notional quantities of the futures and swaps held for trading purposes totaled 1.9 Bcf and 44.5 Bcf, respectively.

Below is a summary of the activity of the fair value of the Company’s derivative contracts with third parties held for trading purposes during the six months ended June 30, 2004 (in thousands).

Fair value of contracts outstanding as of December 31, 2003	$	173
Contracts realized or otherwise settled	(376		)
Other changes in fair value	255
Fair value of contracts outstanding as of June 30, 2004	$	52

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 June 30, 2004.

Net Fair Value of Third Party Contract 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)	$	13		$	—	$	—	$	—	$	13
Prices provided by other external sources (2)	(18		)	38		19		—		39
Net derivative assets	$	(5	)	$	38	$	19	$	—	$	52

(1) Contracts include futures and fixed price swaps

(2) Contracts include basis swaps

The overall portfolio of the Company’s energy derivatives 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 energy derivative 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 energy derivatives 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 hedged physical transactions, assuming the energy derivatives are not closed out in advance of their expected term, the energy derivatives continue to function effectively as hedges of the underlying risk, and, as applicable, anticipated transactions occur as expected.

E. Investments

As of June 30, 2004, the investments classified by the Company as available-for-sale include approximately $19.5 million of debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures and a $365.5 million investment in Kerr-McGee Corporation (Kerr-McGee). The Company owned approximately 7.4 million shares, or 4.9%, of Kerr-McGee as of June 30, 2004. On April 7, 2004, Westport announced a merger with Kerr-McGee. On June 25, 2004, Kerr-McGee and Westport completed the 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. The Company was a 17.0% shareholder in Westport at the time of the transaction. 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. The Company recorded its book basis in the Kerr-McGee shares at $49.82 per share, which includes a discount to the market price for trading restrictions on the securities. The discount is recorded as a reduction to the increase in the book basis of the Kerr-McGee shares and will be accreted into other comprehensive income over the restriction period, which is the period until the securities can be reasonably expected to qualify for sale. Additionally, as part of the merger, the Company recorded $10.0 million of transaction-related expenses,

including associated compensation accruals. These expenses are included in selling, general and administrative expenses in the Statements of Consolidated Income for both the three and six-month periods ended June 30, 2004. Additionally, the transaction-related expenses are included as unallocated expenses in deriving total operating income for segment reporting purposes. See Note B.

Subsequent to the completion of the merger, the Company sold 800,000 shares of Kerr-McGee. The sale resulted in the Company recognizing a gain of $3.0 million for both the three and six months ended June 30, 2004, which is recorded in other income, net, on the Statements of Consolidated Income. The Company recorded $42.8 million from the proceeds of the sale in accounts receivable on the Condensed Consolidated Balance Sheets as of June 30, 2004, as the cash was received subsequent to June 30, 2004. The Company utilizes the specific identification method to determine the cost of securities sold.

In connection with the merger transaction between Westport and Kerr-McGee in June of 2004, the Company entered into three variable share forward transactions related to an aggregate of 6.0 million Kerr-McGee shares. See subsequent event language at Note Q.

On June 30, 2004, the Company irrevocably committed 357,000 shares of Kerr-McGee to the same charitable foundation established in 2003, expecting to extend the foundation's life. The shares are expected to be transferred to the foundation in the third quarter of 2004 and resulted in the Company recording a charitable foundation contribution expense of $18.2 million for the three and six months ended June 30, 2004. Additionally, the Company recorded a liability for the fair value of the shares to be transferred, which is included in other current liabilities in the Condensed Consolidated Balance Sheets at June 30, 2004. The contribution of the shares will reduce the number of Kerr-McGee shares held by the Company to approximately 7.0 million. Contributions of significantly appreciated shares of stock constitutes a tax efficient use of the shares. As with a similar contribution in the first quarter of 2003, the Company sought to maximize this value and extend the estimated life of the charitable giving program.

On March 31, 2003, the Company donated 905,000 shares of Westport stock to a community giving foundation. The foundation was established by the Company and was projected to facilitate the Company’s charitable giving program for approximately 10 years. The contribution resulted in charitable contribution expense of $9.3 million with a corresponding one-time tax benefit of approximately $7.1 million.

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 income. As of December 31, 2003, 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 second quarter 2004.

F. Comprehensive (Loss) Income

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(Thousands)
Net income	$	130,827		$	31,395		$	200,897		$	92,318
Other comprehensive (loss) income:
Net change in cash flow hedges:
Natural gas (Note D)	(18,152		)	(71,778		)	(68,975		)	(96,838		)
Interest rate	70			30			10			73
Gain on exchange of Westport stock	(143,360		)	—			(143,360		)	—
Unrealized gain (loss) on investments, available-for-sale (Note E):
Westport (to date of merger)	20,277			(31,130		)	43,731			52,329
Kerr-McGee (from date of merger)	(1,890		)	—			(1,890		)	—
Other	(149		)	1,455			122			1,286
Total comprehensive (loss) income	$	(12,377	)	$	(70,028	)	$	30,535		$	49,168

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

	June 30, 2004			December 31, 2003
	(Thousands)
Net unrealized loss from hedging transactions	$	(128,621	)	$	(59,656	)
Unrealized (loss) gain on available-for-sale securities	(951		)	100,446
Minimum pension liability adjustment	(25,532		)	(25,532		)
Foreign currency translation adjustment	7			7
	$	(155,097	)	$	15,265

G. Stock-Based Compensation

Restricted stock grants in the aggregate amount of 138,000 shares were awarded to various employees during the first six months of 2004. The related expense recognized during the three and six month periods ended June 30, 2004 was $0.6 million and $0.9 million, respectively and is classified as selling, general and administrative expense.

No new stock options were awarded during the three and six month periods ended June 30, 2004. 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 historically not recognized any compensation cost for its stock option awards.

The Company has two Executive Performance Incentive Programs (the “Plans”) in place 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 thirty peer companies. The Company anticipates, based on current estimates, that a certain level of performance will be met. As a result of the Company’s share appreciation in the second quarter, the Company recognized an increase in the long-term incentive plan expense of $6.1 million associated with the Plans. The Company’s share price assumption used to determine the accrual is $53 per share at the end of 2004 and $56 per share at the end of 2005. These expenses are included in selling, general and administrative expenses in the Statements of Consolidated Income for both the three and six-month periods ended June 30, 2004. Additionally, 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 June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	(Thousands)
Net income, as reported	$	130,827		$	31,395		$	200,897		$	92,318
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	6,350			3,990			8,875			6,894
Deduct: Total stock-based employee compensation expense determined by the fair value method for all awards, net of related tax effects	(7,279		)	(5,676		)	(10,968		)	(10,404		)
Pro forma net income	$	129,898		$	29,709		$	198,804		$	88,808
Earnings per share:
Basic, as reported	$	2.11		$	0.51		$	3.23		$	1.49
Basic, pro forma	$	2.09		$	0.48		$	3.20		$	1.43

Diluted, as reported	$	2.06		$	0.50		$	3.17		$	1.46
Diluted, pro forma	$	2.05		$	0.47		$	3.13		$	1.40

H. Appalachian Basin Partners, LP

In February 2003, the Company purchased the remaining 31% limited partnership interest in Appalachian Basin Partners, LP (ABP) from the minority interest holders for $44.2 million. In February 2003, the 31% limited partnership interest represented approximately 60.2 Bcf of reserves. The ABP partnership was formed in November 1995 when the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit. The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target, which was met near the end of 2001. The Company consequently consolidated the partnership starting in 2002, and the remaining portion not owned by the Company was recorded as minority interest. As a result of the acquisition of the 31% interest, effective February 1, 2003, the Company no longer recognized minority interest expense associated with ABP, which totaled $0.9 million for the six months ended June 30, 2003.

I. 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 from continuing operations to be 34.4%.

J. Pension and Other Postretirement Benefit Plans

The Company has defined benefit pension and other postretirement benefit plans covering union 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. All other salaried 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 and six months ended June 30, 2004 and 2003 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
	2004			2003			2004			2003
	(Thousands)
Components of net periodic benefit cost
Service cost	$	398		$	671		$	121		$	78
Interest cost	1,743			1,889			818			867
Expected return on plan assets	(2,457		)	(2,165		)	—			—
Amortization of prior service cost	235			322			(10		)	(11		)
Recognized net actuarial loss	187			5			500			457
Settlement loss	490			552			—			—
Net periodic benefit cost	$	596		$	1,274		$	1,429		$	1,391

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
	2004			2003			2004			2003
	(Thousands)
Components of net periodic benefit cost
Service cost	$	795		$	1,342		$	242		$	156
Interest cost	3,485			3,777			1,637			1,734
Expected return on plan assets	(4,914		)	(4,330		)	—			—
Amortization of prior service cost	470			644			(21		)	(22		)
Recognized net actuarial loss	373			10			1,000			914
Settlement loss	966			1,104			—			—
Net periodic benefit cost	$	1,175		$	2,547		$	2,858		$	2,782

Consistent with the disclosure made in its Form 10-K for the fiscal year ended December 31, 2003, the Company expects that it will not make a contribution to its defined benefit plan in 2004.

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. Additionally, the Act introduced a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company sponsors retiree medical programs for certain of its locations and expects that this legislation will reduce the Company’s costs for some of these programs in the future.

In May 2004, the Financial Accounting Standards Board (FASB) issued Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2) which permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act. FSP FAS 106-2 superceded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” which was issued in January 2004. At the present time, the specific regulations that are necessary to specify how actuarial equivalency is to be determined under the Act have not been issued. The Company is awaiting guidance from various governmental and regulatory agencies concerning the requirements that must be met to obtain these cost reductions as well as the manner in which such savings should be measured. Based on the Company’s preliminary analysis, it appears that some of the Company’s retiree medical plans may need to be revised in order to qualify for beneficial treatment under the Act, while other plans may continue unchanged. The Company will continue to monitor the evolving regulations surrounding the Act and how those regulations may impact the medical plans in place.

