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 SEPTEMBER 30, 2002

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

Class		Outstanding at October 31, 2002

Common stock, no par value		62,497,185 shares

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Index

		Page No.
Part I. Financial Information:

Item 1.	Financial Statements (Unaudited):

	Statements of Consolidated Income for the Three and Nine Months Ended September 30, 2002 and 2001	2

	Statements of Condensed Consolidated Cash Flows for the Three and Nine Months Ended September 30, 2002 and 2001	3

	Condensed Consolidated Balance Sheets as of September 30, 2002, and December 31, 2001	4-5

	Notes to Condensed Consolidated Financial Statements	6-13

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14-32

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	33

Part II. Other Information:

Item 1.	Legal Proceeding	34

Item 6.	Exhibits and Report on Form 8-K	34

Signature		35

Certifications		36-38

Index to Exhibits		39

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

(Thousands, except per share amounts)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002			2001

Operating revenues	$	162,571		$	165,842	$	585,706		$	748,316
Cost of sales	44,204			53,147		182,445			321,324
Net operating revenues	118,367			112,695		403,261			426,992

Operating expenses:
Operation and maintenance	18,833			19,469		54,829			60,696
Production and exploration	6,746			7,675		19,587			26,899
Selling, general and administrative	24,300			25,554		73,248			85,817
Impairment of long-lived assets	—			—		5,320			—
Depreciation, depletion and amortization	17,613			18,100		51,151			52,637
Total operating expenses	67,492			70,798		204,135			226,049

Operating income	50,875			41,897		199,126			200,943

Equity earnings (losses) from nonconsolidated investments and minority interest:
Westport	231			5,465		(4,642		)	19,932
Other	(958		)	1,134		(2,294		)	6,437
	(727		)	6,599		(6,936		)	26,369

Earnings before interest and taxes (EBIT)	50,148			48,496		192,190			227,312

Interest charges	9,344			10,188		28,182			31,000

Income from continuing operations before income taxes and cumulative effect of accounting change	40,804			38,308		164,008			196,312
Income taxes	14,118			13,508		55,761			68,809
Income from continuing operations before cumulative effect of accounting change	26,686			24,800		108,247			127,503
Income from discontinued operations	—			—		9,000			—
Cumulative effect of accounting change, net of tax	—			—		(5,519		)	—
Net income	$	26,686		$	24,800	$	111,728		$	127,503

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	62,326			63,912		63,023			64,470
Income from continuing operations before cumulative effect of accounting change	$	0.43		$	0.39	$	1.72		$	1.98
Income from discontinued operations	—			—		0.14			—
Cumulative effect of accounting change, net of tax	—			—		(0.09		)	—
Net income	$	0.43		$	0.39	$	1.77		$	1.98

Diluted:
Weighted average common shares outstanding	63,668			65,562		64,541			66,233
Income from continuing operations before cumulative effect of accounting change	$	0.42		$	0.38	$	1.68		$	1.93
Income from discontinued operations	—			—		0.14			—
Cumulative effect of accounting change, net of tax	—			—		(0.09		)	—
Net income	$	0.42		$	0.38	$	1.73		$	1.93

Dividends declared per common share	$	0.17		$	0.16	$	0.50		$	0.47

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)

(Thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001

Cash flows from operating activities:
Net income from continuing operations before cumulative effect of accounting change	$	26,686		$	24,800		$	108,247		$	127,503
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for doubtful accounts	551			1,098			5,580			11,328
Depreciation, depletion, and amortization	17,613			18,100			51,151			52,637
Impairment of assets	—			—			5,320			—
Recognition of monetized production revenue	(14,040		)	(24,779		)	(41,664		)	(71,541		)
Deferred income taxes	6,857			6,353			19,112			24,646
(Increase) decrease in undistributed earnings from nonconsolidated investments	(1,152		)	(5,570		)	2,384			(21,568		)
Changes in other assets and liabilities	(23,401		)	(33,092		)	39,535			(7,345		)
Total adjustments	(13,572		)	(37,890		)	81,418			(11,843		)
Net cash provided by (used in) operating activities	13,114			(13,090		)	189,665			115,660

Cash flows from investing activities:
Capital expenditures	(68,519		)	(38,999		)	(155,235		)	(83,474		)
Decrease in restricted cash	—			—			62,956			—
Decrease (increase) in equity of nonconsolidated entities	77			33			1,050			(16		)
Proceeds from sale of contract receivables	—			—			—			1,130
Proceeds from sale of property	—			2,073			—			6,598
Net cash used in investing activities	(68,442		)	(36,893		)	(91,229		)	(75,762		)

Cash flows from financing activities:
Dividends paid	(10,474		)	(10,221		)	(31,257		)	(30,178		)
Proceeds from exercises under employee compensation plans	4,784			1,461			14,487			4,813
Purchase of treasury stock	(34,403		)	(7,251		)	(79,270		)	(53,457		)
Loans against construction contracts	9,927			15,611			18,156			45,768
Repayments and retirement of long-term debt	(162		)	(151		)	(477		)	(151		)
Increase (decrease) in short-term loans	85,864			47,295			(43,047		)	(58,515		)
Net cash provided by (used in) financing activities	55,536			46,744			(121,408		)	(91,720		)

