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

Distribution Operations

Pipeline Operations

Equitable Marketing

Distribution Operations

Pipeline Operations

Equitable Marketing

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

3 EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

3

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Equitable Resources, Inc. and Subsidiaries

Equitable Resources, Inc. and Subsidiaries

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003

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 April 30, 2003

Common stock, no par value		62,448,018 shares

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Index

Part I. Financial Information:

	Item 1.	Financial Statements (Unaudited):

		Statements of Consolidated Income for the Three Months Ended March 31, 2003 and 2002

		Statements of Condensed Consolidated Cash Flows for the Three Months Ended March 31, 2003 and 2002

		Condensed Consolidated Balance Sheets as of March 31, 2003 and December 31, 2002

		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 6.	Exhibits and Report on Form 8-K

Signature

Certifications

Index to Exhibits

Statements of Consolidated Income (Unaudited)

	Three Months Ended March 31,
	2003			2002
	(Thousands, except per share amounts)

Operating revenues	$	342,322		$	294,043
Cost of sales	153,970			133,167
Net operating revenues	188,352			160,876

Operating expenses:
Operation and maintenance	18,855			17,584
Production and exploration	9,162			6,450
Selling, general and administrative	32,262			25,857
Depreciation, depletion and amortization	18,753			16,767
Total operating expenses	79,032			66,658

Operating income	109,320			94,218

Charitable contribution expense	(9,279		)	—
Equity earnings (losses) from nonconsolidated investments:

Westport	3,614			(4,248		)
Other	1,232			1,429
Total equity earnings (losses) from nonconsolidated investments	4,846			(2,819		)

Minority interest	(871		)	(1,248		)

Earnings before interest and taxes (EBIT)	104,016			90,151

Interest expense	12,321			9,579
Income from continuing operations before income taxes and cumulative effect of accounting change	91,695			80,572
Income taxes	27,216			28,200
Income from continuing operations before cumulative effect of accounting change	64,479			52,372
Cumulative effect of accounting change, net of tax	(3,556		)	(5,519		)

Net income	$	60,923		$	46,853

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	62,063			63,566
Income from continuing operations before cumulative effect of accounting change	$	1.04		$	0.82
Cumulative effect of accounting change, net of tax	(0.06		)	(0.08		)
Net income	$	0.98		$	0.74
Diluted:
Weighted average common shares outstanding	63,333			65,063
Income from continuing operations before cumulative effect of accounting change	$	1.02		$	0.80
Cumulative effect of accounting change, net of tax	(0.06		)	(0.08		)
Net income	$	0.96		$	0.72

Dividends declared per common share	$	0.20		$	0.17

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Condensed Consolidated Cash Flows (Unaudited)

	Three Months Ended March 31,
	2003			2002
	(Thousands)
Cash flows from operating activities:
Net income from continuing operations before cumulative effect of accounting change	$	64,479		$	52,372
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for doubtful accounts	7,665			4,269
Depreciation, depletion, and amortization	18,753			16,767
Charitable contribution	9,279			—
Recognition of monetized production revenue	(13,736		)	(13,736		)
Deferred income taxes	11,119			2,200
(Increase) decrease in undistributed earnings from nonconsolidated investments	(4,846		)	3,284
Changes in other assets and liabilities	(14,692		)	28,413
Total adjustments	13,542			41,197

Net cash provided by operating activities	78,021			93,569

Cash flows from investing activities:
Capital expenditures	(32,850		)	(37,072		)
Purchase of minority interest in ABP	(44,200		)	—
Decrease in restricted cash	—			1,196
Decrease in equity of unconsolidated entities	—			781
Proceeds from sale of property	6,550			—

Net cash used in investing activities	(70,500		)	(35,095		)

Cash flows from financing activities:
Issuance of long-term debt	200,000			—
Dividends paid	(10,585		)	(10,081		)
Proceeds from exercises under employee compensation plans	8,783			2,240
Purchase of treasury stock	(16,180		)	(17,672		)
Increase in loans against construction contracts	3,969			4,799
Repayments and retirements of long-term debt	(15,167		)	(157		)
Decrease in short-term loans	(50,006		)	(64,706		)

Net cash provided by (used in) financing activities	120,814			(85,577		)

Net increase (decrease) in cash and cash equivalents	128,335			(27,103		)
Cash and cash equivalents at beginning of period	17,748			29,622
Cash and cash equivalents at end of period	$	146,083		$	2,519

Cash paid during the period for:
Interest, net of amount capitalized	$	11,987		$	12,506
Income taxes paid, net of refund	$	(1,103	)	$	(1,029	)

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

Condensed Consolidated Balance Sheets (Unaudited)

	March 31, 2003		December 31, 2002
	(Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	146,083	$	17,748
Accounts receivable (less accumulated provision for doubtful accounts: 2003, $16,048; 2002, $15,294)	231,010		160,778
Unbilled revenues	111,716		130,348
Inventory	64,082		74,735
Derivative commodity instruments, at fair value	56,224		38,512
Prepaid expenses and other	11,659		7,930

Total current assets	620,774		430,051

Equity in nonconsolidated investments	107,557		245,792

Property, plant and equipment	2,621,683		2,545,138

Less accumulated depreciation and depletion	980,648		983,323

Net property, plant and equipment	1,641,035		1,561,815

Investments, available-for-sale	278,533		16,098

Other assets	186,458		183,135

Total	$	2,834,357	$	2,436,891

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

	March 31, 2003			December 31, 2002
	(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	19,250		$	24,250
Current portion of nonrecourse project financing	15,888			16,055
Short-term loans	55,994			106,000
Accounts payable	198,376			136,478
Prepaid gas forward sale	47,151			55,705
Derivative commodity instrument, at fair value	94,010			46,768
Current portion of project financing obligations	66,050			73,032
Other current liabilities	84,563			93,452

Total current liabilities	581,282			551,740

Long-term debt:
Debentures and medium-term notes	637,000			447,000

Deferred and other credits:
Deferred income taxes	399,246			350,690
Deferred investment tax credits	12,946			13,210
Prepaid gas forward sale	36,409			41,591
Project financing obligations	13,772			13,684
Other credits	148,425			115,337
Total deferred and other credits	610,798			534,512

Preferred trust securities	125,000			125,000

Capitalization:
Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares; shares issued: March 31, 2003 and December 31, 2002, 74,504	287,365			287,597
Treasury stock, shares at cost: March 31, 2003, 12,154; December 31, 2002, 12,162 (net of shares and cost held in trust for deferred compensation of 640, $12,204 and 642, $12,273)	(278,671		)	(271,930		)
Retained earnings	837,843			787,505
Accumulated other comprehensive income (loss), net of taxes	33,740			(24,533		)

Total common stockholders’ equity	880,277			778,639

Total	$	2,834,357		$	2,436,891

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

Notes to Condensed Consolidated Financial Statements (Unaudited)

A. Financial Statements

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles 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 generally accepted accounting principles 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) as of March 31, 2003, and the results of its operations and cash flows for the three month period ended March 31, 2003 and 2002.

The balance sheet at December 31, 2002 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements.

Due to the seasonal nature of the Company’s natural gas distribution and energy marketing businesses and the volatility of natural gas prices, the interim statements for the three month period ended March 31, 2003 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003.

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, 2002 as well as in “Information Regarding Forward Looking Statements” on page 17 of this document.

B. Segment Information

The Company reports its operations in three segments, which reflect its lines of business. 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 and sale of natural gas and minor associated oil, and the extraction and sale of natural gas liquids. 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. NORESCO’s activities comprise distributed on-site generation, combined heat and power, and central boiler/chiller plant development, design, construction, and operation; performance contracting; and energy efficiency programs.

Operating segments are evaluated on their contribution to the Company’s consolidated results based on earnings before interest and taxes. Interest charges and income taxes are managed on a consolidated basis and are allocated proportionately to the operating segments based upon the respective capital structures and separate company income tax liabilities of the operating segments. 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, but are instead included as a reconciling item to consolidated earnings from continuing operations.