Due to various uncertainties related to the Act and the appropriate accounting methodology for this event, the Company has elected to defer financial recognition with respect to the effects of the Act until further guidance is issued. When issued, that final guidance may require the Company to change previously reported information. In accordance with FSP FAS 106-2, measures of the accumulated postretirement benefit obligation or net periodic postretirement benefit cost in the condensed consolidated financial statements or accompanying notes do not reflect any amounts associated with the subsidy as the Company is unable to conclude whether the benefits provided by the plan are actuarially equivalent to Medicare Part D under the Act.

K. Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations” (Statement No. 143). Statement No. 143 was adopted by the Company effective January 1, 2003, and its primary impact was to change the method of accruing for well plugging and abandonment costs. These costs were formerly recognized as a component of depreciation, depletion and amortization expense with a corresponding credit to accumulated depletion in accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (Statement No. 19). At the end of 2002, the cumulative liability was approximately $20.9 million. Under Statement No. 143, the fair value of the asset retirement obligations are recorded as liabilities when they are incurred, which is typically at the time the wells are drilled. Amounts recorded for the related assets are increased by the amount of these obligations. Over time the liabilities are accreted for the change in their present value, through charges to operating expense, and the initial capitalized costs are depleted over the useful lives of the related assets.

The adoption of Statement No. 143 by the Company resulted in a one-time, net of tax, charge to earnings of $3.6 million, or $0.06 per diluted share, during the six months ended June 30, 2003, which is reflected as a cumulative effect of accounting change in the Company’s Statements of Consolidated Income. In addition to the one-time charge to earnings, the depletion rate in the Company’s Supply segment increased by $0.03 per Mcfe.

The Company also recognized a $28.7 million other long-term liability and a $2.3 million long-term asset upon adoption of Statement No. 143. The long-term obligation related to the estimated future expenditures required to plug and abandon the Company’s approximately 12,000 wells in Appalachia. These wells will incur plugging and abandonment costs over an extended period of time, significant portions of which costs are not projected to occur for over 40 years. Additionally, the Company does not have any assets that are legally restricted for purposes of settling the asset retirement obligation.

The following table presents a reconciliation of the beginning and ending carrying amounts of the asset retirement obligations:

	Three months ended June 30, 2004			Six months ended June 30, 2004
	(Thousands)
Asset retirement obligation as of beginning of period	$	30,007		$	29,780
Accretion expense	523			1,045
Liabilities incurred	59			92
Liabilities settled	(1,691		)	(2,019		)
Asset retirement obligation as of end of period	$	28,898		$	28,898

L. Recently Issued Accounting Standards

Consolidation of Variable Interest Entities

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (FIN No. 46). FIN No. 46 required certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity did not have the characteristics of a controlling financial interest or did not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Prior to FIN No. 46, an entity was generally consolidated by an enterprise when the enterprise had a controlling financial interest through ownership of a majority voting interest in the entity. FIN No. 46 was effective for all new variable interest entities created or acquired after January 31, 2003. The Company adopted FIN No. 46 for variable interest entities created or acquired prior to February 1, 2003 as of July 1, 2003. The adoption of FIN No. 46 required the consolidation of Plymouth Cogeneration Limited Partnership (Plymouth), a joint venture entered into by NORESCO, and the deconsolidation of EAL/ERI Cogeneration Partners LP (Jamaica), which is the partnership that holds the Jamaican power plant.

In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R) that modified some of the provisions of FIN No. 46 and provided exemptions to certain entities from the original guidance. The Company adopted FIN No. 46R in the first quarter of 2004. The adoption of FIN No. 46R required the Company to deconsolidate Plymouth as of January 1, 2004, due to certain modifications of the original FIN No. 46 provisions.

This deconsolidation returned Plymouth to the equity method of accounting for investments. The Company restored the equity investment in Plymouth of $0.1 million and decreased minority interest by $0.6 million in the Condensed Consolidated Balance Sheet. As of January 1, 2004, $4.9 million of assets and $4.9 million of liabilities, including nonrecourse debt of $4.0 million, were removed from the Condensed Consolidated Balance Sheet.

The Company also has a non-equity interest in a variable interest entity, Appalachian NPI, LLC (ANPI), in which Equitable was not deemed to be the primary beneficiary. As of June 30, 2004, ANPI had $272.2 million of total assets and $303.9 million of total liabilities (including $191.7 million of long-term debt, including current maturities), excluding minority interest. The Company’s maximum exposure to a loss as a result of its involvement with ANPI is estimated to be $29.0 million.

Employers’ Disclosures about Pensions and Other Postretirement Benefits

In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (Statement No. 132). This Statement revises employers’ disclosures about pension plans and other postretirement benefits. It retains the original disclosure requirements contained in SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. This Statement was effective for financial statements with fiscal years ending after December 15, 2003. Accordingly, the additional disclosures required by the revised Statement No. 132 were included in the Company’s 2003 Form 10-K. Interim period disclosures required by revised Statement No. 132 are effective for interim periods beginning after December 15, 2003 and have been included in Note J.

On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act expanded Medicare to include, for the first time, coverage for prescription drugs. In May 2004, the FASB issued Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP FAS 106-2), which permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Act. FSP FAS 106-2 superceded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” which was issued in January 2004. At the present time, the specific regulations that are necessary to specify how actuarial equivalency is to be determined under the Act have not been issued. The Company is awaiting guidance from various governmental and regulatory agencies concerning the requirements that must be met to obtain these cost reductions as well as the manner in which such savings should be measured. Based on the Company’s preliminary analysis, it appears that some of the Company’s retiree medical plans may need to be revised in order to qualify for beneficial treatment under the Act, while other plans may continue unchanged. The Company will continue to monitor the evolving regulations surrounding the Act and how those regulations will impact the medical plans in place. In accordance with FSP FAS 106-2, appropriate disclosures have been made in Note J.

Stock Compensation

On March 31, 2004, the FASB issued an exposure draft, “Share-Based Payment, an Amendment of FASB Statements No. 123 and 95.” The proposed change in accounting would replace existing requirements under SFAS 123, “Accounting for Stock-Based Compensation,” and APB Opinion No. 25, “Accounting for Stock Issued to Employees.” The exposure draft covers a wide range of equity-based compensation arrangements. Under the FASB’s proposal, all forms of share-based payments to employees, including employee stock options, would be treated the same as other forms of compensation by recognizing the related cost in the income statement. The expense of the award would generally be measured at fair value at the grant date. The comment period for the exposure draft ended on June 30, 2004 and final rules are expected to be issued in late 2004. The standard would be applicable for fiscal years beginning after December 15, 2004. The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final rules are issued.

Asset Retirement Obligations

On June 17, 2004, the FASB issued an exposure draft, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” The proposed interpretation would clarify that a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A recording of the liability at fair value would be recognized for a conditional asset retirement obligation when the liability is incurred. Certain factors regarding the timing and method of the settlement, which are conditional upon the future events occurring, would be factored into the measurement of the liability rather than the recognition of the liability. The final rules are expected to be issued in late 2004 and are anticipated to be effective no later than the end of the fiscal year ending after December 15, 2005. The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final rules are issued.

M. International Investments

Certain NORESCO projects are held through equity in nonconsolidated entities that operate private power generation facilities located in select international countries. During the second quarter of 2004, several negative circumstances caused the Company to evaluate 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 ICG/ERI Pan Am Thermal Generating Limited (Pan Am), a Panamanian electric generation project. As a result of these market events, 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 represents the full value of NORESCO’s equity investment in the project.

value of the investment, the Company recorded an impairment charge of $2.8 million in the second quarter of 2004 to write down the investment to its fair value less costs to sell. Following the impairment, the investment in Dona Julia is considered held for sale. The investment is included in the equity in nonconsolidated investments on the Condensed Consolidated Balance Sheet and the Company expects to sell the investment within one year.

Additional impairment-related charges of $15.3 million were also recorded in the second quarter of 2004 for total impairment charges of $40.2 million for the quarter. The additional charges relate 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 a 50% owned non-recourse financed energy project known as Pan Am. The entire impairment charge has been included as impairment on nonconsolidated investments on the Statements of Consolidated Income. The Company is actively evaluating alternatives for the sale and disposal of its international assets.

After an extended period of troubled operations, ERI JAM, LLC, a subsidiary that holds the Company’s interest in EAL/ERI Cogeneration Partners LP, an international infrastructure project, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. In the third quarter 2003, ERI JAM, LLC transferred control of the international infrastructure project under the partnership agreement to the other general partner. The international infrastructure project was deconsolidated in accordance with FIN No. 46. In September 2003, project-level counterparties, Jamaica Broilers Group Limited (JBG) and Energy Associated Limited (EAL), filed a claim against ERI JAM LLC as Debtor-in-Possession in the Chapter 11 case. EAL is a limited partner in EAL/ERI Cogeneration Partners LP. In October 2003, JBG and EAL also filed a multi-count complaint against Equitable and certain of its affiliates in U.S. District Court (Western District of PA). Equitable and its affiliates believe they have meritorious defenses to all claims asserted in the litigation by JBG and EAL and intend to vigorously defend this litigation, which they view as without merit. A mediation held in April 2004 did not resolve the litigation, which is in discovery.

N. Prepaid Forward Contract

In 2000, the Company entered into two prepaid natural gas sales contracts pursuant to which the Company was required to sell and deliver 52.7 Bcf of natural gas during the term of the contracts. The first contract was for five years with net proceeds of $104.0 million. The second contract was for three years with net proceeds of $104.8 million and was completed at the end of 2003. These contracts were recorded as prepaid forward sales and are recognized in income as deliveries occur.

In June 2004, the Company continued to evaluate its capital structure as a result of the anticipated increase in liquidity, expected as a result of the Westport/Kerr-McGee merger. Based on this evaluation, the Company amended the remaining prepaid natural gas contract, which has been viewed as debt by the rating agencies. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. The Company’s obligation to deliver a fixed quantity of gas at a fixed price has not changed but the amendment has the effect of increasing the realized sales price for the delivery of gas for the remaining term of the contract. As such, the Company repaid the counterparty $36.8 million, removed the prepaid forward sale from the balance sheet and recorded a loss of $5.5 million in other income in the Statements of Consolidated Income reflecting the difference between the net present value of the underlying quantities and the remaining unamortized balance recorded as deferred revenue. On a going forward basis, through the term of the remaining contract (December 2005), the Company will deliver the required quantity of gas at an effective price of $4.79 per Mcf rather than $3.99 per Mcf. Income will continue to be recognized upon delivery of the gas.