Net increase (decrease) in cash and cash equivalents	208			(3,239		)	(22,972		)	(51,822		)
Cash and cash equivalents at beginning of period	6,442			3,440			29,622			52,023
Cash and cash equivalents at end of period	$	6,650		$	201		$	6,650		$	201

Cash paid during the period for:
Interest, net of amount capitalized	$	12,480		$	10,423		$	30,469		$	32,696
Income taxes paid, net of refund	$	13		$	616		$	11,720		$	10,896

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	September 30, 2002		December 31, 2001
	(Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	6,650	$	29,622
Restricted cash	—		62,956
Accounts receivable (less accumulated provision for doubtful accounts: 2002, $14,047; 2001, $14,807)	88,845		132,750
Unbilled revenues	102,194		77,080
Inventory	94,109		96,445
Derivative commodity instruments, at fair value	74,491		193,623
Prepaid expenses and other	20,365		20,868

Total current assets	386,654		613,344

Equity in nonconsolidated investments	249,780		253,214

Property, plant and equipment	2,479,284		2,337,344

Less accumulated depreciation and depletion	966,198		923,067

Net property, plant and equipment	1,513,086		1,414,277

Investments, available-for-sale	10,455		—

Other assets	184,945		237,912

Total	$	2,344,920	$	2,518,747

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	September 30, 2002			December 31, 2001
	(Thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of nonrecourse project financing	$	16,219		$	16,696
Current portion of debentures and medium-term notes	24,250			—
Short-term loans	232,400			275,447
Accounts payable	104,595			101,654
Prepaid gas forward sale	55,705			55,705
Derivative commodity instrument, at fair value	41,934			62,002
Other current liabilities	107,670			100,686

Total current liabilities	582,773			612,190

Long-term debt:
Debentures and medium-term notes	247,000			271,250

Deferred and other credits:
Deferred income taxes	357,345			364,633
Deferred investment tax credits	13,501			14,336
Prepaid gas forward sale	55,632			97,296
Deferred revenue	13,755			6,560
Project financing obligations	83,173			109,209
Other	77,970			72,119
Total deferred and other credits	601,376			664,153

Preferred trust securities	125,000			125,000

Capitalization:
Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares; shares issued: September 30, 2002 and December 31, 2001, 74,504	281,931			282,920
Treasury stock, shares at cost: September 30, 2002, 12,327; December 31, 2001, 10,634 (net of shares and cost held in trust for deferred compensation of 409, $7,299 and 362, $6,284)	(268,135		)	(203,353		)
Retained earnings	755,495			675,207
Accumulated other comprehensive income, net of taxes	19,480			91,380

Total common stockholders’ equity	788,771			846,154

Total	$	2,344,920		$	2,518,747

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

Equitable Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

A. Financial Statements

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with 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 only of normal, recurring adjustments necessary for a fair presentation of the financial position of Equitable Resources, Inc. and subsidiaries (the Company or Equitable Resources) as of September 30, 2002, and the results of its operations and cash flows for the three and nine month periods ended September 30, 2002 and 2001.

The balance sheet at December 31, 2001 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 and nine month periods ended September 30, 2002 are not necessarily indicative of the results that may be expected for the year ending December 31, 2002.

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, 2001 as well as in “Information Regarding Forward Looking Statements” on page 14 of this document.

B. Segment Information

The Company reports its operations in three segments, which reflect its lines of business. The Equitable Utilities segment’s operations are comprised of 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 Production segment’s operations are comprised of the development, production, gathering and sale of natural gas. The NORESCO segment’s operations are comprised of energy infrastructure projects that include on-site power generation and central boiler/chiller plant 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 September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
	(Thousands)
Revenues from external customers:
Equitable Utilities	$	39,735		$	59,129		$	253,017		$		413,437
Equitable Production	68,627			66,401			196,547			224,792
NORESCO	54,209			40,312			136,142			110,087
Total	$	162,571		$	165,842		$	585,706		$		748,316

Intersegment revenues:
Equitable Utilities	$	39,054		$	23,989		$	102,517		$		115,523
Equitable Production	3,405			1,922			9,915			9,574
Total	$	42,459		$	25,911		$	112,432		$		125,097

Segment earnings before interest and taxes:
Equitable Utilities	$	3,340		$	1,991		$	71,895		$		56,959
Equitable Production	40,975			40,034			117,050			143,957
NORESCO	5,787			1,474			9,375			8,929
Total operating segments	$	50,102		$	43,499		$	198,320		$		209,845

Reconciling items:
Equity earnings (losses) in Westport	$	231		$	5,465		$	(4,642	)	$		19,932
Headquarters operating expenses	(185		)	(468		)	(1,488		)	(2,465				)
Interest expense	(9,344		)	(10,188		)	(28,182		)	(31,000				)
Income tax expenses	(14,118		)	(13,508		)	(55,761		)	(68,809				)
Discontinued operations	—			—			9,000			—
Cumulative effect of accounting change, net of tax	—			—			(5,519		)	—
Net income	$	26,686		$	24,800		$	111,728		$		127,503

							September 30, 2002				December 31, 2001
							(Thousands)

Segment Assets:
Equitable Utilities							$	942,205			$		937,147
Equitable Production							967,331				1,138,550
NORESCO							235,094				264,960

Total operating segments							2,144,630				2,340,657

Headquarters assets, including investment in Westport, cash and short-term investments							200,290				178,090

Total							$	2,344,920			$		2,518,747

C. Contract Receivables

In September 2000, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (Statement) No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” that replaces in its entirety, Statement No. 125. Although Statement No. 140 has changed many of the rules regarding securitizations, it continues to require an entity to recognize the financial and servicing assets it controls and the liabilities it has incurred and to derecognize financial assets when control has been surrendered in accordance with the criteria provided in the Statement. As required, the Company has applied the new rules prospectively to transactions beginning in the second quarter 2001.