	Three Months Ended March 31,
	2003			2002
	(Thousands)
Revenues from external customers:(a)
Equitable Utilities	$	236,109		$	223,751
Equitable Supply	81,697			66,402
NORESCO	45,518			35,439
Less: intersegment revenues(b)	(21,002		)	(31,549		)
Total	$	342,322		$	294,043

Depreciation, depletion and amortization:
Equitable Utilities	$	6,735		$	6,518
Equitable Supply	11,582			9,759
NORESCO	349			437
Headquarters	87			53
Total	$	18,753		$	16,767

Segment earnings before interest and taxes:
Equitable Utilities	$	59,027		$	53,475
Equitable Supply	47,780			37,247
NORESCO	4,858			4,200
Total segment earnings before interest & taxes	$	111,665		$	94,922
Reconciling items:
Headquarters earnings (loss) before interest & taxes not allocated to operating segments:
Westport equity earnings	$	3,614		$	(4,248	)
Charitable contribution expense	(9,279		)	—
Other	(1,984		)	(523		)
Earnings before interest & taxes	104,016			90,151
Interest expense	(12,321		)	(9,579		)
Income tax expenses	(27,216		)	(28,200		)
Income from continuing operations before cumulative effect of accounting change	64,479			52,372
Cumulative effect of accounting change, net of tax(c)	(3,556		)	(5,519		)
Net income	$	60,923		$	46,853

	March 31, 2003			December 31, 2002
	(Thousands)
Segment Assets:
Equitable Utilities	$	980,681		$	929,718
Equitable Supply	1,206,595			1,079,924
NORESCO	270,143			269,707
Total operating segments	2,457,419			2,279,349
Headquarters assets	376,938			157,542
Total	$	2,834,357		$	2,436,891

	Three Months Ended March 31,
	2003			2002
Expenditures for segment assets:
Equitable Utilities	$	8,668		$	9,320
Equitable Supply(d)	67,738			27,571
NORESCO	48			181
Other	596			0
Total	$	77,050		$	37,072

(a) Operating revenues for the prior periods have been reduced to conform to EITF No. 02-3. See Note J.

(b) Intersegment revenues represents sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities, which marketed all of the Equitable Supply production in 2002. In 2003, Equitable Supply assumed the marketing of a substantial portion of their operated volumes and recorded the marketing activity directly.

(c) Net income for the period ended March 31, 2002 has been adjusted to reflect the cumulative effect of an accounting change related to the adoption of Statement No. 142 that was retroactive to the first quarter 2002.

(d) 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 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 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 that it is determined control was not surrendered. 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 the contract receivables once the sale is complete. As of March 31, 2003, the Company had recorded a current liability of $66.1 million classified as current project financing obligations and a long-term liability of $13.8 million classified as project financing obligations on the Condensed Consolidated Balance Sheets. The current project financing obligations represent 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. Prior year has been reclassified to conform with current year presentation.

For the quarter ended March 31, 2003, approximately $11.5 million of the contract receivables met the criteria for sales treatment, generating a recognized gain of $0.1 million. The de-recognition of the $11.5 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 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 Company’s Board of Directors and is comprised of the chief executive officer, the chief financial officer and other officers and employees.

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. 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) and by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (Statement No. 138). 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 deemed appropriate by the Company’s CRC.

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 $51.8 million asset and an $82.1 million liability as of March 31, 2003, and a $30.9 million asset and a $25.0 million liability as of December 31, 2002. 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, 2002 to March 31, 2003 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 343.4 Bcfe and 265.1 Bcfe as of March 31, 2003 and December 31, 2002, respectively, and primarily relate to natural gas swaps. The open swaps at March 31, 2003 have maturities extending through December 2008.

The Company deferred a net loss of $22.3 million and a gain of $2.8 million in accumulated other comprehensive income (loss), net of tax, as of March 31, 2003 and December 31, 2002, 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 $29.4 million of unrealized loss on its derivative commodity instruments reflected in accumulated other comprehensive income as of March 31, 2003 will be recognized in earnings during the next twelve months due to the physical settlement of hedged transactions.

For the three months ended March 31, 2003 and 2002, ineffectiveness associated with the Company’s derivative commodity instruments designated as cash flow hedges (decreased) increased earnings by approximately ($1.0 million) and $0.5 million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.

The Company conducts trading activities primarily 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 March 31, 2003, the absolute notional quantities of the futures and swaps held for trading purposes totaled 1.3 Bcf and 5.5 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 year ended March 31, 2003 (in thousands).

Fair value of contracts outstanding as of December 31, 2002	$	6,623
Contracts realized or otherwise settled	(250		)
Other changes in fair value(a)	(6,476		)
Fair value of contracts outstanding as of March 31, 2003	$	(103	)

(a) This amount includes a decrease of $7.2 million related to the adoption of EITF No. 02-3 which is no longer included as trading activity. This change had no effect on other comprehensive income as the amount was fully reserved. There were no other adjustments to the fair value of the Company’s derivative contracts held for trading purposes relating to changes in valuation techniques and assumptions during the three months ended March 31, 2003.

The following table presents maturities and the fair valuation source for the Company’s derivative commodity instruments that are held for trading purposes as of March 31, 2003.

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

Source of Fair Value	Maturity Less than 1 Year		Total Fair Value

Prices actively quoted (NYMEX)(1)	(219	)	(219	)
Prices provided by other external sources(2)	116		116
Net derivative (liabilities) assets	(103	)	(103	)

(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

Investment Securities

A portion of the investments classified by the Company as available for sale are debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures. The net unrealized holding losses related to these securities as of March 31, 2003 and December 31, 2002 were $1.7 million and $1.5 million, respectively and are included in accumulated other comprehensive income. As of December 31, 2002, the Company performed an impairment analysis in accordance with Statement No. 115 and concluded that the decline below cost is not other-than-temporary. Factors and considerations the Company used to support this conclusion (as more fully described in the 2002 10K) have not changed in the first quarter 2003.

Westport Resources Corporation

The Company owns approximately 13 million shares, or 19.5% of Westport Resources Corporation (Westport), which decreased from 20.8% at the end of 2002. The Company does not have operational control of Westport. As a result of the decreased ownership, the Company changed the accounting treatment for its investment from the equity method to the cost method, effective March 31, 2003. The change in accounting method will eliminate the inclusion of Westport’s results in the Company’s equity earnings in future periods. Also, the Company’s investment in Westport at a fair market value totaling $262.5 million as of March 31, 2003, was reclassified to Investments, available for sale on the Condensed Consolidated Balance Sheet in accordance with Statement No. 115. The equity investment at the time it was reclassified was $134.1 million. The increase in the carrying value of the investment of $128.4 million represents an unrealized gain recorded in accumulated other comprehensive income. As the Company files its financial statements earlier than Westport, there may be differences between the financial results utilized by the Company to adjust its equity investment and the financial results reported by Westport. The Company records any differences that occur after the filing of the Company’s financial statements in the subsequent interim period. There were no significant adjustments recorded by the Company in the first quarter 2003 related to these differences.

In March 2003, the Company established a community giving foundation, projected to facilitate the Company’s charitable giving program for approximately 10 years. The foundation was funded through a donation of 905,000 shares of Westport stock. This resulted in charitable contribution expense of $9.3 million with a corresponding one-time tax benefit of approximately $7.1 million (see Note I).

F. Comprehensive Income (loss)

Total comprehensive income was as follows:

	Three Months Ended March 31,
	2003			2002
	(Thousands)
Net income	$	60,923		$	46,853
Other comprehensive income (loss), net of tax:
Net change in cash flow hedges:
Natural gas (Note D), net of tax benefit of $13,494 and $31,206 in 2003 and 2002, respectively	(25,060		)	(57,954		)
Interest rate, net of tax expense of $23 in 2003	43			—
Unrealized gain on available-for-sale securities (Note E), net of tax expense of $44,939 in 2003	83,290			—
	58,273			(57,954		)
Total comprehensive income (loss)	$	119,196		$	(11,101	)

G. Stock-Based Compensation

On February 27, 2003, the Company granted 439,400 stock units for the 2003 Executive Performance Incentive Share Plan. The 2003 Plan was established to provide additional incentive benefits to retain senior executives of the Company and to further align the persons primarily responsible for the success of the Company with the interests of the shareholders. The vesting of these units will occur on December 31, 2005, contingent upon the level of total shareholder return relative to 30 peer companies and will result in distribution of zero to 878,800 units (200% of the units). The Company anticipates, based on current estimates, that a certain level of performance will be met and has expensed a ratable estimate of the units accordingly. The expense for the three month period ended March 31, 2003 was $2.6 million, and is classified as selling, general and administrative expense.

A restricted stock grant in the amount of 70,510 shares was also awarded to various employees during the first quarter of 2003. The related expense recognized during the three month period ended March 31, 2003 was $0.1 million, and is classified as selling, general and administrative expense.

Additionally, 0.5 million stock options were awarded during the first quarter of 2003. The Company applies Accounting Principles Board Opinion 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.

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 employee stock-based awards.