O. Insurance Settlement

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

P. Reclassification

Certain previously reported amounts have been reclassified to conform to the 2004 presentation. These reclassifications did not affect reported net income or cash flows.

Q. Subsequent Events

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 funding up to the 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 shares of Kerr-McGee 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, the 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 60% of the next Kerr-McGee dividend.

These variable share forward transactions limit the Company’s downside exposure with respect to the underlying Kerr-McGee shares while allowing the Company to maintain significant potential upside. The bidding process for each transaction was structured to allow the Company to maximize the pricing of the collars while diversifying counterparty credit exposure. At August 6, 2004, the Company owns approximately 7.0 million shares that are not committed to the charitable foundation. Approximately 1.0 million of these Kerr-McGee shares remain unhedged.

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.

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. Statements that do not relate strictly to historical or current facts are forward-looking and can usually be identified by the use of words such as “should,” “anticipate,” “estimate,” “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, such statements specifically include the expected amount, timing, and the source of payment for the Company’s plugging and abandonment obligations; the description of the Company’s hedging strategy and the effectiveness of that strategy, including the impact on earnings of a change in NYMEX; the adequacy of the Company’s borrowing capacity to meet the Company’s liquidity requirements; the amount of unrealized losses on the Company’s derivative commodity instruments that will be recognized in earnings; the amount and timing of the expected increase in depletion rates; the expected impact of new accounting pronouncements; the resolution of issues surrounding implementation of the Company’s new customer information and billing system and the related costs; the ability of the Company to divest its international projects on an accelerated schedule; the adequacy of legal reserves and therefore the belief that the ultimate outcome of any matter currently pending will not materially affect the financial position of the Company; the amount and timing of Company’s pension plan funding obligations; the amount of or increase in future dividends; the ultimate outcome of rate cases, regulatory reviews and other regulatory action, including the amounts that the Company expects to recover or incur as a consequence of such events; the dividend pass-through for the Company’s hedges of its investment in Kerr-McGee Corporation; the amount of the cost to implement the Environmental Protection Agency rules regarding Spill Prevention, Control and Countermeasures; the Company’s ultimate funding obligation with respect to its two Executive Incentive Performance Programs; the timing and amount of expenses to be incurred as a consequence of the Company’s relocation to new office space and of the increased efficiencies resulting from the relocation; the Company’s estimated annual effective income tax rate for 2004; the expectation that the passage of the Medicare Prescription, Drug, Improvement and Modernization Act of 2003 will reduce certain of the Company’s medical costs; the possibility of the passage of enabling legislation for performance contracting; the improvements which may result from operational changes in the Supply segment and other forward looking statements relating to financial results, cost savings and operational matters.

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 including changes in the hedge portfolio, availability and cost of financing, changes in interest rates, the needs of the Company with respect to liquidity, implementation and execution of operational enhancement and cost restructuring initiatives, curtailments or disruptions in production, 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, the ability to satisfy project finance lenders and other factors discussed in other reports (including Form 10-K) 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 update any forward-looking statement, 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 our subsidiaries) is at times referred to as “the Company”.

Equitable Resources’ consolidated income from continuing operations for the quarter ended June 30, 2004 totaled $130.8 million, or $2.06 per diluted share, compared to $31.4 million, or $0.50 per diluted share, reported for the same period a year ago. Operating income decreased to $47.2 million at June 30, 2004 from $56.8 million at June 30, 2003. The decrease was the result of Westport/Kerr-McGee transaction related expenses, including associated compensation accruals and increased costs related to the Company’s Executive Performance Incentive Programs, somewhat offset by higher realized sales prices. The second quarter 2004 earnings from continuing operations increased from 2003 due to the gain recorded as a result of the Westport/Kerr-McGee merger, the gain recorded on the subsequent sale of 800,000 shares of Kerr-McGee and proceeds received from an insurance settlement. Offsetting these gains were impairment charges related to the Company’s international investments, the charitable foundation contribution expense, and an amendment of the Company’s prepaid forward contract.

Equitable Resources’ consolidated income from continuing operations before cumulative effect of accounting change for the six months ended June 30, 2004 totaled $200.9 million, or $3.17 per diluted share, compared to $95.9 million, or $1.52 per diluted

share, reported for the same period a year ago. The increase of $105.0 million is primarily the result of the factors addressed above.

RESULTS OF OPERATIONS

EQUITABLE UTILITIES

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003

OPERATIONAL DATA

Total operating expenses as a % of net operating revenues	75.36		%	71.19		%	51.65		%	49.25		%

Capital expenditures (thousands)	$	14,970		$	14,708		$	29,570		$	23,376

FINANCIAL RESULTS (Thousands)

Utility revenues (regulated)	$	68,944		$	62,485		$	264,633		$	246,810
Marketing revenues	69,633			53,135			155,318			104,919
Total operating revenues	138,577			115,620			419,951			351,729

Utility purchased gas costs (regulated)	28,267			22,773			140,635			119,992
Marketing purchased gas costs	65,499			48,668			140,739			90,339
Net operating revenues	44,811			44,179			138,577			141,398

Operating expenses:
Operating and maintenance expense	12,289			12,722			24,406			25,825
Selling, general and administrative expense	14,058			11,940			32,421			30,294
Depreciation, depletion and amortization	7,424			6,789			14,750			13,524
Total operating expenses	33,771			31,451			71,577			69,643

Operating income	$	11,040		$	12,728		$	67,000		$	71,755

Three Months Ended June 30, 2004
vs. Three Months Ended June 30, 2003

Net operating revenues for the three months ended June 30, 2004 of $44.8 million remained relatively unchanged from the net operating revenues of $44.2 million for the same quarter in 2003. Total operating expenses increased by $2.3 million due almost entirely to increased provisions for doubtful accounts at the Distribution segment.

Six Months Ended June 30, 2004
vs. Six Months Ended June 30, 2003

Net operating revenues decreased by $2.8 million in 2004 compared to the six months ended June 30, 2003. The decrease in net operating revenues is a result of 6% warmer weather in 2004 as compared to the same period in 2003. Total operating expenses increased $2.0 million from $69.6 million to $71.6 million due to $1.8 million of increased insurance and legal costs combined with increased operating costs of $1.0 million related to the implementation of the Distribution’s customer information system discussed below. These increases were partially offset by on-going cost reduction initiatives

Distribution Operations

Rates and Regulatory Matters

Equitable Utilities’ distribution operations are carried out by Equitable Gas Company (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. The distribution operations provide natural gas services to approximately 275,100 customers, comprising 256,000 residential customers and 19,100 commercial and industrial customers. Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky.

A PA PUC mandated asset service life study was filed with the PA PUC by Equitable Gas in May 2004. This study will change the estimated useful lives for Equitable Gas’ main lines and service lines as a result of installing plastic pipe. If the revised useful lives are approved retroactively to January 1, 2004, as requested by Equitable Gas, then it will result in a decrease of depreciation expense of approximately $3.0 million in 2004. The study is expected to be approved in the fourth quarter of 2004.

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 to improve participants’ ability to pay their bills. In October 2003, the PA PUC approved Equitable Gas’ revised programs and instructed the various stakeholders to ascertain if additional funding was necessary to implement the revised programs. Initially the stakeholders argued that the full cost of the programs was already being collected by Equitable Gas in its base rates and through various surcharges. Ultimately, consensus was reached to allow the Company to collect an additional $.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. This funding mechanism is not expected to have a significant impact on 2004 results given that it was approved at the end of the highest volume quarter and during the remainder of 2004 the Company plans to increase spending and focus its collection efforts internally on improving analytical resources and reducing outstanding balances. In the future, it is expected that this mechanism will become a key component in the Company’s efforts to reduce bad debt expense.

Equitable Gas has been working 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 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. During the third quarter 2002, the PA PUC approved a one-year extension of this program through September 2004. In that same order, the PA PUC approved a second performance-based initiative related to balancing services. This initiative runs through 2005. During the second quarter of 2003, Equitable Gas reached a settlement with all parties to extend its performance-based purchased gas cost credit incentive through September 2005. The settlement also included a new performance-based incentive, which allows Equitable to retain 25% of any revenue generated from a new service designed to increase the recovery of capacity costs from transportation customers. A PA PUC Order approving the settlement was issued in September 2003.

Equitable Gas submits quarterly purchased gas cost filings with the PA PUC that are subject to quarterly reviews and annual audits by the PA PUC. The PA PUC Bureau of Audits’ most recent annual purchased gas-cost audit for the 2000-2001 purchased gas period concluded in the fourth quarter of 2003. A final audit report for the 2000-2001 period was received in the first quarter of 2004. No adverse audit findings were included in the report. The Company’s purchased gas costs for 2002-2003 are currently unaudited by the PA PUC Bureau of Audits, but have received a final prudency review by the PA PUC through 2002 in which no material issues have been noted.

Other

In the first quarter of 2004, Equitable Gas implemented a new customer information and billing system for which it incurred $13.1 million of capital expenditures from project inception through June 30, 2004. The system is being depreciated over a fifteen-year period. The new system will help the Company better segment customer information, thereby making it easier for the Company to identify customers eligible for the energy assistance programs and customers for which additional collection efforts are necessary. The Company has incurred additional costs of $1.0 million through June 30, 2004 and expects to incur additional costs.

Equitable Gas’ contract with the members of the local United Steelworkers union representing 208 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 June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
OPERATIONAL DATA

Heating Degree days (30 year normal average: Qtr - 705 YTD - 3,635 (a)	520		554		3,445		3,669

O&M per customer (b)	$	73.7	$	65.6	$	159.0	$	156.9

Volumes (MMcf)
Residential sales and transportation	3,716		3,467		16,796		17,632
Commercial and industrial	6,089		4,965		17,755		16,555
Total throughput	9,805		8,432		34,551		34,187

FINANCIAL RESULTS (Thousands)

Net operating revenues:
Residential net operating revenues	$	18,404	$	18,318	$	63,370	$	66,464
Commercial and industrial net operating revenues	9,443		9,347		30,216		30,828
Other net operating revenues	1,721		911		3,285		2,477
Total net operating revenues	29,568		28,576		96,871		99,769

Operating expenses (total operating expenses excluding depreciation)	20,979		18,531		45,045		43,959
Depreciation, depletion and amortization	5,415		4,926		10,733		9,876

Operating income	$	3,174	$	5,119	$	41,093	$	45,934

(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 day 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) less other taxes. Other taxes for the three months ended June 30, 2004 and 2003 totaled $0.7 million and $0.7 million, respectively. Other taxes for the six months ended June 30, 2004 and 2003 totaled $1.3 million and $1.4 million, respectively. As of June 30, 2004 and 2003, Equitable Gas had approximately 275,100 customers and 271,300 customers, respectively.