The Company transfers contract amounts due from customers to financial institutions. The Company does not retain any interests in the transferred contract receivables. The value of the contract receivables is based on the face value of the executed contract and the gain or loss on the sale of contract receivables depends in part on the previous carrying amount of the financial assets involved in the transfer. Certain of these transfers do not immediately qualify as “sales” under 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. The Company derecognizes the receivables and the liabilities when control has been surrendered in accordance with the criteria provided in Statement No. 140. As of September 30, 2002, the Company had recorded a liability of $83.2 million classified as project financing obligations on the Consolidated Balance Sheets with the related assets classified as unbilled revenues as construction progresses and as other assets upon completion of construction. For the nine month period ending September 30, 2002, approximately $44.5 million of the contract receivables met the criteria for sales treatment generating a recognized gain of $1.1 million. The derecognition of the $44.5 million in receivables and the related liabilities was considered a non-cash transaction and is consequently not reflected in the Statements of 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 to hedge exposures to fluctuations in natural gas prices. 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 Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by Statement No. 137, “Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133” and by Statement No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities.” As a result, the Company recognizes all derivative instruments as either assets or liabilities 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.

Derivative Commodity Instruments

The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production have been designated and qualify as cash flow hedges. The fair value of these derivative commodity instruments as of September 30, 2002 is included in the Consolidated Balance Sheets as a $63.4 million asset and an $8.9 million liability separately classified as derivative commodity instruments, at fair value. The decrease in the amount of derivative commodity instruments, at fair value from December 31, 2001 to September 30, 2002 is primarily the result of an increase in natural gas market prices during this period. The difference between the fair value of these derivative instruments and the total amounts classified on the Consolidated Balance Sheets as derivative commodity instruments, at fair value represent the fair value of the Company’s derivative commodity instruments held for trading purposes.

The effective portion of the change in fair value of the Company’s derivative commodity instruments designated as cash flow hedges remains in accumulated other comprehensive income until the hedged transactions occur, at which point the gains or losses are reclassified to operating revenues on the Statements of Consolidated Income. If a cash flow hedge is terminated before the settlement date of the hedged item, the amount of other comprehensive income recorded up to that date would remain accrued provided that the forecasted sale remains probable of occurring, and, going forward, the fair value change of the derivative(s) would be recorded in earnings. The Company estimates that $2.2 million of net unrealized gains on its derivative commodity instruments reflected in accumulated other comprehensive income as of September 30, 2002 will be recognized in earnings during the next twelve months due to physical settlement.

The ineffective portion of the change in fair value of the Company’s derivative commodity instruments is recognized in earnings immediately. For the nine months ended September 30, 2002 and 2001, ineffectiveness associated with the Company’s derivative commodity instruments increased earnings by approximately $0.7 million and $0.3 million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.

Interest Rate Swaps

The Company intends to issue between $150 million and $200 million of long-term debt in the fourth quarter of 2002 to pay down commercial paper, which has a maturity of less than 90 days. Consequently, in September 2002, the Company entered into interest rate swap agreements with a notional amount of $150 million to hedge the risk of movement in interest rates from the date of the swap agreements to the date of issuance of the long-term debt. Upon issuance of the long-term debt, the Company intends to terminate these swaps. These swap agreements were designated at inception as being cash flow hedges and were deemed to be effective. The fair value of these swap agreements as of September 30, 2002 was a liability of $0.9 million that is reflected in other current liabilities on the Consolidated Balance Sheets. As these swap agreements were deemed to be effective, the change in their fair value is recorded in accumulated other comprehensive income on the Consolidated Balance Sheets and will be reclassified to interest expense in the period in which the Company’s earnings are impacted by the hedged item.

E. Investments

Investment Securities

Investments classified by the Company as available-for-sale consist of debt and equity securities that are intended to fund plugging and abandonment and other liabilities for which the Company self-insures. The unrealized holding losses related to these securities as of September 30, 2002 total $1.2 million and are included in accumulated other comprehensive income.

Westport Resources Corporation

The Company owns approximately 27% of Westport Resources Corporation (Westport), which it accounts for under the equity method of accounting. The Company’s equity investment in Westport totaled $143.5 million as of September 30, 2002 and is included in equity in non-consolidated investments on the Consolidated Balance Sheets. 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 third quarter 2002 related to these differences.