	Three Months Ended March 31,
	2003			2002
	(Thousands)
Net Income, as reported	$	60,923		$	46,853
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	2,904			355
Deduct: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects	(4,004		)	(2,092		)
Pro Forma net income	$	59,823		$	45,116
Earnings per share:
Basic, as reported	$	0.98		$	0.74
Basic, pro forma	$	0.96		$	0.71

Diluted, as reported	$	0.96		$	0.72
Diluted, pro forma	$	0.94		$	0.69

H. Appalachian Basin Partners, LP (ABP)

In November 1995, the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit to a partnership, Appalachian Basin Partners, LP (ABP). The Company recorded the proceeds as deferred revenue, which was recognized as production occurred. The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target. The performance target was met near the end of 2001. The Company consolidated the partnership starting in 2002, and the remaining portion not owned by the Company was recorded as minority interest.

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, discontinued operations and cumulative effects of accounting changes. As a result of the donation on March 31, 2003 of appreciated shares of Westport Resources Corporation to a charitable foundation created by the Company (see Note E), the Company reported a one-time tax benefit of approximately $7.1 million. A gift of qualified appreciated stock allows for a tax deduction based on the fair market value of the gifted stock, resulting in a permanent difference between financial and tax reporting income that reduces the effective income tax rate. A permanent tax benefit of $3.9 million resulted in a decrease of the Company’s 34.0% estimated annual effective income tax rate for net income from continuing operations for the quarter to the Company’s 29.7% estimated effective income tax rate recorded during the quarter.

J. New Accounting Pronouncements

Asset Retirement Obligations

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143 (Statement No. 143), “Accounting for Asset Retirement Obligations”. Statement No. 143 has been 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 (DD&A) expense with a corresponding credit to accumulated depletion in accordance with Statement of Financial Accounting Standards No. 19 (Statement No. 19), “Financial Accounting and Reporting by Oil and Gas Producing Companies”. At the end of 2002, the cumulative amount recognized under this policy was approximately $20.9 million. Under Statement No. 143, the fair value of the asset retirement obligations will be recorded as liabilities when they are incurred, which is typically at the time the wells are drilled. Amounts recorded for the related assets will be 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 Company adopted Statement No. 143 on January 1, 2003. This cumulative effect of a change in accounting principle resulted in a one-time charge to earnings of $3.6 million, or $0.06 per diluted share, during the three months ended March 31, 2003. In addition, the Company recognized a $28.7 million other long-term liability and a $2.3 million long-term asset.

The Company’s only long-term obligation relates to the estimated future expenditures required to plug and abandon the Company’s approximately 12,000 wells in Appalachia. These wells will require plugging and abandonment costs to be incurred over an extended period of time, significant portions of which are not projected to occur for over 40 years.

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

	Three months ended March 31, 2003
Asset retirement obligations as of January 1, 2003	$	28,690
Accretion Expense	481
Liabilities incurred	11
Asset retirement obligations as of March 31, 2003	$	29,182

The associated long-lived assets of $2.3 million as of March 31, 2003 are not legally restricted assets.

Assuming retroactive application of the change in accounting principle as of January 1, 2002, there would be no material change in the pro forma net income for the three months ended March 31, 2002. Long-term liabilities, assuming retroactive application of the change in accounting principle as of January 1, 2002 and March 31, 2002, would have increased $26.9 million and $27.3 million, respectively.

Goodwill and Other Intangible Assets

In July 2001, the FASB issued Statement No. 142, “Goodwill and Other Intangible Assets,” which is effective for fiscal year 2002. Under Statement No. 142, goodwill and intangible assets with indefinite lives are no longer amortized but are reviewed at least annually for impairment. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives.

In accordance with the requirements of Statement No. 142, the Company tested its goodwill for impairment as of January 1, 2002. The fair value of the Company’s goodwill was estimated using discounted cash flow methodologies and market comparable information. As a result of the impairment test, the Company recognized an impairment of $5.5 million, net of tax, or $0.08 per diluted share, to reduce the carrying value of the goodwill to its estimated fair value as the level of future cash flows from the NORESCO segment are expected to be less than originally anticipated. In accordance with Statement No. 142, this impairment adjustment has been reported as the cumulative effect of an accounting change in the Company’s Statements of Consolidated Income retroactive to the first quarter 2002. The impairment adjustment reduced the Company’s reported first quarter 2002 net income of $52.4 million, or $0.80 per diluted share to $46.9 million, or $0.72 per diluted share.

The Company’s goodwill balance as of March 31, 2003 totaled $57.4 million and is entirely related to the NORESCO segment. The Company does not anticipate additional impairment and will perform the required annual impairment test of the carrying amount of goodwill in the fourth quarter.

Income Statement Presentation of Gains and Losses on Energy Trading Contracts

In June 2002, the FASB’s EITF issued EITF No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” and No. 00-17, “Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10.” EITF No. 02-3 was initially effective for financial statements issued for periods ending after July 15, 2002 and required that gains and losses on energy trading contracts be recorded net (i.e., within operating revenues) on a company’s income statement. Prior to this guidance, the Company reported the gains and losses on its energy trading contracts gross (i.e., included the revenues and costs comprising the gains and losses on energy trading derivative contracts within operating revenues and cost of sales, respectively) on its Statements of Consolidated Income in accordance with the guidance contained in EITF No. 98-10. As a result of the guidance contained in EITF No. 02-3, in the third quarter 2002, the Company classified all gains and losses on its energy trading contracts net on its Statements of Consolidated Income for all periods presented.

In the fourth quarter 2002, the FASB revised its consensus contained in EITF No. 02-3. EITF No. 02-3, as revised, rescinds the guidance contained in EITF No. 98-10 and requires that only energy trading contracts that meet the definition of a derivative in Statement No. 133 be carried at fair value. Energy trading contracts that do not meet the definition of a derivative must be accounted for as an executory contract (i.e., on an accrual basis).

Additionally, EITF No. 02-3, as revised, states that it will no longer be an acceptable industry practice to account for energy inventory held for trading purposes at fair value when fair value exceeds cost, unless explicitly provided by other authoritative literature. The EITF’s revised consensus is effective for all new energy trading contracts entered into and energy inventory held for trading purposes purchased after October 25, 2002. For any energy trading contracts entered into or energy inventory held for trading purposes as of October 25, 2002, companies are required to recognize a cumulative effect of a change in accounting principle beginning the first day of the first fiscal period beginning after December 15, 2002. The implementation of the above provisions of EITF No. 02-3 effective for the year ended December 31, 2002 and three month period ended March 31, 2003, did not have a material impact on the Company’s consolidated financial statements.

EITF No. 02-3, as revised, also requires that all gains and losses on derivative instruments held for trading purposes be presented on a net basis in the income statement for all periods presented, whether or not settled physically. For gains and losses on energy trading activities that are not derivatives pursuant to Statement No. 133, the presentation is determined based upon the guidance contained in EITF No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” This guidance is effective for all periods presented in financial statements issued for periods beginning after December 15, 2002 (earlier adoption is permitted). Prior to the implementation of this guidance, companies are able to present these gains or losses on either a gross or a net basis in accordance with the provisions contained in EITF No. 98-10. The reduction from a gross to a net classification has resulted in a reduction in both operating revenues and cost of sales for the Equitable Utilities segment for the three months ended March 31, 2002 of $50.8 million.

Revenue Arrangements with Multiple Deliverables

In November 2002, the EITF reached a consensus on Issue No. 00-21 “Revenue Arrangements with Multiple Deliverables,” (EITF No. 00-21). EITF No. 00-21 provides guidance on how to account for arrangements that involve the delivery or performance of multiple products, services and rights to use assets. The provisions of EITF 00-21 will apply to revenue arrangements entered into in the fiscal periods beginning after June 15, 2003. The Company is currently evaluating the impact EITF No. 00-21 will have on its financial position and results of operations.

Consolidation of Variable Interest Entities

In January 2003, the FASB issued FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.” FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. Management is currently evaluating the effect that the adoption of FIN 46 will have on its results of operations and financial condition. Adequate disclosure has been made for all off balance sheet arrangements for which it is reasonably possible that consolidation will be required under FIN 46.

Guarantees

In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). FIN 45 clarifies and expands on existing disclosure requirements for guarantees, including loan guarantees. It also would require that, at the inception of a guarantee, the Company must recognize a liability for the fair value, of its obligation under that guarantee. The initial fair value recognition and measurement provisions will be applied on a prospective basis to certain guarantees issued or modified after December 31, 2002.