Three Months Ended June 30, 2004
vs. Three Months Ended June 30, 2003

The 3% increase in net operating revenues for the three months ended June 30, 2004 was due primarily to a favorable settlement of a customer dispute for which a reserve was previously established. Additionally, in the first quarter 2004, Pipeline operations transferred gathering assets to the Distribution operations. These assets provided $0.3 million of increased operating revenues in the second quarter of 2004. Although there was a 16% increase in throughput in the second quarter of 2004, this increase was associated with large commercial and industrial process

load customers with relatively low margins. As a result, this increased throughput did not significantly impact net operating revenues.

Total operating expenses increased $2.9 million due to increased bad debt expense of $2.0 million combined with increased operating costs related to the implementation of the customer information system of $0.7 million. Additionally, depreciation, depletion and amortization (DD&A) expenses have increased $0.5 million, of which approximately $0.2 million is related to the implementation of the customer information system. Bad debt expense increased primarily as a result of delays in customer terminations related to difficulties with the implementation of the new customer information system. Typically, a key tool in recovering delinquent customer receivables is the threat of termination of service. These terminations are only allowed in the Company’s market area once the winter months have ended. However, as a result of these delays, the Company was less aggressive on customer terminations than is typical, and as a result, delinquent customer receivables increased. As a result of the increased delinquent receivables, the Company increased the provision for doubtful accounts in the second quarter by $2.0 million. These increases in bad debt expense, in system implementation costs and in DDA expense were partially offset by on-going cost reduction initiatives.

Six Months Ended June 30, 2004
vs. Six Months Ended June 30, 2003

Weather in the distribution service territory for the six months ended June 30, 2004, was 5% warmer than the thirty year normal average and 6% warmer than last year, primarily associated with warmer temperatures in the first quarter 2004. Residential volumes decreased 5% from prior year, while commercial and industrial volumes increased 7% compared to 2003. The majority of the increase in commercial and industrial volumes relates to low margin, high volume customers.

Net operating revenues for the six months ended June 30, 2004, decreased to $96.9 million from $99.8 million, or 3% from the same period last year. The majority of the decrease is attributable to warmer weather in 2004 versus 2003. This decrease was partially offset by $0.6 million of gathering revenue related to assets transferred from the Pipeline operations during first quarter 2004.

Total operating expenses of $55.8 million for the six months ended June 30, 2004 increased $2.0 million compared to $53.8 million for the same period in 2003. The increase in operating expenses was due to $1.6 million of increased insurance and legal costs combined with increased operating costs of $1.0 million related to the implementation of the Distribution’s customer information system. Additionally, DD&A expenses have increased $0.9 million, of which approximately $0.3 million is related to the implementation of the customer information system. Bad debt expense for the six months ended June 30, 2004 remained relatively unchanged from the same period in 2003 as increased bad debt expense of $7.7 million was offset by a reduction of a regulatory asset reserve for $7.3 million. These increases were partially offset by on-going cost reduction initiatives.

Pipeline Operations

Interstate Pipeline

The interstate pipeline operations of Equitrans and Carnegie Pipeline are subject to rate regulation by the Federal Energy Regulatory Commission (FERC). In 1997, Equitrans filed a general change application (rate case). The rate case was resolved through a FERC approved settlement among all parties. The settlement provided, with certain limited exceptions, that Equitrans not file a general rate increase with an effective date before August 1, 2001, and must file a general rate case application to take effect no later than August 1, 2003. In the second quarter 2002, Equitrans filed with the FERC to merge its assets and operations with the assets and operations of Carnegie Pipeline. In April 2003, Equitrans filed a proposed settlement with the FERC related to the application to merge its assets with the assets of the former Carnegie Pipeline operations. The settlement also provided for a deferral to April 2005 of the August 1, 2003 rate case filing requirement. This proposed settlement was broadly supported by most parties. On July 1, 2003, Equitrans received an order from the FERC approving the merger of Equitrans and Carnegie Pipeline but denying the request for deferral of the requirement to file a rate case by August 1, 2003. In response to the July 1, 2003 order Equitrans filed for and received an extension of time for its rate case filing deadline from August 1, 2003 until December 1, 2003. Also in response to the July 1, 2003 order, on January 1, 2004, the merger of Equitrans and Carnegie Pipeline was effectuated with Equitrans surviving the merger.

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 have been 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 Carnegie Pipeline. 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.

In the interest of avoiding unnecessary delay, Equitrans re-filed its rate case application on March 1, 2004, complete with cost and revenue data for the former Carnegie Pipeline Operations. Consistent with the Company’s original December 1, 2003 filing, Equitrans’ rate case application addresses 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 is for an 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 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 June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
OPERATIONAL DATA

Transportation throughput (BBtu)	19,673		16,387		38,634		36,815

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	11,109	$	11,136	$	27,127	$	27,049
Operating expenses (Total operating expenses excluding depreciation)	5,482		5,755		10,880		11,428
Depreciation, depletion and amortization	1,967		1,792		3,932		3,499
Operating income	$	3,660	$	3,589	$	12,315	$	12,122

Three Months Ended June 30, 2004
vs. Three Months Ended June 30, 2003

Total transportation throughput increased 3,286 BBtu, or 20%, over the prior year quarter due to increased throughput from the Distribution operations, subsequently placed into storage, combined with increased firm transportation volumes related to a single third party customer. Because the margin from these firm transportation contracts is generally derived from fixed monthly fees, regardless of the volumes transported, the increased throughput did not positively impact net revenues.

Net revenues for the three months ended June 30, 2004 and 2003 remained relatively unchanged at $11.1 million. Gathering revenues increased $0.4 million due to a rate increase in 2004 compared to 2003. This increase was offset by a $0.3 million decrease related to the transfer of gathering assets to the Distribution operations in the first quarter 2004.

Operating expenses decreased from $7.5 million in 2003 to $7.4 million in 2004 as a result of on-going cost reduction initiatives offset by increased DD&A.

Six Months Ended June 30, 2004
vs. Six Months Ended June 30, 2003

Total transportation throughput increased 1,819 BBtu, or 5%, over the prior year due to increased throughput from the Distribution operations, subsequently placed into storage during the second quarter, offset by decreased throughput during the first quarter 2004 as a result of warmer weather. Additionally, volumes increased in 2004 compared to 2003 due to increased firm transportation to a single third party customer. Because the margin from these firm transportation contracts is generally derived from fixed monthly fees, regardless of the volumes transported, the increased throughput did not positively impact net revenues.

Net operating revenues for the six months ended June 30, 2004, were $27.1 million compared to $27.0 million for the same period in 2003. Gathering revenues increased $1.0 million due to a rate increase in 2004 compared to 2003. This increase was offset by a $0.6 million decrease related to the transfer of gathering assets to the Distribution operations in the first quarter 2004. The increase was also offset by lost storage revenue opportunities resulting from higher gas prices.

Operating expenses decreased by $0.1 million to $14.8 million. The decrease in operating costs is primarily a result of on-going cost reduction initiatives offset by increased DD&A.

Energy Marketing

	Three Months Ended June 30,					Six Months Ended June 30,
	2004			2003		2004		2003

OPERATIONAL DATA

Total throughput (BBtu)	8,403			5,900		30,337		20,057

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	4,134		$	4,467	$	14,579	$	14,580
Operating expenses	(114		)	376		902		732
Depreciation, depletion and amortization	42			71		85		149
Operating income	$	4,206		$	4,020	$	13,592	$	13,699

Three Months Ended June 30, 2004
vs. Three Months Ended June 30, 2003

Net operating revenues in the second quarter of 2004 decreased $0.3 million, or 7%, to $4.1 million from the prior year quarter. This decline is due primarily to lower storage revenues and reduced sales of excess capacity. The volume increase of 42% over the prior year quarter was driven mostly by higher commercial and industrial volumes, as well as increased volumes for resale off the Equitable Utilities’ systems.

Operating expenses, excluding DD&A, decreased $0.5 million from the second quarter of 2003. This reduction is the result of a $0.5 million reserve adjustment due to a favorable outcome of the associated legal reserve.

Six Months Ended June 30, 2004
vs. Six Months Ended June 30, 2003

Net operating revenues for the six months ended June 30, 2004 remained consistent with the prior year at $14.6 million. Although volumes increased approximately 51% compared to last year, the majority of these volumes related to sales for resale off the Equitable Utilities’ systems, which were transacted at relatively low margins.

Operating expenses of $0.9 million, excluding DD&A, for the six months ended June 30, 2004 increased $0.2 million from $0.7 million for the same period in 2003. This variance is due to the recovery of a bankrupt customer’s balance in first quarter 2003 of approximately $1.0 million, offset by cost savings from the Company’s continued initiative to reduce low-margin marketing activities.

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 of natural gas liquids.

Purchase and Sale of Gas Properties

In February 2003, the Company purchased the remaining 31% limited partnership interest in Appalachian Basin Partners, LP (ABP) from the minority interest holders for $44.2 million. This amount was included in the total capital spending of the first quarter of 2003. Effective February 1, 2003, the Company no longer recognized minority interest expense associated with ABP, which totaled $0.9 million for the six months ended June 30, 2003. The 31% limited partner interest represents approximately 60.2 Bcf of reserves.

In February 2003, the Company sold approximately 500 of its low-producing wells, within two of its non-strategic districts, in two separate transactions. The sales resulted in a decrease of approximately 13 Bcf of net reserves for proceeds of approximately $6.6 million. The wells produced an aggregate of approximately 0.2 Bcf during the first quarter of 2003. The Company did not recognize a gain or a loss as a result of this disposition.