F. Comprehensive Income

Total comprehensive income for the three and nine months ended September 30, 2002 and 2001 was as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002			2001
	(Thousands)
Net income	$	26,686		$	24,800	$	111,728		$	127,503
Other comprehensive income (loss), net of tax:
Cumulative effect of Statement No. 133 adoption	—			—		—			(37,023		)
Net change in cash flow hedges:
Natural gas (Note D)	10,334			29,027		(69,748		)	130,583
Interest rate (Note D)	(909		)	—		(909		)	—
Unrealized loss on available-for-sale securities (Note E)	(669		)	—		(1,243		)	—
	8,756			29,027		(71,900		)	93,560
Total comprehensive income	$	35,442		$	53,827	$	39,828		$	221,063

G. Stock-Based Compensation

On March 12, 2002, the Company granted 133,000 stock awards from the 1999 Long-Term Incentive Plan for the 2002 Executive Performance Incentive Share Plan. The 2002 Plan was established to provide additional incentive benefits to retain senior executive employees 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 awards will occur on March 12, 2005 and is contingent upon the attainment of certain performance measures and will result in a range of zero to 266,000 shares (200% of the award) being awarded. The Company anticipates, based on current estimates, that the performance measures will be met and has expensed a ratable estimate of the award accordingly. The expense for the three and nine month periods ended September 30, 2002 was $1.7 million and $4.1 million, respectively, and is classified as selling, general and administrative expense.

A restricted stock grant in the amount of 73,800 shares was also awarded to various employees during the first quarter of 2002. The related expense recognized during the three and nine month periods ended September 30, 2002 was $0.1 million, and $0.3 million, respectively, and is classified as selling, general and administrative expense.

Additionally, 1.5 million stock options were awarded during the first half of 2002. 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.

H. Appalachian Basin Partners, LP (ABP)

In November 1995, the Company monetized certain Appalachian gas properties to a partnership, Appalachian Basin Partners, LP (ABP), the production from which qualifies for the nonconventional fuels tax credit. The Company treated the proceeds from the deal as monetized production, and consequently recognized all of the activity from the partnership in the Company’s Statements of Consolidated Income and reduced the deferred revenue balance established from the receipt of the proceeds by the cash payments made to the other partners as production occurred. The Company also retained a partnership interest in the properties that increased substantially at the end of 2001 to 69% when a performance target was met. Consequently, beginning in 2002, the Company no longer includes ABP volumes as monetized sales, but instead as equity production sales. As a result, monetized volumes sold decreased by 6.5 Bcf during the nine months ended September 30, 2002, while equity production volumes increased by the same amount. Additionally, beginning January 1, 2002, the Company consolidated the partnership with the portion not owned by the Company recorded as a minority interest. The minority interest expense recognized for the three and nine months ended September 30, 2002 was $1.8 million and $5.2 million, respectively, and is included within minority interest other in the Statements of Consolidated Income. The minority interest expense includes additional expense to provide for items in dispute between the partners. The sales volumes attributed to the minority interest owners for the three and nine months ended September 30, 2002, were 0.8 Bcf and 2.1 Bcf, respectively.

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 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 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 is scheduled to expire at the end of 2002.

J. Discontinued Operations

In April 1998, management adopted a formal plan to sell the Company’s natural gas midstream operations. A capital loss was treated as a nondeductible item for tax reporting purposes under the then current Treasury regulations embodying the “loss disallowance rule,” resulting in additional tax recorded on this sale as a reduction to net income from discontinued operations. In May 2002, the IRS issued new Treasury regulations interpreting the “loss disallowance rule” that now permit this capital loss to be treated as deductible. During June 2002, the Company filed amended tax return filings. Consequently, in the second quarter 2002, the Company recorded a $9.0 million increase in net income from discontinued operations related to this unexpected tax benefit.

K. New Accounting Pronouncements

Business Combinations

In July 2001, the FASB issued Statement No. 141, “Business Combinations,” which is effective for fiscal year 2002. Statement No. 141 eliminates the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and further clarifies the criteria to recognize intangible assets separately from goodwill. The implementation of this Statement had no impact on the Company’s consolidated financial statements for nine months ended September 30, 2002.

Goodwill and Other Intangible Assets

In July 2001, the FASB also 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 Company’s goodwill balance as of January 1, 2002 totaled $57.4 million and is entirely related to the NORESCO segment. 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 $0.09 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 expects to perform the required annual test of the carrying value of goodwill for impairment during the fourth quarter 2002.

Had the Company been accounting for its goodwill under Statement No. 142 for all prior periods presented, the Company’s net income and diluted earnings per share for the nine months ended September 30, 2002 and 2001 would have been as follows:

	Net Income (in millions)				Diluted EPS
	2002		2001		2002		2001
Net income	$	111.7	$	127.5	$	1.73	$	1.93
Add goodwill amortization	—		2.9		—		.04
Adjusted net income	$	111.7	$	130.4	$	1.73	$	1.97

Net income for the three months ended September 30, 2001 would have been $0.9 million, or $0.01 per diluted share, higher if goodwill amortization had been discontinued effective January 1, 2001.

Asset Retirement Obligations

In July 2001, the FASB also issued Statement No. 143, “Accounting for Asset Retirement Obligations,” which will be effective for fiscal year 2003. This Statement requires asset retirement obligations (ARO) to be measured at fair value and to be recognized at the time the obligation is incurred. Management is currently assessing this Statement and has not yet determined the impact that the implementation of this Statement will have, if any, on the earnings and financial position of the Company.

Accounting for the Impairment or Disposal of Long-Lived Assets

Effective January 1, 2002, the Company adopted Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” This Statement supercedes or amends existing accounting literature related to the impairment and disposal of long-lived assets.

In accordance with Statement No. 144, whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets.