The Company entered into transactions with Eastern Seven Partners, L.P. (ESP) and Appalachian Natural Gas Trust (ANGT) by which natural gas producing properties located in the Appalachian Basin region of the United States were sold. Appalachian NPI (ANPI) contributed cash and debt to ANGT. The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt. The Company has given to ANPI, subject to certain restrictions and limitations, a liquidity reserve guarantee secured by the fair market value of the assets purchased by ANGT for a market-based fee. These entities manage the assets and produce, market, and sell the related natural gas from the properties. As of March 31, 2003 ESP and ANPI had $132.5 million and $280.0 million of total assets, respectively, and $0.1 million and $261.6 million of liabilities (including $192 million of long-term debt), respectively. The Company’s maximum exposure to loss as a result of its involvement with ESP and ANPI is $26.1 million and $54.0 million, respectively.

K. Reclassification

Certain previously reported amounts have been reclassified to conform to the 2003 presentation.

L. Subsequent Events

The Company exercised its option to redeem the entire $125 million of 7.35% Trust Preferred Capital Securities on April 23, 2003.

After an extended period of troubled operations (more fully described in the 2002 10K), ERI JAM, LLC, a subsidiary that holds the Company’s interest in an international infrastructure project, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. The Company will continue to consolidate the partnership until it no longer has control. This change will not have a material effect on the Company’s financial position or results of operations.

Equitable Resources, Inc. and Subsidiaries

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. 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 amount of the Company’s plugging and abandonment obligations; the impact on the Company of FASB Statement 142; the Company’s hedging strategy and the effectiveness of that strategy, including the impact on earnings of a change in NYMEX; the likelihood and cost of resolving operational issues at the IGC/ERI Pan-Am Thermal project; the adequacy of the Company’s borrowing capacity to meet the Company’s liquidity requirements; the amount of unrealized gains on the Company’s derivative commodity instruments that will be recognized in earnings; the impact of new accounting pronouncements, including EITF No. 00-21 and Fin No. 46; the ultimate cost of the Company’s new customer and billing system; the resolution of issues relating to the Company’s Jamaican energy infrastructure project and the impact on the Company of the bankruptcy of that project; the Company’s pension plan funding obligations; future dividends; 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, implementation and execution of cost restructuring initiatives, curtailments or disruptions in production, timing and availability of regulatory and governmental approvals, 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 execute on certain energy infrastructure projects, the ability of the Company to negotiate satisfactory collective bargaining agreements with its union employees, changes in accounting rules, the financial results achieved by Westport Resources, 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.

OVERVIEW

Equitable Resources’ consolidated net income from continuing operations before cumulative effect of accounting change for the quarter ended March 31, 2003 totaled $64.5 million, or $1.02 per diluted share, compared to $52.4 million, or $0.80 per diluted share, reported for the same period a year ago. The first quarter 2003 earnings from continuing operations before cumulative effect of accounting change increased 23% from 2002 due to the increased equity earnings in nonconsolidated investments primarily related to the Company’s investment in Westport, higher realized selling prices, colder weather, increased commercial and industrial margins, increase in sales volumes from production and an increase in construction revenue. These factors were partially offset by an increase in interest expense, a charitable foundation contribution expense, and increased benefit and insurance costs.

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.

In the third quarter of 2002, the Company reclassified all gains and losses on its energy trading contracts (as defined in EITF 98-10) to a net presentation for all periods presented in accordance with EITF 02-3.

	Three Months Ended March 31,
	2003			2002
OPERATIONAL DATA

Capital expenditures (thousands)	$	8,668		$	9,320

Operating expenses as a % of net revenues	39.28		%	37.75		%

FINANCIAL RESULTS (Thousands)

Utility revenues	$	184,325		$	134,994
Marketing revenues	51,784			88,757
Total operating revenues	236,109			223,751

Purchased gas costs	138,890			137,851
Net operating revenues	97,219			85,900

Operating Expenses:
Operating and maintenance expense	13,103			11,624
Selling, general and administrative expense	18,354			14,283
Depreciation, depletion and amortization	6,735			6,518
Total expenses	38,192			32,425

EBIT	$	59,027		$	53,475

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

Net operating revenues increased $11.3 million, or 13%, for the three months ended March 31, 2003 compared to the prior year first quarter. The increase in net operating revenues is primarily attributable to 29% colder weather in the first quarter 2003 compared to the prior year first quarter, offset by a decrease in storage-related revenue in the pipeline operations. Total expenses for the quarter were $38.2 million compared to the $32.4 million reported during the same period last year. The increase in expenses of $5.8 million, or 18%, is mainly due to increased provisions for doubtful accounts ($4.0 million) combined with increased operation and maintenance expenses ($0.6 million), both related to the colder weather. The remaining increase in expenses is primarily related to higher legal, insurance and employee benefit costs.

Rates and Regulatory Matters

The local distribution operations of Equitable Gas Company (Equitable Gas), a division of the Company, provide natural gas services in southwestern Pennsylvania and to municipalities in northern West Virginia. In addition, Equitable Gas provides field line sales (also referred to as “farm tap” service) in eastern Kentucky. Equitable Gas is subject to rate regulation by state regulatory commissions in Pennsylvania, West Virginia and Kentucky.

Over the last two years 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 Pennsylvania Public Utility Commission (PA PUC) to implement a performance-based incentive that provides customers a guaranteed purchased gas cost credit, while enabling Equitable Gas to retain any cost savings 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.

In the second quarter 2002, the PA PUC authorized Equitable Gas to offer a sales service that would give residential and small business customers the alternative to fix the unit cost of the commodity portion of their rate. The program was developed in response to customer requests for a method to reduce the fluctuation in gas costs. This “first of its kind” program in Pennsylvania is another in a series of service-enhancing initiatives implemented by Equitable Gas. The Company is currently preparing to offer this sales service to its residential and small business customers.

In the third quarter 2002, the PA PUC issued an order approving Equitable Gas’ request for a Delinquency Reduction Opportunity Program. The program gives incentives to eligible customers to make payments exceeding their current bill amount and receive additional credits from Equitable Gas to reduce the customer’s delinquent balance. The program will be fully funded through customer contributions and a surcharge in rates.

Equitable Gas completes quarterly purchased gas cost filings with the PA PUC, which are subject to quarterly reviews and annual audits by the PA PUC. The PA PUC completed its last audit in 2001, which approved the Company’s purchased gas costs through 1999. The Company’s purchased gas costs for the years 2000 through 2003 are currently unaudited by the PA PUC, but have received final prudency review by the PA PUC through 2001.

Other

Equitable Gas is in the process of implementing a new customer information and billing system for which the Company has incurred $7.2 million of capital expenditures from project inception through March 31, 2003. Based upon the information currently available to management, the implementation is expected to be successfully completed by the end of 2003.

Equitable Gas’s contract with the members of the local United Steelworkers union expired on April 15, 2003. The Company and the union have agreed to work under the terms of the expired contract and will continue to negotiate in the second quarter.

	Three Months Ended March 31,
	2003		2002

OPERATIONAL DATA

Degree days (30 year normal YTD average – 2,930)	3,115		2,409
O & M and SG&A (excluding other taxes) per customer	$	89.64	$	69.40

Volumes (MMcf)
Residential	14,165		11,216
Commercial and Industrial	11,590		10,415
Total gas sales and transportation	25,755		21,631

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	71,193	$	59,253

Operating costs	25,429		19,806
Depreciation and amortization	4,949		4,834

EBIT	$	40,815	$	34,613

The 30-year normal degree days figure is derived from the National Oceanic and Atmospheric Administration’s (NOAA) 30-year normal figures. The NOAA released updated normal figures for the period 1971 to 2000 and accordingly, Equitable Gas’ figure decreased from 3,016 referenced in 2002 to 2,930 in 2003.

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

Net operating revenues for the first quarter 2003 increased by $11.9 million compared to the 2002 period due almost entirely to colder weather. Heating degree days were 3,115, which is 29% cooler than the 2,409 degree days reported in 2001 and 6% cooler than the 30-year normal of 2,930. Accordingly, the colder weather caused total volumes to increase by 4.1 Bcf.

Total expenses of $25.4 million for the quarter ended March 31, 2003 increased $5.6 million compared to the first quarter 2002’s total expenses of $19.8 million. The increase in operating costs was primarily due to increased provisions for doubtful accounts ($4.0 million), which were recorded at approximately 6% of residential revenues for the quarter. This expense combined with higher operating costs ($0.6 million) mainly for the repair of leaks (876 in the first quarter 2002 compared to 439 in the same period of 2001) and increased emergency calls (3303 in the first quarter 2002 compared to 2509 in the same period of 2001), resulted from colder weather. The remaining increase in operating costs is primarily related to higher legal, insurance and employee benefit costs.