Other

In the first quarter of 2004, Equitable Supply implemented a significant change to its business model. Previously, Equitable Supply followed the typical model for an Appalachian Basin exploration and production company, which suggests that growth occurs from drilling and then subsequently tending to the base wells and supporting the infrastructure in the most inexpensive possible manner. The current strategy employed by Equitable Supply is to continue to drill wells, but to spend more time and resources to aggressively tend to the improvement of the base infrastructure. In the second quarter of 2004, the Company lowered the expected number of wells to be drilled in 2004 from 340 to 320, consistent with the increased focus on infrastructure this year. This change is intended to accelerate sales from existing wells and reduce the Company’s long-term requirement for maintenance capital with respect to these wells. 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.

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
OPERATIONAL DATA
Total sales volumes (MMcfe)	16,798		15,563		33,840		31,080
Capital expenditures (thousands) (a)	$	29,329	$	42,767	$	50,382	$	110,505

FINANCIAL DATA (Thousands)

Production revenues	$	74,586	$	62,292	$	154,015	$	126,971
Gathering revenues	17,923		17,093		37,738		34,111
Total operating revenues	92,509		79,385		191,753		161,082

Operating expenses:
Lease operating expense, excluding severance taxes	7,356		5,125		13,441		10,400
Severance tax	4,033		3,499		8,035		7,386
Gathering and compression (operation and maintenance)	7,982		5,879		14,569		11,631
Selling, general and administrative (SG&A)	6,623		7,096		13,620		13,884
Depreciation, depletion and amortization	13,789		12,019		27,832		23,601
Total operating expenses	39,783		33,618		77,497		66,902

Operating income	$	52,726	$	45,767	$	114,256	$	94,180

Other income, net	$	576	$	—	$	576	$	—
Equity earnings from nonconsolidated investments	$	137	$	24	$	280	$	262
Minority interest	$	—	$	—	$	—	$	(871	)

(a) Capital expenditures for the six months ended June 30, 2003 include the purchase of the remaining 31% limited partnership interest in ABP ($44.2 million) which was separately approved by the Board of Directors of the Company in addition to the total amount originally authorized for the 2003 capital budget program.

Three Months Ended June 30, 2004
vs. Three Months Ended June, 2003

Equitable Supply’s operating income for the 2004 second quarter totaled $52.7 million, 15% higher than the $45.8 million earned in the same period last year. Total net operating revenues were $92.5 million, $13.1 million higher than the 2003 second quarter total net operating revenues of $79.4 million. Production revenues increased $12.3 million quarter over quarter to $74.6 million in 2004 from $62.3 million in 2003. The revenue increase was a result of both a sales volume increase of 1.2 Bcf and an average well-head sales price increase of $0.45 per Mcfe. Gathering revenues were $0.8 million higher at $17.9 million, compared with $17.1 million in 2003.

Total operating expenses for the 2004 second quarter were $39.8 million compared to $33.6 million in the 2003 second quarter. The increase in total operating expenses was due to increases of $2.2 million in lease operating expense, $2.1 million in gathering and compression expense and $1.8 million in DD&A expense.

Other income, net increased quarter over quarter to $0.6 million in 2004. This increase was a result of a $6.1 million settlement of a disputed insurance coverage claim, offset by a $5.5 million expense related to the Company’s amendment of its prepaid forward contract in the second quarter of 2004. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract and eliminated the related deferred revenues. The deferred revenues were viewed by many as the equivalent of debt. On a going forward basis, the Company will deliver the required quantities of gas at an effective price of $4.79 per Mcf, rather than $3.99 per Mcf.

Capital expenditures for the 2004 second quarter were $29.3 million compared to $42.8 million in the 2003 second quarter. This decrease is primarily the result of a decrease in drilling costs in the 2004 second quarter consistent with Equitable Supply’s increase in focus on infrastructure in 2004.

Six Months Ended June 30, 2004
vs. Six Months Ended June 30, 2003

Equitable Supply’s operating income for the six months ended June 30, 2004 was $114.3 million, 21% higher than the $94.2 million earned for the six months ended June 30, 2003. The segment’s results were favorably impacted by higher realized wellhead sales prices, increased natural gas sales volume and increased gathering revenues, somewhat offset by increased operating expenses.

Total operating revenues for the six months ended June 30, 2004, increased 19% to $191.8 million compared to $161.1 million in 2003, which was primarily attributable to a higher effective price and an increase in sales volumes and gathering revenues. Equitable Supply’s weighted average well-head sales price realized on produced volumes for the six months ended June 30, 2004 was $4.39 per Mcfe compared to $3.91 per Mcfe for the same period last year. The $0.48 per Mcfe increase in the weighted average well-head sales price is attributable to higher hedged prices and the satisfaction of a prepaid contract at the end of 2003.

Total operating expenses were $77.5 million for the six months ended June 30, 2004, compared to $66.9 million for the six months ended June 30, 2003. This increase was primarily due to increased DD&A costs ($4.2 million), increased lease operating expenses ($3.0 million), and increased gathering and compression expenses ($2.9 million).

The increase in other income to $0.6 million was the result of a $6.1 million settlement of a disputed property insurance coverage claim, offset by a $5.5 million expense related to the Company’s amendment of its prepaid forward contract, as discussed previously.

Equitable Production

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004			2003
OPERATIONAL DATA
Total sales volumes (MMcfe)	16,798		15,563		33,840			31,080
Average (well-head) sales price ($/Mcfe)	$	4.28	$	3.83	$	4.39		$	3.91

Company usage, line loss (MMcfe)	1,036		1,488		2,235			2,545

Natural gas inventory usage, net (MMcfe)	41		—		(71		)	—

Natural gas and oil production (MMcfe) (a)	17,875		17,051		36,004			33,625

Operated volumes – third parties (MMcfe) (b)	5,526		5,594		10,881			11,376

Lease operating expense (LOE), excluding severance tax ($/Mcfe)	$	0.41	$	0.30	$	0.37		$	0.31
Severance tax ($/Mcfe)	$	0.23	$	0.21	$	0.22		$	0.22
Production depletion ($/Mcfe)	$	0.54	$	0.49	$	0.54		$	0.48

Depreciation, depletion and amortization (in thousands):
Production depletion	$	9,619	$	8,346	$	19,441		$	16,301
Other depreciation, depletion and amortization	604		495		1,178			970
Total depreciation, depletion and amortization	$	10,223	$	8,841	$	20,619		$	17,271

(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 usage, net.

(b) Includes volumes in which interests were sold but which the Company still operates for third parties for a fee.

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003

FINANCIAL DATA (Thousands)

Production revenues	$	71,847	$	59,636	$	148,495	$	121,538
Other revenues	2,739		2,656		5,520		5,433
Total production revenues	74,586		62,292		154,015		126,971

Operating expenses:
Lease operating expense, excluding severance taxes	7,356		5,125		13,441		10,400
Severance tax	4,033		3,499		8,035		7,386
Selling, general and administrative	4,371		4,683		8,989		9,163
Depreciation, depletion and amortization	10,223		8,841		20,619		17,271
Total operating expenses	25,983		22,148		51,084		44,220

Operating income	$	48,603	$	40,144	$	102,931	$	82,751

Other income	$	576	$	—	$	576	$	—
Equity in earnings of nonconsolidated investments	$	137	$	24	$	280	$	262
Minority interest	$	—	$	—	$	—	$	(871	)

Three Months Ended June 30, 2004
vs. Three Months Ended June 30, 2003

Equitable Production’s revenues, which are derived primarily from the sale of produced natural gas, increased $12.3 million from the second quarter of 2003 to the second quarter of 2004. The increase is primarily the result of a higher average well-head sales price of $4.28 per Mcfe compared to $3.83 per Mcfe in the prior year ($7.0 million) and a 1.2 Bcf increase in sales volume ($5.3 million). The increase in sales volumes is the result of new wells drilled in 2003 and 2004 and improved pipeline system management, partially offset by the natural production decline in the Company’s wells.

Total operating expenses increased $3.8 million, or 17%, over the prior year from $22.2 million to $26.0 million. This increase was primarily due to increased lease operating expenses ($2.2 million), increased DD&A ($1.4 million) and increased severance tax ($0.5 million), offset by a slight decline in selling, general and administrative expense ($0.3 million). The increase in lease operating expenses is primarily the result of a charge to earnings for environmental site assessments to be performed in accordance with the Company’s amended Spill Prevention, Control and Countermeasure (SPCC) compliance plan ($1.0 million), an increase in field labor due to Equitable Production’s strategic decision to spend more time and resources aggressively tending wells and improving base infrastructure ($0.5 million) and an increase in property taxes and liability insurance premiums ($0.5 million). The increase in DD&A was due to a $0.05 per Mcfe increase in the unit depletion rate ($0.9 million) and increased production volumes and other depreciation ($0.5 million). The $0.05 per Mcfe increase in the unit depletion rate is primarily the result of the net development capital additions in 2003 on a relatively consistent proved reserve base. Given Equitable Production’s projected capital program and the fact that the total proved reserve base is expected to remain consistent, with reserve additions being offset by production, the Company expects the per unit depletion expense to increase by approximately $0.05 per Mcfe each year. The increase in severance tax is primarily attributable to an increase in the average gas price and an increase in sales volumes.

Six Months Ended June 30, 2004
vs. Six Months Ended June 30, 2003

Equitable Production’s revenues for the six months ended June 30, 2004 were $154.0 million, a 21% increase over the prior year’s six months revenues of $127.0 million. The increase is primarily the result of a higher average well-head sales price of $4.39 per Mcfe compared to $3.91 per Mcfe in the prior year ($14.9 million) and a 2.8 Bcf increase in sales volume ($12.1 million).

Total operating expenses increased $6.9 million over the prior year quarter from $44.2 million to $51.1 million. The increase is a result of higher DD&A costs ($3.3 million), increased lease operating expenses ($3.0 million), and higher severance taxes ($0.6 million), offset by slightly lower SG&A costs ($0.2 million). The increase in DD&A costs are due to an increase in the unit depletion rate and increased production volumes. The increase in lease operating expense is due to environmental costs associated with SPCC compliance, increases in field labor and increases in property taxes, liability insurance premiums and road maintenance costs.