During the second quarter 2002, the Company reviewed the Jamaica power plant project related to the NORESCO operating segment for impairment as the project had not been operating to expected levels and remediation efforts were unsuccessful. The Company owns 91.2% of the equity in the project and therefore consolidates the project in its financial statements. As a result of the Company’s review, an impairment loss of $5.3 million was recorded to adjust the project assets to their fair value. Fair value was based on the expected future cash flows to be generated by the Jamaican power plant, discounted at the risk-free rate of interest.

Income Statement Presentation of Gains and Losses on Energy Trading Contracts

In June 2002, the FASB’s Emerging Issues Task Force (EITF) issued EITF 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 02-3 is effective for financial statements issued for periods ending after July 15, 2002 and requires that gains and losses on energy trading contracts be recorded net on a company’s income statement.

Prior to this guidance, the Company was required to report the gains and losses on its energy trading contracts (as defined in EITF 98-10) gross on its Statements of Consolidated Income. As a result of this guidance, in the third quarter 2002, the Company has classified all gains and losses on its energy trading contracts net on its Statements of Consolidated Income for all periods presented. 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 and nine months ended September 30, 2002 and 2001, of $81.9 million and $271.4 million, and $77.9 million and $692.2 million, respectively.

On October 25, 2002, the FASB’s Emerging Issues Task Force reached a consensus to rescind EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As a result, only energy contracts that meet the definition of a derivative in Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, will be carried at fair value. The EITF also issued a consensus to expand EITF 02-3’s requirement to classify gains and losses on energy trading contracts net on a company’s income statement to include all derivative contracts that are entered into for trading purposes. The EITF’s consensus is to be applied to all contracts entered into after October 25, 2002. For any contracts existing 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. Management is currently assessing the impact of this consensus and has not yet determined the impact that the implementation of this consensus will have on the earnings and financial position of the Company.

L. Reclassification

Certain previously reported amounts have been reclassified to conform to the 2002 presentation.

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 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. Forward looking statements include, among other things, statements regarding the results that may be expected for the year ending December 31, 2002, the amount of long term debt to BE ISSUED in the fourth quarter of 2002, the expectation that the performance requirements will be met for the Executive Performance Share Plan, the implementation of the Equitable Gas Company customer information and billing system, the approval by FERC of the merger of Equitrans’ assets and operations with the assets and operations of Carnegie Pipeline, the value of the Company’s 45% interest in a Panamanian power Plant after the expiration of its power purchase agreement in February 2003, the expected operational and financial improvements in a Panamanian power plant in which the Company has a 50% interest including the expected cost to resolve noise issues , the strategic alternatives for the Company’s Jamaica power plant, the expectation through hedging to provide price protection for the majority of the company’s expected production from 2002 through 2005 and for over 25% of expected equity production for the years 2006 through 2008, the belief that the ultimate outcome of any claims or legal proceedings against the Company including the civil lawsuit in Knott County Circuit Court Kentucky will not materially affect the financial position of the Company, the belief that environmental expenditures will not be significantly different in nature or amount in the future and will not have a material effect on the Company’s financial position or results of operations, the total pension expense expected to be recognized in 2002 and 2003, the potential effect of the Financial Accounting Standards Board Exposure Draft on “Consolidation of Certain Special Purpose Entities” would have on the Company if it became final, the effect of a decrease of 10% in the market price of natural gas would have on the fair market value derivative contracts held by the Company for hedging or trading purposes, and other financial and operational matters. The Company notes that 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 future changes in the hedging strategy, creditworthiness of counterparties, availability 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 effect of acts of terrorism, the ability of the Company to obtain insurance at reasonable prices, 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 avoid or resolve labor union disputes, insurance coverage, insurance, litigation, compliance activities and costs, 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 from time to time.

OVERVIEW

Equitable Resources’ consolidated net income for the quarter ended September 30, 2002 totaled $26.7 million, or $0.42 per diluted share, compared to $24.8 million, or $0.38 per diluted share, reported for the same period a year ago. Excluding equity earnings associated with Westport Resources, the Company reported total earnings per diluted share of $0.42 on net income of $26.5 million for the quarter ended September 30, 2002 as compared to earnings per diluted share of $0.32 on net income of $21.2 million for the quarter ended September 30, 2001. The increase in net income excluding equity earnings from Westport Resources is principally the result of an after-tax increase in segment earnings and a $0.8 million reduction in interest expense. The after-tax increase in segment earnings is primarily the result of non-recurring charges related to compressor station automation and a lease buyout in the third quarter 2001 at Equitable Utilities; an overall volume increase at Equitable Production; and the termination of a demand side management program, an increase in operations and construction revenue and the elimination of goodwill amortization in 2002 as a result of Statement No. 142 at NORESCO.

RESULTS OF OPERATIONS

In July 2001, Equitrans, L.P., a subsidiary of the Company within the Equitable Utilities segment, filed an order with the Federal Energy Regulatory Commission (FERC) to transfer five natural gas pipeline gathering systems located in West Virginia and Pennsylvania to a subsidiary of the Company within the Equitable Production segment. In February 2002, the FERC approved the order that resulted in the transfer of the gathering systems. The transfer was effective January 1, 2002 for segment reporting purposes. The systems transferred consist of approximately 1,300 miles of low pressure, small diameter pipeline and related facilities used to gather gas from wells in the region. The effect of this transfer is not material to the results of operations or financial position of Equitable Resources. Additionally, the effect of this transfer is not material to the results of operations or financial position of the Equitable Utilities or Equitable Production segments. Therefore, segment results have not been restated for this transfer.