Interstate Pipeline

The pipeline operations of Equitrans, L.P. (Equitrans) and Carnegie Interstate Pipeline Company (Carnegie Pipeline), subsidiaries of the Company, are subject to rate regulation by the FERC. Equitrans’ last general rate change application (rate case) was filed in 1997. The rate case was resolved through a FERC approved settlement among all parties. The settlement provided, with certain limited exceptions, that Equitrans will not file a general rate increase with an effective date before August 1, 2001 and must file a general rate increase 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. Included in this filing is a request for a deferral of the 2003 rate case requirement discussed above.

In April 2003, Equitrans filed a proposed settlement with FERC related to the second quarter 2002 filing to merge its assets with the assets of Carnegie Pipeline. The settlement also provided for a continuation of the rate moratorium until April 2005. FERC subsequently received a protest to the settlement. Equitrans has filed comments with FERC to address the protest. The Company anticipates a FERC decision on the proposed settlement before the end of the third quarter 2003.

	Three Months Ended March 31,
	2003		2002
	(Thousands)
OPERATIONAL DATA

Transportation throughput (MMbtu)	20,428		16,719

FINANCIAL RESULTS

Net operating revenues	$	15,913	$	17,518

Operating costs	5,673		5,160
Depreciation and amortization	1,707		1,580

EBIT	$	8,533	$	10,778

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

Total transportation throughput increased 3.7 million MMbtu, or 22%, over the prior year quarter. The sustained colder than normal weather in the first quarter 2003 caused many of the firm transportation contract customers to use the full capacity of the pipeline, leading to a significant increase in the transportation throughput. 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 decreased by $1.6 million from $17.5 million in 2002 to $15.9 million in 2003. The decrease in net revenues from the prior year quarter is due almost entirely to lost storage revenue opportunities as a result of firm customer delivery demands resulting from the colder weather. In order to meet all firm customer needs, there were occasional reductions for interruptible customers in the first quarter 2003. These curtailments coupled with the increased firm transportation throughput resulted in the inability to take advantage of excess capacity commercial opportunities that typically exist.

Operating expenses were essentially flat in the 2003 first quarter compared to the first 2002 quarter. The slight increase is due to increased legal, insurance and employee benefit costs.

	Three Months Ended March 31,
	2003		2002
	(Thousands)
OPERATIONAL DATA

Marketed gas sales (MMBtu)	14,157		50,357

Total Physical and Financial Unit Margin/MBtu	$	0.68	$	0.18

FINANCIAL RESULTS

Net operating revenues	$	10,112	$	9,129

Operating costs	355		941
Depreciation and amortization	78		104

EBIT	$	9,679	$	8,084

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

The Company has continued to focus on high margin sales through storage optimization and asset management, which has contributed to an increase in net operating revenues of $1.0 million over the $9.1 million reported in the first quarter 2002. Additionally, the Equitable Supply segment assumed the direct marketing of its operated volumes at the beginning of 2003, which had previously been marketed by Equitable Marketing. These volumes, approximately 32 million MMbtu in the first quarter 2003, had been marketed by Equitable Marketing at very low margins and the change has not had a significant impact on the current quarter net revenue results.

Operating expenses for the current quarter of $0.4 million decreased $0.6 million from the first quarter 2002. The reduction is due to a recovery of a previously reserved bankrupt customer’s balance recorded in 2002 and continued cost reduction initiatives associated with the Company’s decision to de-emphasize low margin trading-oriented activities.

EQUITABLE SUPPLY

Equitable Supply operates two lines of business – production and gathering – with operations in the Appalachian region of the United States. Equitable Production develops, produces and sells natural gas and, to a limited extent, crude oil and its associated by-products. Equitable Gathering engages in natural gas gathering and the processing and sale of natural gas liquids.

Sale of Gas Properties

In November 1995, the Company monetized Appalachian gas properties qualifying for the nonconventional fuels tax credit to a partnership, Appalachian Basin Partners, LP (ABP). The Company recorded the proceeds as deferred revenue, which was recognized as production occurred. The Company retained a partnership interest in the properties that increased substantially based on the attainment of a performance target. The performance target was met at the end of 2001. The Company has consolidated the partnership starting in 2002, and the remaining portion not owned by the Company was recorded as minority interest.

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 15.3 Bcf of net reserves for proceeds of approximately $6.6 million. The wells produced approximately 0.8 Bcf annually.

Purchase of Gas Properties

In February 2003, the Company purchased the remaining 31% limited partnership interest in ABP from the minority interest holders for $44.2 million. The limited partner interest represents approximately 60.2 Bcf of reserves. Effective February 1, 2003, the minority interest is no longer being recognized.

Operational and Financial Data

	Three Months Ended March 31,
	2003		2002
OPERATIONAL DATA
Total sales volumes (MMcfe)(a)	15,517		14,895
Total operated volumes (MMcfe)(b)	22,356		22,506
Volumes handled (MMcfe)(c)	35,309		33,247
Selling, general, and administrative ($/Mcfe handled)	$	0.19	$	0.17
Capital expenditures (Thousands)(d)	$	67,738	$	27,571

(a) Includes net equity sales and monetized sales volumes

(b) Includes equity volumes, monetized volumes, and volumes in which interests were sold, but which the Company still operates for a fee.

(d) Includes the purchase of the remaining 31% limited partnership interest in ABP ($44.2 million) which was approved by Board of Directors of the Company in addition to the total amount authorized for the 2003 capital budget program.

	Three Months Ended March 31,
	2003			2002
FINANCIAL DATA (Thousands)
Production revenues	$	64,679		$	50,814
Gathering revenues	17,018			15,588
Total operating revenues	81,697			66,402
Operating expenses:
Lease operating expense	4,916			4,744
Severance tax	3,887			1,410
Land and leasehold maintenance	359			296
Gathering and compression expense	5,752			5,960
Selling, general and administrative	6,788			5,588
Depreciation, depletion and amortization	11,582			9,759
Total operating expenses	33,284			27,757
Operating income	48,413			38,645
Equity from nonconsolidated investments	239			52
Minority interest	(872		)	(1,450		)
EBIT	$	47,780		$	37,247

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

Equitable Supply’s EBIT for the three months ended March 31, 2003 was $47.8 million, 29% higher than the $37.2 million earned for the three months ended March 31, 2002. The segment’s results were favorably impacted by higher commodity prices, increased natural gas sales volume and increased gathering revenues.

Total revenues for the first quarter 2003 increased 23% to $81.7 million compared to $66.4 million in 2002, which is primarily attributable to a higher effective price. Equitable Supply’s weighted average well-head sales price realized on produced volumes for the 2003 first quarter was $3.99 per Mcfe compared to $3.21 per Mcfe for the same period last year. The $0.78 increase in the weighted average well-head sales price is attributed to higher NYMEX prices, increased hedged volumes, higher hedged prices and increased basis over the first quarter 2002. The high commodity price environment in the first quarter 2003 has highlighted that not all gathering systems may be profitable and the need to further evaluate these gathering systems.

Total operating expenses for the three months ended March 31, 2003 were $33.3 million compared to $27.8 million in last year’s first quarter, which represents a 20% increase. This increase is primarily due to severance taxes attributed to higher gas prices ($2.5 million), increased depletion costs ($1.8 million) and increased selling, general and administrative (SG&A) expense relating to increases in insurance premiums, legal reserves and staffing costs ($1.2 million).

Equitable Production (Appalachian)

Operational and Financial Data

	Three Months Ended March 31,
	2003		2002
OPERATIONAL DATA
Net equity sales, natural gas and equivalents (MMcfe)	12,046		11,424
Average (well-head) sales price ($/Mcfe)	$	4.21	$	3.20

Monetized sales (MMcfe)(a)	3,471		3,471
Average (well-head) sales price ($/Mcfe)	$	3.23	$	3.25
Weighted average (well-head) sales price ($/Mcfe)	$	3.99	$	3.21

Company usage, line loss (MMcfe)	1,057		1,340

Lease operating expense (LOE), excluding severance tax ($/Mcfe)	$	0.30	$	0.29
Severance tax ($/Mcfe)	$	0.23	$	0.09
Depletion ($/Mcfe)	$	0.48	$	0.40

Total operated volumes (MMcfe)(b)	22,356		22,506

(a) Volumes sold associated with the Company’s two prepaid natural gas sales contracts

(b) Includes equity volumes, monetized volumes, and volumes in which interests were sold, but which the Company still operates for a fee.