Equitable Gathering

Operational and Financial Data

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
OPERATIONAL DATA
Gathered volumes (MMcfe)	31,305		29,177		63,873		61,729
Average gathering fee ($/Mcfe) (a)	$	0.57	$	0.58	$	0.59	$	0.55
Gathering and compression expense ($/Mcfe)	$	0.25	$	0.20	$	0.23	$	0.19
Gathering and compression depreciation ($/Mcfe)	$	0.10	$	0.10	$	0.10	$	0.09

Depreciation, depletion and amortization (in thousands):
Gathering and compression depreciation	$	3,255	$	2,924	$	6,607	$	5,831
Other depreciation, depletion and amortization	311		254		606		499
Total depreciation, depletion and amortization	$	3,566	$	3,178	$	7,213	$	6,330

FINANCIAL DATA (Thousands)
Gathering revenues	$	17,923	$	17,093	$	37,738	$	34,111

Operating expenses:
Gathering and compression expense	7,982		5,879		14,569		11,631
Selling, general and administrative (SG&A)	2,252		2,413		4,631		4,721
Depreciation, depletion and amortization (DD&A)	3,566		3,178		7,213		6,330
Total operating expenses	13,800		11,470		26,413		22,682

Operating income	$	4,123	$	5,623	$	11,325	$	11,429

(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 June 30, 2004
vs. Three Months Ended June 30, 2003

Equitable Gathering’s revenues increased $0.8 million from $17.1 million in the second quarter of 2003 to $17.9 million in the second quarter of 2004. The increase was primarily attributable to increased throughput.

Total operating expenses increased $2.3 million to $13.8 million in the 2004 second quarter from $11.5 million in the same quarter last year. The increase resulted from a $2.1 million increase in gathering and compression costs and a $0.4 million increase in depreciation relating to capital expenditures for gathering system improvements and extensions. The $2.1 million increase in gathering and compression costs is primarily attributable to the installation of electric compressors, increased field line operations and repair costs and higher right-of-way clearing costs. The additional compression costs increased horsepower to approximately 100,000 horsepower from 92,000 horsepower in 2003.

Six Months Ended June 30, 2004

vs. Six Months Ended June 30, 2003

Equitable Gathering’s revenues for the six months ended June 30, 2004 of $37.7 million increased $3.6 million over the prior year’s six months ended June 30, 2003 revenues of $34.1 million. The increase was primarily attributable to increased equity volumes and slightly higher average rates.

Total operating expenses increased $3.7 million to $26.4 million for the six months ended June 30, 2004 from $22.7 million for the six months ended June 30, 2003. The increase resulted from a $2.9 million increase in gathering and compression costs and a $0.9 million increase in depreciation relating to capital expenditures for gathering system improvements and extensions. The increase in gathering and compression costs is primarily attributable to increased field line maintenance costs, increased compressor electricity charges resulting from newly installed electric compressors and higher compressor station maintenance and repair costs, as previously described.

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 are comprised of 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. NORESCO also develops, constructs and operates facilities in the United States and operates private power plants in selected international countries.

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
OPERATIONAL DATA

Revenue backlog, end of period (thousands)	$	97,163		$	78,399		$	97,163		$	78,399
Gross profit margin	27.3		%	20.0		%	28.1		%	20.4		%
SG&A as a% of revenue	16.9		%	13.5		%	17.0		%	12.4		%

Capital expenditures (thousands)	$	164		$	98		$	192		$	146

FINANCIAL RESULTS (Thousands)

Energy service contract revenues	$	35,700		$	42,580		$	69,626		$	88,098
Energy service contract costs	25,962			34,074			50,067			70,156
Net operating revenue (gross profit margin)	9,738			8,506			19,559			17,942

Operating expenses:
Selling, general and administrative (SG&A)	6,021			5,733			11,805			10,899
Depreciation, depletion and amortization	250			341			501			690
Total operating expenses	6,271			6,074			12,306			11,589

Operating income	$	3,467		$	2,432		$	7,253		$	6,353

Equity earnings from nonconsolidated investments	$	416		$	1,452		$	1,136		$	2,389
Impairment of nonconsolidated subsidiaries	$	(40,251	)	$	—		$	(40,251	)	$	—
Minority interest	$	(359	)	$	—		$	(729	)	$	—

Three Months Ended June 30, 2004
vs. Three Months Ended June 30, 2003

NORESCO’s operating income was $3.5 million in the second quarter of 2004 compared to $2.4 million in the same period in 2003, an increase of $1.1 million. The increase was primarily due to an increase in the profitability on the projects constructed during the quarter and the consolidation of Hunterdon Cogeneration, LP (Hunterdon) as of July 1, 2003, partially offset by higher project development expenses related to increased sales activities in the performance contracting group. Revenue backlog increased by $18.8 million from $78.4 million on June 30, 2003 to $97.2 million on June 30, 2004. This increase was primarily due to the award of federal government contracts in the fourth quarter of 2003.

Total energy services contract revenue for the second quarter 2004 decreased by $6.9 million to $35.7 million from $42.6 million in the second quarter of 2003, primarily due to decreased construction activity on energy infrastructure projects versus the prior year. NORESCO’s second quarter 2004 gross profit margin increased to $9.7 million compared to $8.5 million during the second quarter 2003. Gross profit margin as a percentage of revenue increased from 20.0% in the second quarter 2003 to 27.3% in the second quarter 2004 due to an increase in the construction activity gross profit margin and the gross profit margin of Hunterdon.

Equity in earnings from power plant investments during the second quarter 2004 declined to $0.4 million from $1.5 million during the second quarter 2003. This reduction was primarily due to the consolidation of Hunterdon and decreased equity in earnings from the power plants in Panama. The consolidation of Hunterdon required NORESCO to recognize minority interest of $0.4 million in the second quarter 2004.

Several negative circumstances during the second quarter of 2004 caused the Company to evaluate its international investments for additional impairments and to accelerate its plans to exit the international generation business. As a result, the Company recognized an impairment of $40.2 million, essentially the cost of its entire international investment and the related costs of exiting these investments. The Company is actively evaluating alternatives for the sale of its international assets. See “Equity in Nonconsolidated Investments” below for further details on the impairment.

Six Months Ended June 30, 2004
vs. Six Months Ended June 30, 2003

NORESCO’s operating income increased $0.9 million to $7.3 million from $6.4 million in the same period last year. The increase was primarily due to an increase in net operating revenues partially offset by an increase in SG&A expenses. This increase in net operating revenues was due in part to a change in the mix of projects constructed and the consolidation of Hunterdon Cogeneration, LP (Hunterdon) as of July 1, 2003. The increase in SG&A expenses was due primarily to an increase in project development expenses related to the increase in sales activities in the performance contracting group.

Total revenue for the six months ended June 30, 2004 decreased by $18.5 million to $69.6 million from $88.1 million, primarily due to decreased construction activity on energy infrastructure projects versus the prior year. NORESCO’s gross profit margin increased to $19.6 million compared to $17.9 million in the same period last year. Gross profit margin as a percentage of revenue increased from 20.4% in 2003 to 28.1% in the 2004 due to an increase in the construction activity gross profit margin and the gross profit margin of Hunterdon.

Equity in earnings from power plant investments for the six months ended June 30, 2004 declined to $1.1 million from $2.4 million. This reduction was primarily due to the consolidation of Hunterdon and decreased equity in earnings from the power plant in Panama. The consolidation of Hunterdon required NORESCO to recognize minority interest expense of $0.7 million during the six months ending June 30, 2004.

EQUITY IN NONCONSOLIDATED INVESTMENTS

Certain NORESCO projects are held through equity in nonconsolidated entities that consist of private power generation facilities located in select international locations. The Company reviewed its equity investment related to Petroelectrica de Panama, an independent power plant in Panama, during the fourth quarter of 2003. As a result of the analysis performed, an impairment of $11.1 million in the fourth quarter of 2003 was recorded which represented the full value of NORESCO’s equity investment in the project.

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 ICG/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 represents the full value of NORESCO’s equity investment in the project.

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 is 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 in the second quarter of 2004 to write down the investment to its fair value less costs to sell. Following the impairment, the investment in Dona Julia is considered held for sale. The investment is included in equity in nonconsolidated investments on the Condensed Consolidated Balance Sheet and the Company expects to sell the investment within one year.

Additional impairment charges of $15.3 million were also recorded in the second quarter of 2004 for total impairment charges of $40.2 million for the quarter. The additional charges relate 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 a 50% owned non-recourse financed energy project known as Pan Am. The entire impairment charge has been included in impairment on nonconsolidated investments on the Statements of Consolidated Income. The Company is actively evaluating alternatives for the sale and disposal of its international assets.

In June 2003, the Company reevaluated its interest in Hunterdon Cogeneration LP (Hunterdon) and concluded that the Company effectively controlled Hunterdon for consolidation purposes. As a result, the Company began consolidating Hunterdon’s financial condition, results of operations and cash flows as of June 30, 2003 in the NORESCO segment.

NON-GAAP DISCLOSURES

The SEC’s final rule regarding the use of non-Generally Accepted Accounting Principals (GAAP) financial measures by public companies was effective after March 2003. The rule defined a non-GAAP financial measure as a numerical measure of an issuer’s historical or future financial performance, financial position or cash flows that:

1) Excludes amounts, or is subject to adjustments that have the effect of excluding amounts, that are included in the comparable measure calculated and presented in accordance with GAAP in the financial statements.

2) Includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the comparable measure so calculated and presented.

The Company has reported operating income, equity in earnings of nonconsolidated investments, excluding Westport, and minority interest by segment and by operations within each segment in the MD&A section of this Form 10-Q. Interest charges 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, equity in earnings of nonconsolidated investments, excluding Westport, and minority interest to the Company’s consolidated operating income, equity in earnings of nonconsolidated investments, excluding Westport, and minority interest 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 MD&A section of this Form 10-Q, and where appropriate, has provided information describing how a measure was derived. Equitable’s management believes that presentation of this non-GAAP 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.