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.

During the third quarter 2002, the Company classified 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 September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001

OPERATIONAL DATA

Capital expenditures (thousands)	$	25,865		$	9,265		$	48,170		$	26,002

Total expenses/net revenues (%)	90.23		%	94.39		%	56.62		%	65.79		%

FINANCIAL RESULTS (Thousands)

Utility revenues	$	35,112		$	40,495		$	226,964		$	318,423
Marketing revenues	43,677			42,623			128,570			210,537
Total operating revenues	78,789			83,118			355,534			528,960

Purchased gas costs and revenue related taxes	44,594			47,615			189,807			362,457
Net operating revenues	34,195			35,503			165,727			166,503

Operating and maintenance expense	13,079			13,133			37,299			42,780
Selling, general and administrative expense	10,900			13,205			36,552			46,900
Depreciation, depletion and amortization	6,876			7,174			19,981			19,864
Total expenses	30,855			33,512			93,832			109,544

EBIT	$	3,340		$	1,991		$	71,895		$	56,959

Three Months Ended September 30, 2002

vs. Three Months Ended September 30, 2001

Net operating revenues decreased $1.3 million, or 4% for the three months ended September 30, 2002 compared to the prior year quarter. The decrease in net operating revenues is primarily attributable to the transfer of five natural gas pipeline gathering systems to Equitable Production earlier in 2002. Total expenses for the quarter were $30.9 million compared to the $33.5 million reported during the same period last year. After adjusting for $1.7 million in charges related to compressor station automation and a lease buyout in September 2001, total expenses for Equitable Utilities were down $0.9 million or 3% due to ongoing cost reduction initiatives. There were also two significant offsetting factors that impacted total expense at Equitable Utilities in the third quarter; a $1.0 million increase in pension related expense and a $1.0 million cost savings from the transfer of the gathering assets mentioned above.

Nine Months Ended September 30, 2002

vs. Nine Months Ended September 30, 2001

Net operating revenues decreased slightly by $0.8 million in 2002 compared to the nine months ended September 30, 2001. The decrease is related to lower distribution net operating revenues from warm temperatures primarily in the first quarter 2002 offset by improved marketing operations margins. The improved margins were a result of the Company’s decision to focus on storage and asset management activities and de-emphasize the low margin trading-oriented activities.

EBIT increased 26% to $71.9 million for the current period compared to $57.0 million for the same period in 2001. The segment’s results for 2001 included one-time charges related to a workforce reduction of $4.3 million during the second quarter and the previously described $1.7 million third quarter charge associated with the compressor automation and lease buyout. Excluding these one-time charges, EBIT increased $8.9 million or 14% due principally to ongoing cost reduction initiatives and improved marketing margins.

Distribution Operations

Rates and Regulatory Matters

The local distribution operations of Equitable Gas Company (Equitable Gas), a division of the Company, provides natural gas services in southwestern Pennsylvania and to municipalities in northern West Virginia. In addition, Equitable Gas provides field line sales 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 Resources 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 Resources 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 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 Resources. 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 Company’s Low Income Balance Reduction Program. The program allows eligible customers to make payments exceeding their current bill amount and receive matching credits from Equitable Resources to reduce the customer’s delinquent balance. The program will be fully funded through customer contributions and a surcharge in rates.

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

Other

Equitable Gas Company is in the process of implementing a new customer information and billing system for which the Company has incurred $5.5 million of capital expenditures from project inception through September 30, 2002. Based upon the information currently available to management, the implementation is expected to be successfully completed by the end of 2003. Total capital expenditures for this project are expected to significantly exceed the original estimate.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002		2001
OPERATIONAL DATA

Degree days (normal = Qtr – 120, YTD – 3,848)	35			135			3,076		3,457

O & M, and SG&A (excluding other taxes) per customer	$	58.69		$	54.98		$	189.89	$	202.17

Volumes (MMcf)
Residential	1,772			1,804			16,864		17,997
Commercial and industrial	4,778			3,385			21,340		17,991
Total gas sales and transportation	6,550			5,189			38,204		35,988

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	19,438		$	19,395		$	107,182	$	112,121

Operating expenses	16,481			15,834			53,560		57,323
Depreciation and amortization	5,076			4,980			14,812		13,569

EBIT (Losses before interest and taxes)	$	(2,119	)	$	(1,419	)	$	38,810	$	41,229

Three Months Ended September 30, 2002

vs. Three Months Ended September 30, 2001

Net operating revenues for the September 2002 quarter increased slightly from the 2001 period. This increase is due to commercial customer sales offset by the decrease in revenue caused by the warmer weather. Commercial and industrial volumes were 41% higher than the same quarter last year primarily due to increased domestic steel industry throughput. The margin from large industrial business is low, and consequently the increase in volume had no material impact on the quarter’s results.

Total expenses of $21.6 million for the 2002 quarter increased compared to the September 2001 quarter’s total expenses of $20.8 million. The increased operating costs were primarily due to increased pension and post-retirement benefits expense as compared to the prior year.