	Three Months Ended March 31,
	2003			2002
FINANCIAL DATA (Thousands)
Produced natural gas sales	$	61,902		$	47,830
Other revenues	2,777			2,984
Total operating revenues	64,679			50,814
Operating expenses:
Lease operating	4,916			4,744
Severance tax	3,887			1,410
Land and leasehold maintenance	359			296
Selling, general and administrative (SG&A)	4,480			3,688
Depreciation, depletion and amortization	8,430			6,731
Total operating expenses	22,072			16,869

Operating income	42,607			33,945
Equity from nonconsolidated investments	239			52
Minority interest/ other	(872		)	(1,450		)
EBIT	$	41,974		$	32,547

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

Equitable Production’s EBIT for the three months ended March 31, 2003 was $42.0 million, a 29% increase over the prior year’s first quarter EBIT of $32.5 million. Production revenues were up $13.9 million from $50.8 million in the first quarter 2002 to $64.7 million in the first quarter 2003. This increase results from an effective sales price of $3.99 per Mcfe compared to $3.21 per Mcfe in the prior year quarter and a 0.6 Bcf increase in sales volumes.

Sales volume increases resulting from new drilling in the past 12 months were partially offset by increased interstate pipeline system curtailment (0.2 Bcfe), coupled with production issues surrounding automation implementation and surveillance (0.3 Bcf). Severe cold weather and above average snowfall in the months of January and February also created operational shortfalls (0.2 Bcf). In addition, the Company changed its methodology for calculating hydrocarbon liquids conversion. Effective January 1, 2003, the Company adjusted its method for using a natural gas equivalents conversion factor to convert gallons of liquid hydrocarbon sales to equivalent volumes of natural gas sales. This change results in an additional 0.3 Bcfe of natural gas sales volume and a corresponding reduction to reported company usage and line loss for the first quarter 2003.

Operating expenses were up $5.2 million over the prior year quarter from $16.9 million to $22.1 million. The increase is a result of higher severance taxes attributed to higher natural gas prices ($2.5 million), increased depletion costs ($1.7 million), increased SG&A due to higher insurance premiums and legal reserves and increased staffing ($0.8 million), and increased lease operating expenses due to increased liability insurance premiums ($0.2 million).

Depletion per Mcfe increased from $0.40 in the 2002 first quarter to $0.48 in the 2003 first quarter. Of the total $0.08 per Mcfe increase, $0.03 per Mcfe relates to the developmental drilling program, $0.03 is attributed to the changes resulting from purchases and sales of natural gas properties and $0.02 per Mcfe is a result of the implementation of SFAS No. 143, described in Note J.

Equitable Gathering

Operational and Financial Data

	Three Months Ended March 31,
	2003		2002
OPERATIONAL DATA

Gathered volumes (MMcfe)	32,552		30,615
Average gathering fee ($/Mcfe)(a)	$	0.52	$	0.51
Gathering and compression expense ($/Mcfe)	$	0.18	$	0.19
Gathering and compression depreciation ($/Mcfe)	$	0.09	$	0.09

(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 this case the Company utilizes standard measures in order to split the price into its two components.

	Three Months Ended March 31,
	2003		2002
FINANCIAL DATA (Thousands)
Gathering revenues	$	16,866	$	15,588
Other revenues	152		—
Total operating revenues	17,018		15,588
Operating expenses:
Gathering and compression	5,752		5,960
Selling, general and administrative (SG&A)	2,308		1,900
Depreciation, depletion and amortization	3,152		3,028
Total operating expenses	11,212		10,888

EBIT	$	5,806	$	4,700

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

Equitable Gathering’s EBIT for the three months ended March 31, 2003 of $5.8 million increased $1.1 million or 24% over the prior year’s first quarter EBIT of $4.7 million. Gathering revenues were $16.9 million compared to $15.6 million in the first quarter 2002, an 8% increase. Contributing to this increase is additional throughput from new customers coupled with slightly higher average gathering rates.

Operating expenses were $11.2 million in the 2003 first quarter, a $0.3 million increase over the $10.9 million in the same quarter last year. SG&A expenses were higher due to increased insurance premiums, legal reserves and staffing costs increases discussed above.

NORESCO

NORESCO provides energy-related products and services that are designed to reduce its customers’ operating costs and to improve their productivity. The segment’s activities are comprised of combined heat and power and central boiler/chiller plant development, design, construction, ownership and operation; performance contracting; and energy efficiency programs. NORESCO’s customers include governmental, military, institutional, and industrial end-users. NORESCO’s energy infrastructure group develops, designs constructs and operates facilities in the United States and operates private power plants in selected international countries.

	Three Months Ended March 31,
	2003			2002
OPERATIONAL DATA

Revenue backlog, end of period (thousands)	$	88,992		$	108,088
Construction completed (thousands)	$	30,562		$	21,305

Capital expenditures (thousands)	$	48		$	181

Gross profit margin	20.7		%	24.2		%
SG&A as a % of revenue	11.4		%	15.6		%
Development expenses as a % of revenue	2.2		%	2.6		%

FINANCIAL RESULTS (Thousands)

Energy service contract revenues	$	45,518		$	35,439
Energy service contract costs	36,082			26,865
Net operating revenues	9,436			8,574

Selling, general and administrative expenses	5,166			5,516

Depreciation, depletion and amortization	349			437
Total expenses	5,515			5,953

Equity earnings of nonconsolidated investments	937			1,579

EBIT	$	4,858		$	4,200

Three Months Ended March 31, 2003

vs. Three Months Ended March 31, 2002

NORESCO’s EBIT increased $0.7 million due to increased earnings of $4.9 million from the first quarter 2003 over earnings of $4.2 million in the first quarter 2002. This increase in EBIT is primarily attributable to an increase in construction revenue and lower SG&A expenses, offset by lower earnings from power plant investments. Total revenue for the first quarter 2003 increased by 28% to $45.5 million, compared to $35.4 million in the first quarter 2002.

Revenue backlog in the current year decreased by $19 million from $108 million on March 31, 2002 to $89 million on March 31, 2003, primarily due to a decrease in new federal government performance contracts.

NORESCO’s first quarter 2003 gross margin increased to $9.4 million compared to $8.6 million during the first quarter 2002. Gross profit margin decreased as a percentage of revenue from 24.2% in the first quarter 2002 to 20.7% in the first quarter 2003 due to an increased construction mix of larger projects with lower gross margins and a reduction in earnings from demand side management programs.

Equity in earnings from power plant investments during the first quarter 2003 declined to $0.9 million from $1.6 million during the first quarter 2002. This reduction is primarily due to lower equity in earnings from power plants in Panama and Rhode Island.

Total operating expenses were lower by $0.4 million to $5.5 million for the first quarter 2003 versus $6.0 million for the same period in 2002, primarily to decrease in SG&A labor costs. SG&A as a percentage of revenue decreased to 11.4% versus 15.6% for the same period last year.

EQUITY IN NONCONSOLIDATED INVESTMENTS

On April 10, 2000, Equitable Resources merged its Gulf of Mexico operations with Westport Oil and Gas Company for approximately $50 million in cash and approximately 49% of a minority interest in the combined company, named Westport Resources Corporation (Westport). Equitable Resources accounted for this investment under the equity method of accounting. In October 2000, Westport completed an initial public offering (IPO) of its shares. Equitable Resources sold 1.325 million shares in this IPO for an after-tax gain of $4.3 million. On August 21, 2001, Westport Resources completed a merger with Belco Oil & Gas. On March 31, 2003, the Company donated 905,000 shares to a community giving foundation. The Company currently owns approximately 13 million shares, or 19.5% of Westport Resources Corporation (Westport), which is a decrease from 20.8% at the end of 2002. The Company does not have operational control of Westport. As a result of the decreased ownership, the Company changed the accounting treatment for its investment from the equity method to the cost method, effective March 31, 2003. The Company has recognized earnings of $3.6 million in the first quarter classified as equity earnings from nonconsolidated investments in the Statements of Consolidated Income on its equity investment in Westport. The change in accounting method will eliminate the inclusion of Westport’s results in the Company’s equity earnings in future periods. Also, the Company’s investment in Westport at fair market value totaling $262.5 million as of March 31, 2003, was reclassified to Investments, Available for Sale on the Condensed Consolidated Balance Sheet in accordance with Statement No. 115. The equity investment at the time it was reclassified was $134.1 million.