CAPITAL RESOURCES AND LIQUIDITY

Operating Activities

Cash flows provided by operating activities in the first six months of 2004 totaled $170.4 million, a $24.9 million increase from the $145.5 million recorded in the prior year period. The Company had several significant items that were recorded on the income statement during the second quarter of 2004, which resulted from non-cash items. The Company’s net cash provided by operating activities from a liquidity standpoint was primarily affected by two items. There was an increase in cash provided from working capital in the second quarter 2004 due to a large decrease in inventory during the six months ended June 30, 2004 compared to a significant increase in inventory during the six months ended June 30, 2003. The decrease in inventory is the result of an increase in natural gas prices combined with colder weather in the first quarter of 2004, which caused large withdrawals of gas from storage as compared to year-end 2003. These large withdrawals in the first quarter were partially offset by injection of gas into underground storage during the second quarter of 2004. Offsetting this increase in cash resulting from the decrease in inventory was a decrease in cash resulting from the Company’s amendment of the prepaid forward contract in the second quarter of 2004. As a result of this amendment, the Company paid the counterparty to the contract the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. This resulted in a decrease to cash from operations of $36.8 million.

When the Company’s two prepaid forward gas sale transactions were originally consummated in January of 2001, the Company reviewed the specific facts and circumstances related to these transactions to determine if the appropriate Statement of Cash Flows presentation would be as an operating activity or a financing activity. The Company concluded that the appropriate accounting presentation of the prepaid forward gas sales transactions was as an operating cash flow item. Consistent with the Company’s previous presentation, the current presentation includes recognition of monetized production revenues related to prepaid forward gas sales in operating activities. One of the Company’s two prepaid forward gas sales contracts expired on December 31, 2003 resulting in the recognition of $17.3 million less monetized production revenue in the first six months of 2004 compared to the prior year period. In June 2004, the remaining prepaid forward contract was amended, which resulted in the Company repaying the net present value of the portion of the prepayment related to undelivered quantities of natural gas in the original contract. As stated previously, this amendment resulted in the Company repaying $36.8 million and recognizing a loss of $5.5 million on the settlement of the prepaid contract. On a going forward basis, the Company will deliver the required quantities of gas at an effective price of $4.79 per Mcf, rather than $3.99 per Mcf. These future revenues will be classified as operating cash flows.

Investing Activities

Cash flows used in investing activities in the first six months of 2004 were $79.7 million compared to $128.3 million in the prior year. The change from the prior year is attributable to a decrease in capital expenditures of $54.3 million primarily related to the purchase of the remaining limited partnership interest in ABP for $44.2 million in 2003, offset by proceeds from the sale of wells in Ohio in 2003.

Financing Activities

Cash flows used in financing activities during the first six months of 2004 were $123.4 million compared to cash flows used in financing activities of $11.9 million in the prior year period. The increase in cash used is primarily attributable to an increased repurchases of treasury stock, increased dividends paid, and repayments of long-term debt offset by the net effect of the $200 million issuance of notes in February 2003 and the redemption of $125 million of Trust Preferred Securities, and a slight decrease in short-term loans. As a result of the anticipated increase in liquidity associated with the recently completed merger between Westport and Kerr-McGee, the Company evaluated all alternatives for the use of those proceeds, including the potential for extinguishment of debt. To date, it has not been economically beneficial to early retire any of the Company’s currently outstanding debt.

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 2006. The credit agreement may be used for, among other things, credit support for the Company’s commercial paper program. As of June 30, 2004, the Company has the authority to arrange for a commercial paper program up to $650 million.

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 hedges natural gas through financial instruments including forward contracts, 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, options and other contractual agreements.

With respect to hedging the Company’s exposure to changes in natural gas commodity prices, management’s objective is to provide price protection for the majority of expected production for the years 2004 through 2008, and for over 25% of expected equity production for the years 2009 through 2010. The Company’s exposure to a $0.10 change in average NYMEX is $0.005 per diluted share in 2004 and is approximately $0.01 per diluted share in 2005 and 2006. Although the Company uses derivative instruments that create a price floor in order to provide downside protection while allowing the Company to participate in upward price movements through the use of collars and straight floors, the preponderance of instruments tend 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 basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices.

The approximate volumes and prices of the Company’s hedges and fixed price contracts for 2004 through 2006 are:

	2004**		2005		2006
Volume (Bcf)	31		63		62
Average Price per Mcf (NYMEX)*	$	4.68	$	4.80	$	4.74

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

** July through December

Commitments and Contingencies

The Company has annual commitments of approximately $28.4 million for demand charges under existing long-term contracts with various pipeline suppliers for periods extending up to 11 years, as of June 30, 2004, which relate to natural gas distribution and production operations. However, approximately $20.5 million of these costs are recoverable in customer rates.

In the third quarter of 2003, the Company signed a long-term lease for office space with Continental Real Estate Companies, which will own and construct the building in which the office space will be located. Plans call for the building to be complete early in 2005. The office space is located on the North Shore in Pittsburgh, Pennsylvania and will allow Equitable to consolidate its Pittsburgh office operations and increase efficiencies. The term of the lease is 20 years and nine months and the base rent is approximately $2 million per year, exclusive of operating expenses. Relocation of operations from locations that utilize space under long-term leases will likely cause additional expense in the second half of 2004 and the first half of 2005.

There are various claims and legal proceedings against the Company arising in the normal course of business. Although counsel is unable to predict with certainty the ultimate outcome, management and counsel believe that the Company has significant and meritorious defenses to any claims and intends to pursue them vigorously. The Company has established adequate reserves for that litigation, which it believes are appropriate, and therefore believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position of the Company. The reserves recorded by the Company do not include any amounts for legal costs expected to be incurred. It is the Company’s policy to recognize any legal costs associated with any claims and legal proceedings against the Company as they are incurred.

The various regulatory authorities that oversee Equitable’s operations will, from time to time, make inquiries or investigations into the activities of the Company. As previously disclosed, the Company received informal requests for information from the CFTC regarding the reporting of prices to industry publications. The Company cooperated fully with the CFTC as the Company always does when regulatory bodies make requests. The CFTC has advised the Company that its inquiry has been closed.

In July 2002, the United States Environmental Protection Agency (EPA) published a final rule that amends the Oil Pollution Prevention Regulation. The effective date of the rule was August 16, 2002. Under the final rule, Owners/Operators of existing facilities were to revise their Spill Prevention, Control and Countermeasure (SPCC) plans on or before February 17, 2003 and were required to implement the amended plans as soon as possible but not later than August 18, 2003. On April 17, 2003, the EPA extended the deadline to adopt a plan amendment to August 17, 2004 and the deadline to comply with the amended plan to February 18, 2005. In March 2004, the EPA resolved various lawsuits related to the final rule and held a public meeting to clarify certain aspects of the final rule. Based on this clarification, the Company has amended its plan of compliance resulting in a downward adjustment in the Company’s estimate of total costs of compliance to a range of $4.0 million to $6.0 million. The Company recorded a charge to earnings of $1.0 million in the second quarter of 2004 for environmental site assessments to be performed in accordance with the Company’s amended Spill Prevention, Control and Countermeasure (SPCC) compliance plan. The Company expects the remaining costs to be capitalized, but it did not include these amounts in the 2004 capital budget.

In addition to the SPCC requirement, the Company is subject to other 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 reserve requirement. The guarantee was included as part of the entire impairment charge of $40.2 million, which has been included as impairment on nonconsolidated investments on the Statements of Consolidated Income.

Investment in Kerr-McGee Corporation

On April 7, 2004, Westport announced a merger with Kerr-McGee. On June 25, 2004, Westport and Kerr-McGee announced that the two companies had completed their merger upon approval by the stockholders of each company. 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 17.0%, of Westport, resulting in the Company receiving 8.2 million shares of Kerr-McGee. The Company accounted for this investment as available for sale in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (Statement No. 115). 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 capital gain of $217.2 million on the exchange of the Westport shares for Kerr-McGee shares for the three and six months ended June 30, 2004. The Company recorded its book basis in the Kerr-McGee shares at $49.82 per share, which includes a discount to the market price for trading restrictions on the securities. The discount is recorded as a reduction to the increase in the book basis of the Kerr-McGee shares and will be accreted into other comprehensive income over the restriction period, which is the period until the securities can be reasonably expected to qualify for sale. Additionally, as part of the merger, the Company recorded $10.0 million of transaction-related expenses, including associated compensation accruals, in the second quarter of 2004.

Subsequent to the merger, the Company sold 800,000 shares of Kerr-McGee for $42.8 million, thus resulting in a realized gain of $3.0 million for the three and six months ended June 30, 2004. As a result of the sale, the Company recorded $42.8 million in accounts receivable on the Condensed Consolidated Balance Sheets as of June 30, 2004, as the cash was received subsequent to June 30, 2004. Additionally, on June 30, 2004, the Company irrevocably committed to contribute 357,000 shares of Kerr-McGee to the charitable foundation established in 2003, expecting to extend the foundation’s life. The shares are expected to be transferred to the foundation in the third quarter and resulted in the Company recording a charitable foundation contribution expense of $18.2 million for the three and six months ended June 30, 2004. The additional contribution to the foundation represents the optimal net present value for the Company with the two factors having changed since the original establishment of the foundation being the passage of time and the sizable increase and gain associated with the Kerr-McGee shares. As of June 30, 2004, the Company owned approximately 7.4 million shares of Kerr-McGee.

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 (Note Q). 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 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. The Company now owns approximately 7.0 million shares that are not committed to the charitable foundation. Approximately 1.0 million of these Kerr-McGee shares remain unhedged.

Benefit Plans

The Company made cash contributions totaling $51.8 million to its pension plan during the year ended December 31, 2003. As a result of the $51.8 million contribution, the Company’s minimum funding requirement is zero and is expected to be zero through the 2006 plan year.

In the fourth quarter of 2003, the Company froze the pension benefit provided through a defined benefit plan to approximately 340 salaried employees. The Company now provides benefits to these employees under a defined contribution plan that covers all other salaried employees of the Company. The decrease in service cost related to the conversion of this benefit plan, coupled with the cash contributions made by the Company in 2003, will decrease the amount of pension expense, exclusive of any special termination benefits and curtailment losses, to be recognized by the Company in future years. This decrease in pension expense is expected to be partially offset by increased defined contribution plan expense. The Company’s pension expense, exclusive of any special termination benefits

and curtailment losses, totaled $0.6 million and $1.2 million for the three and six months ended June 30, 2004 and $1.3 million and $2.6 million for the three and six months ended June 30, 2003, respectively.