Nine Months Ended September 30, 2002

vs. Nine Months Ended September 30, 2001

Net operating revenues for the nine months ended September 30, 2002, decreased to $107.2 million from $112.1 million, or 4% from the same period last year. Weather in the distribution service territory for the nine months ended September 30, 2002 was 20% warmer than normal and 11% warmer than last year, primarily associated with warm temperatures in the first quarter 2002. Residential volumes decreased 6% from prior year, while commercial and industrial volumes increased 19% in the current year. Despite the increase in commercial and industrial volumes, net operating revenues did not proportionately increase due to the relatively low margins on industrial customer volumes.

Operating expenses for the nine months ended September 30, 2002 decreased $3.8 million, or 7%, from the same period in 2001. The decrease in operating expenses is related to a reduction in the provision for bad debts attributable to lower gas prices and warmer weather in the current year, and from continued process improvement initiatives.

Pipeline Operations

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. The Company anticipates approval of the merger by the first quarter 2003.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001

OPERATIONAL DATA

Transportation throughput (MMbtu)	18,035		16,319		56,725		53,095

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	12,079	$	13,623	$	41,607	$	44,726

Operating expenses	6,666		8,351		17,701		26,579
Depreciation and amortization	1,698		2,089		4,860		6,042

EBIT	$	3,715	$	3,183	$	19,046	$	12,105

Three Months Ended September 30, 2002

vs. Three Months Ended September 30, 2001

As previously disclosed, Equitrans transferred five natural gas pipeline gathering systems located in West Virginia and Pennsylvania to the Equitable Production business segment. The transfer, effective January 1, 2002 for segment reporting purposes, resulted in a reduction in net operating revenues of $1.1 million, and a $1.0 million reduction in operating costs for the quarter. Excluding the impact of the transfer of the gathering assets, net operating revenues for the three months ended September 30, 2002 decreased $0.4 million compared to 2001.

Transportation throughput increased significantly over the prior year quarter. This change resulted from increased demand from the Distribution segment’s commercial and industrial customers as well as new third party firm transportation contracts. Because the margin from this service is generally derived from fixed monthly fees, the impact on net operating revenues from the increased volumes is minimal.

Operating expenses were $6.7 million for the 2002 quarter compared to $8.4 million for the 2001 quarter, a decrease of $1.7 million. As previously described, the 2001 operating expenses included a one-time $1.7 million charge related to the pipeline operations compressor automation and lease buyout and included $1.0 million for gathering operation costs. Excluding these items, normalized operating expenses were $6.7 million in the 2002 quarter as compared to $5.7 million for the same quarter a year ago. The increased operating costs were primarily due to increased pension expense and planned pipeline maintenance expenses.

Nine Months Ended September 30, 2002

vs. Nine Months Ended September 30, 2001

Excluding the net operating revenue impact of the transfer of the gathering assets of $2.8 million, net operating revenues for the nine months ended September 30, 2002, were $41.6 million compared to $41.9 million for the same period in 2001.

Excluding a $4.3 million one-time charge for workforce reductions and a $1.7 million charge for compressor automation and lease buyout in 2001 and the $2.2 million reduction of operating costs in 2002 due to the transfer of gathering assets, operating expenses declined by $0.7 million, or 4%, to $17.7 million. The decrease in operating costs resulted from the ongoing savings realized from workforce reductions, compressor station automation and lease buyout, offset by higher pension and planned maintenance costs.

Equitable Marketing

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001

OPERATIONAL DATA
Marketed gas sales (MMbtu)	37,400		39,645		125,473		170,052

Net operating revenues/MMbtu	$	0.0615	$	0.0627	$	0.1268	$	0.0568

FINANCIAL RESULTS (Thousands)
Net operating revenues	$	2,678	$	2,485	$	16,938	$	9,656

Operating expenses	832		2,154		2,590		5,778
Depreciation and amortization	102		104		309		253
EBIT	$	1,744	$	227	$	14,039	$	3,625

Three Months Ended September 30, 2002

vs. Three Months Ended September 30, 2001

During 2001, the Company announced its decision to focus on storage and asset management and de-emphasize low margin high volume trading revenues which has resulted in sharply lower sales volumes. The marketing net operating revenues for the current quarter were essentially flat compared to the prior year, reflecting the low-margin contribution of trading oriented activities.

Operating expenses for the current quarter of $0.8 million decreased 61% from the 2001 quarter. The reduction is due to cost reduction initiatives associated with the Company’s decision to de-emphasize the low margin trading-oriented activities and from a decreased provision for bad debts attributable to lower gas prices compared to the prior year.

Nine Months Ended September 30, 2002

vs. Nine Months Ended September 30, 2001

Net operating revenues for the nine months ended September 30, 2002 increased $7.3 million, or 75% from the same period last year. Excluding the prior year one-time losses of $2.6 million on transactions marked to market that were previously treated as hedges, the net operating revenues increased $4.7 million. This increase in net operating revenues and in unit marketing margins versus the same period last year is a result of the Company’s decision to focus on storage and asset management activities and de-emphasize the low margin trading-oriented activities.

Operating expenses for the nine month period decreased by $3.2 million, or 55% from the nine months ended September 2001. The decrease is also due to cost reduction initiatives associated with the Company’s decision to de-emphasize the low margin trading-oriented activities and from a decreased provision for bad debts attributable to lower gas prices compared to the prior year.