NORESCO has equity ownership interests in independent power plant (IPP) projects located domestically and in selected international locations. Long-term power purchase agreements (PPAs) are signed with the customer whereby they agree to purchase the energy generated by the plant. The length of these contracts ranges from 1 to 30 years. The Company has not made an investment since April 2001 and has a total cumulative investment of $44.9 million as of March 31, 2003. The Company’s share of the earnings for the first quarter of 2003 and 2002 related to the total investment was $0.9 million and $1.6 million, respectively. These projects generally are financed with nonrecourse financings at the project level.

In 2001, one of the Company’s domestic power plant projects, in which the Company owns a 50% interest, Capital Center Energy in Rhode Island, began experiencing billing disputes. The project has reserved for the amounts in dispute pending resolution of the issues. These disputes adversely affect the cash flows and the financial stability of the project and could trigger project loan covenant violations, particularly if resolution of the disputes is further delayed. In September 2002, the Company filed a complaint against an energy customer in Providence Superior Court seeking recovery of $2.3 million owed for energy services rendered through July 2002. In December 2002, a significant energy customer filed a third-party complaint against the site owner, for alleged breach of its lease with the owner. In December 2002, the Company issued a notice to the energy customer threatening to shut off services unless its account was brought current through July 2002, and a settlement, featuring a current lump sum payment from the customer and reduced payments for energy supplied going forward (pending final settlement) was entered into on December 31, 2002. The Company also provided the site owner a global settlement offer, which, if accepted, would result in resolution of all outstanding payment issues. NORESCO’s equity interest in this non-recourse financed project is $4.4 million as of March 31, 2003. The Company is currently investigating all possible options for resolution of the dispute.

One of the Company’s two Panamanian projects, in which the Company owns a 45% interest, Petroelectrica de Panama, is a party to a five-year PPA, which expired in February 2003. In November 2002, the project won a bid in which the majority of the project’s available capacity is under contract with a local distribution company for the twelve months beginning February 1, 2003. The project debt was fully satisfied in December 2002.

The Company owns a 50% interest in a second Panamanian electric generation project, IGC/ERI Pan-Am Thermal. The project had previously agreed to retrofit the plant to conform to environmental noise standards by a target date of August 31, 2001. Unforeseen events delayed the final completion date of the required retrofits. The project has obtained an extension from the Panamanian government while it evaluates a land acquisition/rezoning proposal, which, if accepted and executed, would eliminate the need for a retrofit requirement. The creditor sponsor continues to evaluate the land acquisition/rezoning proposal while concurrently exploring the feasibility of a final technical resolution to the noise issues. The Company is coordinating with the creditor sponsor to obtain any additional regulatory extensions, which may be required. In September and October 2002, the Panamanian government adopted two resolutions which affect the plant’s compliance requirements—by suspending the noise mitigation deadline while the Company achieves the objectives of the land acquisition and rezoning proposal, and by modifying the noise standards applicable to the plant (by making them less stringent). The expected additional cost to the Company of achieving resolution of this issue, whether by a retrofit or implementation of the land acquisition/rezoning proposal, is not expected to exceed $1.5 million.

Additionally, this second Panamanian electric generation project experienced poor financial performance during 2002 due to adverse weather (abnormally high rainfall), other adverse market-related conditions, and reduced plant availability related to planned and unplanned outages. These factors depressed revenues, causing a drop below the minimum debt service coverage ratio covenant of the non-recourse loan document. The Company has been actively coordinating with the creditor sponsor on this matter and during the second half of 2002 and the first quarter of 2003 experienced improvement in operational and financial performance. Despite the debt service coverage ratio issues, cash flows and payment of debt service are expected to be adequate through 2003.

NON-GAAP DISCLOSURES

The SEC issued a final rule regarding the use of non-Generally Accepted Accounting Principals (GAAP) financial measures by public companies. The rule defines 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) Exclude 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 uses EBIT instead of net income as part of the segment reporting. The Company believes EBIT more accurately depicts the individual financial performance of the segments because both interest and income taxes are controlled on a corporate wide basis and are not fully allocated to the segments. Refer to Note B for a reconciliation of the segments’ EBIT to net income.

CAPITAL RESOURCES AND LIQUIDITY

Operating Activities

Cash flows provided by operating activities totaled $78.0 million, a $15.6 million decrease from the $93.6 million recorded in the prior year period. The decrease is primarily the result of the decrease in cash provided from working capital in the first quarter 2003 due to increase in receivables and inventory.

Investing Activities

Cash flows used in investing activities in the first three months of 2003 were $70.5 million compared to $35.1 million in the prior year. The change from the prior year is primarily attributable to an increase in capital expenditures of $40.0 million primarily related to the purchase of the remaining limited partnership interest in ABP, offset by proceeds from the sale of wells in Ohio.

Financing Activities

Cash flows provided from financing activities during the first three months of 2003 were $120.8 million compared to cash flows used in financing activities of $85.6 million in the prior year period. The increase is primarily the result of the $200 million issuance of notes in February 2003, with a stated interest rate of 5.15% and a maturity date of March 2018. A portion of the proceeds from the issuance will be used for retiring the Company’s outstanding 7.35% Trust Preferred Securities and general corporate purposes. The Company exercised its option and redeemed the entire $125 million of 7.35% Trust Preferred Capital Securities on April 23, 2003. Excluding proceeds received from the debt issuance, cash flows used in financing activities during 2003 were relatively consistent with 2002 and primarily related to the Company’s continued focus on reducing its short-term debt and purchasing shares of its outstanding stock through the use of cash provided by operating activities.

During the first quarter of 2001, a Jamaican energy infrastructure project, owned by a consolidated subsidiary, experienced defaults relating to various loan covenants. Consequently, the Company reclassified the non-recourse project financing from long-term debt to current liabilities. The plant has not operated to expected levels and remediation efforts have been ineffective. As a result, in the second quarter of 2002, the Company reviewed the project for impairment and recognized an impairment loss of $5.3 million. During the first quarter of 2003, the Jamaica power plant project shut down its engines and terminated most of the staff in order to preserve available cash while discussions among different parties involved in the project continued, seeking a global settlement. After an extended period of troubled operations (more fully described in the 2002 10K), ERI JAM, LLC, a subsidiary that holds the Company’s interest in the an international infrastructure project, filed for bankruptcy protection under Chapter 11 in U.S. Bankruptcy Court (Delaware) in April 2003. The Company will continue to consolidate the partnership until it no longer has control. That change will not have a material effect on the Company’s financial position or results of operations.

The Company 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 $250 million of available credit, and a 364-day credit agreement providing $250 million of available credit that expire in 2005 and 2003, respectively. As of March 31, 2003, the Company has the authority to arrange for a commercial paper program up to $650 million.

Hedging

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices.

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 2002 through 2005, and over 25% of expected equity production for the years 2006 through 2008. The Company’s exposure to a $0.10 change in NYMEX is less than $0.005 per diluted share in 2003. While the Company does use 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 costless 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 mitigate the fixed price exposure inherent in its firm capacity commodity commitments. During the quarter ended March 31, 2003, the Company hedged approximately 0.5 Bcf of natural gas basis exposure through March 2004.

The approximate volumes and prices of the Company’s hedges and fixed price contracts for 2003 to 2005 are:

	2003		2004		2005
Volume (Bcf)	47		45		42
Average Price (NYMEX)*	$	4.22	$	4.45	$	4.56

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

Commitments and Contingencies

The Company has annual commitments of approximately $25.8 million for demand charges under existing long-term contracts with pipeline suppliers for periods extending up to 6 years as of December 31, 2002, which relate to natural gas distribution and production operations. However, approximately $19.1 million of these costs are recoverable in customer rates.

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 provided adequate reserves 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, from time to time, make inquiries or investigations into the activities of the Company. Equitable is not aware of any wrongdoing relating to any such inquiries or investigations.

In July 2002, the 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 Regulations (SPCC) 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 EPA extended the compliance deadlines for plan amendment to August 17, 2004 and implementation of the amended plan as soon as possible, but not later than February 18, 2005. Management is currently evaluating the impact of this final rule on the Company.

The Company is also subject to federal state and local environmental 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 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.

Benefit Plans

Poor market conditions that have existed since 2000 have contributed to a significant reduction in the fair market value of the Company’s pension plan assets. As a result, the Company’s benefit obligation relating to its pension plans is significantly underfunded. The Company therefore expects to make contributions of between $30 million and $40 million to the Company’s pension plans during 2003. The Company did not make any contribution to its pension plans during the first quarter of 2003.

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 and the 0.5 million stock option grant awarded during the three months ended March 31, 2003 consistent with the methodology prescribed in Statement No. 123 “Accounting for Stock-Based Compensation,” net income and diluted earnings per share for the three months ended March 31, 2003 would have been reduced by an estimated $1.6 million or $0.03 per diluted share. The estimate of compensation cost is based upon the use of the Black-Scholes option pricing model. The Black-Scholes model is considered a “theoretical” or probability model used to estimate what an option would sell for in the market today. The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.