Stock-Based Compensation

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 Statement No. 123 net income and diluted earnings per share for the three and six months ended June 30, 2004 would have been reduced by an estimated $1.0 million or $0.01 per diluted share and $2.1 million or $.04 per diluted share, respectively. 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 the price 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.

As a result of the Company’s share appreciation in the second quarter of 2004, the Company recognized an increase in the long-term incentive plan expense of $6.1 million associated with the Company’s Executive Performance Incentive Programs.

Federal Legislation

As a result of the Company’s increased partnership interest in ABP in 2002, the Company began receiving a greater percentage of the nonconventional fuels tax credit attributable to ABP. This resulted in a reduction of the Company’s effective tax rate during 2002. The nonconventional fuels tax credit expired at the end of 2002, and it is currently unclear whether legislation will be enacted to allow this tax benefit to exist in the future. On November 18, 2003, the Energy Policy Act of 2003 (H.R. 6) was passed by the House of Representatives. This comprehensive energy policy legislation, as reported by conferees from the House of Representatives and the Senate, included an extension of the nonconventional fuels tax credit for existing qualifying wells and for newly drilled qualifying wells. The Senate was unable to pass H.R. 6 before adjourning for the year due to a lack of votes needed to avoid a threatened filibuster. Energy tax legislation continues to be discussed by the Senate and House of Representatives, but any extension of the nonconventional fuels tax credit continues to remain uncertain.

On September 30, 2003, the enabling legislation for the performance contracting work that NORESCO performs for the federal government under the Department of Energy contracts lapsed and is pending extension in Congress. The Company believes the extension is a non-controversial element of the currently delayed Energy Bill. In 2003, 41% of NORESCO’s operating revenues were generated from the federal government. If this issue is not resolved for a prolonged period of time, the NORESCO segment’s ability to sign new contracts with the federal government is affected. Currently, an amendment providing for an extension of the program is circulating within Congress as part of the Department of Defense authorizations bill. It has passed the Senate as a Manager’s Amendment and is awaiting House approval.

Dividend

On July 14, 2004, the Board of Directors of the Company declared a regular quarterly cash dividend of 38 cents per share, payable September 1, 2004 to shareholders of record on August 13, 2004. Going forward, the Company has targeted dividend growth at a rate similar to the rate of its earnings per share growth.

Purchase of Treasury Stock

During the three and six months ended June 30, 2004, the Company repurchased 1.0 million and 1.3 million shares of Equitable Resources, Inc. stock, respectively. The total number of shares repurchased since October 1998 is approximately 18.0 million of the current 21.8 million share repurchase authorization.

Critical Accounting Policies

The Company’s critical accounting policies are described in the notes to the Company’s consolidated financial statements for the year ended December 31, 2003 contained in the Company’s Annual Report on Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been discussed in the notes to the Company’s condensed consolidated financial statements

for the period ended June 30, 2004. The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the consolidated financial statements. Management uses historical experience and all available information to make these estimates and judgments, and different amounts could be reported using different assumptions and estimates.

Equitable Resources, Inc. and Subsidiaries

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 uses simple, non-leveraged derivative 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 commodity price derivatives used to hedge forecasted Company production, Equitable sets policy limits relative to the expected production and sales levels, which are exposed to price risk. These financial instruments include forward contracts, 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, options and other contractual agreements. The level of price exposure is limited by the value at risk limits allowed by this policy. Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. 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 commodity price derivatives 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. These financial instruments include forward contracts, 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, options and other contractual agreements.

With respect to energy derivatives held by the Company for purposes other than trading (hedging activities), the Company continued to execute its hedging strategy by utilizing price swaps and futures of approximately 319.7 Bcf of natural gas. Some of these derivatives have hedged expected equity production through 2011. A decrease of 10% in the market price of natural gas would have increased the fair value of natural gas instruments by approximately $177.8 million at June 30, 2004. An increase of 10% in market price of natural gas would have decreased the fair market value by the same amount.

With respect to derivative contracts held by the Company for trading purposes, as of June 30, 2004, a decrease of 10% in the market price of natural gas would have increased the fair market value by approximately $0.1 million. An increase of 10% in the market price would have decreased the fair market value by approximately $0.1 million.

The Company determined the change in the fair value of the natural gas instruments using a method similar to its normal change in fair value as described in Note D to the notes to the condensed consolidated financial statements. The Company assumed a 10% change in the price of natural gas from its levels at June 30, 2004. The price change was then applied to the natural gas instruments recorded on the Company’s 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 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 three tranches of contracts represent the hedging of approximately three-fourths of the Kerr-McGee shares received as merger consideration and 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. The remaining unhedged Kerr-McGee shares owned by the Company and not committed to the foundation after entering into these contracts is approximately 1.0 million shares.

See Note D regarding Derivative Commodity Instruments and Note Q regarding the subsequent event related to the variable share forward contracts in the notes to the condensed consolidated financial statements and the 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.

Item 4. Controls and Procedures

The Chief Executive Officer and Chief Financial Officer 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 Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report. There were no significant changes in internal controls over financial reporting that occurred during the second quarter of 2004 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

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 June 30, 2004.

Period	Total number of shares (or units) purchased (a)	Average price paid per share		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 (b)

April 2004 (April 1 – April 30)	16,632	46.44		—	4,776,700

May 2004 (May 1 – May 31)	409,163	$	47.09	405,200	4,371,500

June 2004 (June 1 – June 30)	602,277	$	49.40	594,800	3,776,700

Total	1,028,072			1,000,000

(a) Includes 28,072 shares delivered in exchange for the exercise of options to cover option cost and tax withholding.

(b) On October 2, 1998, the Company’s Board of Directors authorized share repurchases, without an expiration date, of up to 11.2 million shares of common stock (publicly announced on October 7, 1998). On October 27, 1999 the Company’s Board of Directors increased the repurchase amount by 2.2 million shares to 13.4 million shares (increase in authorization was publicly announced on November 12, 1999). On July 19, 2000, the Company’s Board of Directors increased the repurchase amount by 5.4 million shares to 18.8 million shares (increase in authorization was publicly announced on July 20, 2000). On April 14, 2004, the Company’s Board of Directors increased the share repurchase authorization by 3.0 million shares to 21.8 million shares (increase in authorization was publicly announced on April 15, 2004).

In response to guidance provided by the Securities and Exchange Commission after the Company filed its Form 10-Q for the first quarter of 2004, the Company advises that during the first quarter of 2004, the Company purchased 26,723 shares (at an average price of $43.45 per share), delivered in exchange for the exercise of options to cover the option cost and tax witholding, and 785 shares (at an average price of $43.35 per share) to pay tax witholding in connection with the vesting of restricted shares.

Item 4. Submission of Matters to a Vote of Security Holders

a). The Annual Meeting of Shareholders was held on April 14,2004.

b). Brief description of matters voted upon:

(1) Elected the named director to serve a two-year term as follows:

Director		Shares Voted For		Shares Withheld
Lee T. Todd, Jr., Ph.D.		56,317,674		539,335

Elected the named directors to serve three-year terms as follows:

Director	Shares Voted For	Shares Withheld
Murry S. Gerber	56,013,208	843,801
George L. Miles, Jr.	55,975,120	881,889
James W. Whalen	55,940,610	916,339

The following Directors terms continue after the Annual Meeting of Shareholders:

until 2005 – Phyllis A. Domm, Ed.D., David L. Porges, James E. Rohr, and David S. Shapira;

until 2006 – Thomas A. McConomy, and Barbara S. Jeremiah

(2) Approved an amendment and restatement of the Equitable Resources, Inc. 1999 Long-Term Incentive Plan. Vote was 42,511,333 shares for, 6,977,442 shares against and 244,530 shares abstained.

(3) Ratified appointment of Ernst & Young, LLP, as independent auditors for the year ended December 31, 2004. Vote was 55,961,053 shares for; 817,917 shares against and 78,039 shares abstained.

Item 5. Other Information

On June 14, 2004, the Company announced the election of Vicky A. Bailey to the Board of Directors and approval by the Board to increase the number of Directors from ten to eleven. Ms. Bailey is a Partner in the governmental relations firm of Johnson & Associates, LLC. In addition to her duties on the Board, Ms. Bailey will also serve as a member of the Corporate Governance Committee.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits:

10.1		Equitable Resources, Inc. 2004 Short -Term Incentive Plan

10.2		Equitable Resources, Inc. 2002 Executive Performance Incentive Program (as amended and restated May 1, 2003 and April 13, 2004)

10.3		Equitable Resources, Inc 2003 Executive Performance Incentive Program (amended and restated April 13, 2004)

10.4		First Amendment to Equitable Resources, Inc. $500,000,000 Revolving Credit Agreement dated October 30, 2003 (amended June 16, 2004)

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 and David L. Porges pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(b) Reports on Form 8-K during the quarter ended June 30, 2004:

(i) Form 8-K dated April 15, 2004 disclosing the Company’s issuance of a press release announcing the results of its first quarter 2004 earnings and increase in dividend.

Signature

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	EQUITABLE RESOURCES, INC.
	(Registrant)


	/s/ David L. Porges
	David L. Porges
	Executive Vice President
	and Chief Financial Officer


Date: August 6, 2004

INDEX TO EXHIBITS

Exhibit No.	Document Description

10.1	Equitable Resources, Inc. 2004 Short-Term Incentive Plan	Filed Herewith

10.2	Equitable Resources, Inc. 2002 Executive Performance Incentive Program (as amended and restated May 1, 2003 and April 13, 2004)	Filed Herewith

10.3	Equitable Resources, Inc. 2003 Executive Performance Incentive Program (amended and restated April 13, 2004)	Filed Herewith

10.4	First Amendment to Equitable Resources, Inc. $500,000,000 Revolving Credit Agreement dated October 30, 2003 (amended June 16, 2004)	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 and David L. Porges pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed Herewith

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

PART I. FINANCIAL INFORMATION

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

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

Distribution Operations