Nonconventional Fuels Tax Credits

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. This resulted in a reduction in the Company’s effective tax rate during 2002. The nonconventional fuels tax credit expired at the end of 2002. On April 11, 2003, the Energy Policy Act of 2003 (H.R. 6) was passed by the House of Representatives and included an extension of the nonconventional fuels tax credit. A different legislative proposal to extend the nonconventional fuels tax credit is currently before the Senate. Any extension of the nonconventional fuels tax credit continues to be uncertain.

Dividend

On April 17, 2003, the Board of Directors of Equitable Resources declared a regular quarterly cash dividend of 20 cents per share, payable June 1, 2003 to shareholders of record on May 9, 2003. The Company is targeting dividend growth at a rate similar to the rate of earnings per share growth.

Acquisitions and Dispositions

In February 2003, the Company purchased the remaining 31% limited partnership interest in ABP from the minority interest holders for $44.2 million. The limited partnership interest represents approximately 60.2 Bcf of reserves. Effective February 1, 2003, ABP was fully consolidated in the Company’s financial statements and a minority interest is no longer being recognized. On January 16, 2003, the Board of Directors of the Company approved the repurchase of the ABP properties which is in addition to the total $228 million authorized for the 2003 capital budget program.

Critical Accounting Policies

The Company’s significant accounting policies are described in the notes to the Company’s consolidated financial statements for the year ended December 31, 2002 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 included in the notes to the Company’s condensed consolidated financial statements for the period ended March 31, 2003. The application of these 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.

Schedule of Certain Contractual Obligations

Below is a table that details the future projected payments for the Company’s significant contractual obligations as of March 31, 2003.

	Payments Due by Period
	Total	2003	2004-2005	2006-2007	2008+
	(Thousands)
Interest expense	599,248	31,374	80,101	77,966	409,807
Long-term debt	672,138	25,138	30,500	13,000	603,500
Unconditional purchase obligations	218,017	24,614	60,238	55,460	77,705

Total contractual cash obligations	1,489,403	81,126	170,839	146,426	1,090,012

Included in long-term debt is a current portion of non-recourse project financing in the amount of $15.9 million. This amount relates directly to the defaults on the debt convenants for the Jamaican energy infrastructure project in the NORESCO segment discussed above, for which the bank may attempt to call the loan.

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.

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 231.1 Bcf of natural gas. Some of these derivatives have hedged expected equity production through 2008. A decrease of 10% in the market price of natural gas would increase the fair value of natural gas instruments by approximately $106.6 million at March 31, 2003.

With respect to derivative contracts held by the Company for trading purposes, as of March 31, 2003, a decrease of 10% in the market price of natural gas would decrease the fair market value by approximately $0.1 million.

See Footnote D regarding Derivative Instruments in the Notes to Condensed Consolidated Financial Statements and the Hedging 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

Quarterly Evaluation of the Company’s Disclosure Controls and Internal Controls

Within the 90 days prior to the date of the filing of this Report, the Company evaluated the effectiveness of the design and operation of its “disclosure controls and procedures” (Disclosure Controls), and its “internal controls and procedures for financial reporting” (Internal Controls). This evaluation (the Controls Evaluation) was done under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO). Rules adopted by the SEC require that we present the conclusions of the CEO and the CFO about the effectiveness of our Disclosure Controls and Internal Controls based on and as of the date of the Controls Evaluation.

CEO and CFO Certifications

Appearing immediately after the Signature section of this filing and as Exhibit 99 to this filing are separate forms of “Certifications” of the CEO and the CFO. The first form of Certification is required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002 (the Section 302 Certification). This section of the Report contains the information concerning the Controls Evaluation referred to in the Section 302 Certifications and should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

Disclosure Controls and Internal Controls

Disclosure Controls are procedures that are designed with the objective of ensuring that information required to be disclosed in reports filed under the Securities Exchange Act of 1934 (Exchange Act), such as this Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s (SEC) rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. Internal Controls are procedures which are designed with the objective of providing reasonable assurance that (1) our transactions are properly authorized; (2) assets are safeguarded against unauthorized or improper use; and (3) our transactions are properly recorded and reported, all to permit the preparation of our financial statements in conformity with accounting principles generally accepted in the United States.

Limitations on the Effectiveness of Controls

The Company’s management, including the CEO and CFO, does not expect that the Disclosure Controls or our Internal Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, control may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Scope of the Controls Evaluation

The CEO/CFO evaluation of our Disclosure Controls and Internal Controls included a review of the controls’ objectives and design, the implementation by the Company and the effect of the controls on the information generated for use in this Report. In the course of the Controls Evaluation, management sought to identify data errors, controls problems or acts of fraud and to confirm that appropriate corrective action, including process improvements, were being undertaken. This type of evaluation will be done on a quarterly basis so that the conclusions concerning controls effectiveness can be reported in Quarterly Reports on Form 10-Q and Annual Report on Form 10-K. The Internal Controls are also evaluated on an ongoing basis by the Company’s internal auditors, other personnel in the Finance organization and by the independent auditors in connection with their audit and review activities. The overall goals of these various evaluation activities are to monitor Disclosure Controls and with the Internal Controls and to make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls be maintained as dynamic systems that change (including both improvements and corrections) as conditions warrant.

Among other matters, the Company sought in our evaluation to determine whether there were any “significant deficiencies” or “material weaknesses” in the Company’s Internal Controls, or whether the Company had identified any acts of fraud involving personnel who have a significant role in the Company’s Internal Controls. This information was important both for the Controls Evaluation generally and because items 5 and 6 in the Section 302 Certifications of the CEO and CFO require that the CEO and CFO disclose that information to the Board’s Audit Committee and to the independent auditors and to report on related matters in this section of the Report. In the professional auditing literature, “significant deficiencies” are referred to as “reportable conditions”; these are control issues that could have a significant adverse effect on the ability to record, process, summarize and report financial data in the financial statements. A “material weakness” is defined in the auditing literature as a particularly serious reportable condition where the internal control does not reduce to a relatively low level the risk that misstatements caused by error or fraud may occur in amounts that would be material in relation to the financial statements and not be detected within a timely period by employees in the normal course of performing their assigned functions. Management also sought to deal with other controls issues in the Controls Evaluation, and in each case if a problem was identified, to consider whether to make any revision, improvement and/or correction.

In accordance with SEC requirements, the CEO and CFO note that, since the date of the Controls Evaluation to the date of this Report, there have been no significant changes in Internal Controls or in other factors that could significantly affect Internal Controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

Conclusions

Based upon the Controls Evaluation, the CEO and CFO have concluded that, subject to the limitations noted above, the Disclosure Controls are effective to ensure that material information relating to Equitable Resources and its consolidated subsidiaries is made known to management, including the CEO and CFO, particularly during the period when our periodic reports are being prepared, and that our Internal Controls are effective to provide reasonable assurance that the Company’s financial statements are fairly presented in conformity with generally accepted accounting principles.

PART II. OTHER INFORMATION

Item 6. Exhibits and Report on Form 8-K

(a) Exhibits:

10.1 Equitable Resources, Inc. 2003 Executive Performance Incentive Program

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

99 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) Report on Form 8-K during the quarter ended March 31, 2003:

(i) Form 8-K dated January 30, 2003 disclosing the Company’s issuance of a press release announcing the results of its fourth quarter and full year 2002 earnings.

(ii) Form 8-K dated February 14, 2003 disclosing the Company’s adoption of new stock ownership guidelines for certain employees.

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: May 8, 2003

CERTIFICATION

I, Murry S. Gerber, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Equitable Resources, Inc.

2. Based on my knowledge, this Quarterly Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Quarterly Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Quarterly Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Quarterly Report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Quarterly Report is being prepared;

b. evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Quarterly Report (the “Evaluation Date”); and

c. presented in this Quarterly Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this Quarterly Report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 8, 2003

	/s/ Murry S. Gerber
	Murry S. Gerber
	Chairman, President and Chief Executive Officer

CERTIFICATION

I, David L. Porges, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Equitable Resources, Inc.

b. evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Quarterly Report (the “Evaluation Date”); and

c. presented in this Quarterly Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

d. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

e. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 8, 2003

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

INDEX TO EXHIBITS

Exhibit No.

Document Description

Equitable Resources, Inc. 2003 Executive Performance Incentive Program

File Herewith

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

File Herewith

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.

File Herewith