EQUITABLE PRODUCTION

Equitable Production develops, produces and sells natural gas and crude oil, with operations in the Appalachian region of the United States. It also engages in natural gas gathering and the processing and sale of natural gas and natural gas liquids.

In December 2001, the Company sold its oil-dominated fields in order to focus on natural gas activities. The sale resulted in a decrease of 63.0 Bcfe of proved developed producing reserves and 5.0 Bcfe of proved undeveloped reserves for proceeds of approximately $60.0 million. The field produced approximately 3.7 Bcfe annually. Although the Company will no longer operate these properties, it will continue to gather and market the natural gas produced, which resulted in approximately $1.2 million in service revenue through the first three quarters of 2002.

Plugging and abandonment (P&A) activities represent unavoidable costs of production. In accordance with current accounting literature, Equitable Production recognizes annual P&A charges as a component of depreciation, depletion, and amortization (DD&A) expense with a corresponding credit to accumulated depletion. Upon adoption of the new accounting pronouncement, Statement No. 143, on January 1, 2003, Equitable Production will no longer record such P&A costs as a component of DD&A expense. Rather, an asset retirement obligation (ARO) liability and corresponding capitalized retirement cost will be recorded. The ARO liability, which represents the present value of the estimated future P&A costs, will be accreted over the life of the associated wells. This accretion expense will be reflected within operating expenses. In addition, the capitalized retirement cost will be expensed over the life of the associated wells using the units-of-production depreciation method. Management is currently assessing this Statement and has not yet determined the impact that the implementation of this Statement will have, if any, on the earnings and financial position of the Company.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002			2001
OPERATIONAL DATA

Production:
Net equity sales, natural gas and equivalents (MMcfe)	12,128			9,459		34,861			28,052
Average (well-head) sales price ($/Mcfe)	$	3.44		$	3.28	$	3.39		$	3.98

Monetized sales (MMcfe)	3,549			5,676		10,530			17,056
Average (well-head) sales price ($/Mcfe)	$	3.27		$	3.55	$	3.26		$	3.98

Weighted average (well-head) sales price ($/Mcfe)	$	3.40		$	3.38	$	3.36		$	3.98

Company usage (MMcfe)	1,944			1,854		4,731			4,336

Lease operating expense excluding severance tax ($/Mcfe)	$	0.26		$	0.29	$	0.27		$	0.33
Severance tax ($/Mcfe)	$	0.12		$	0.13	$	0.11		$	0.18
Depletion ($/Mcfe)	$	0.39		$	0.38	$	0.39		$	0.38

Production Services:
Gathered volumes (MMcfe)	30,726			26,906		90,258			79,326
Average gathering fee ($/Mcfe)	$	0.52		$	0.56	$	0.51		$	0.58
Gathering and compression expense ($/Mcfe)	$	0.19		$	0.24	$	0.19		$	0.23
Gathering and compression depreciation ($/Mcfe)	$	0.09		$	0.10	$	0.09		$	0.10

Total operated volumes (MMcfe)	23,366			23,576		68,163			69,105
Volumes handled (MMcfe)	34,181			30,955		99,349			89,978
Selling, general and administrative ($/Mcfe handled)	$	0.19		$	0.16	$	0.18		$	0.20

Operating costs per unit (includes LOE, G&C, and SG&A expenses)	$	0.64		$	0.69	$	0.64		$	0.76

Capital expenditures (thousands)	$	41,483		$	29,571	$	105,530		$	56,831

FINANCIAL RESULTS (Thousands)

Revenue from production	$	53,272		$	51,117	$	152,415		$	179,639
Services:
Revenue from gathering fees	15,830			15,032		45,837			45,844
Other revenues	2,930			2,174		8,210			8,883
Total revenues	72,032			68,323		206,462			234,366

Gathering and compression expenses	5,754			6,336		17,530			17,916
Lease operating expense	4,525			4,993		13,534			16,227
Severance tax	2,045			2,154		5,425			9,042
Depreciation, depletion and amortization	10,301			9,387		29,771			28,254
Selling, general and administrative	6,539			5,006		17,526			18,000
Exploration, including dry hole expense	176			528		628			1,630
Total operating expenses	29,340			28,404		84,414			91,069

Equity earnings from nonconsolidated investments and minority interest	(1,717		)	115		(4,998		)	660

EBIT	$	40,975		$	40,034	$	117,050		$	143,957

Three Months Ended September 30, 2002

vs. Three Months Ended September 30, 2001

Equitable Production’s EBIT for the three months ended September 30, 2002, was $41.0 million, 2.5% higher than the $40.0 million earned for the three months ended September 30, 2001. The increase in the segment’s results was primarily attributable to an overall volume increase due to the increased developmental drilling program ($5.5 million) and increased gathering and service revenues partially offset by a reduction in sales volume due to the oil field sale in December 2001 ($3.6 million), increased minority interest expense of $1.8 million due to the transition of ABP noted in the previous section and an increase in depletion and general and administrative costs.

Total revenues for the third quarter 2002 increased 5% to $72.0 million compared to $68.3 million in 2001. Overall sales volumes increased 0.5 Bcfe, despite the production volumes (1.0 Bcfe) lost due to the December 2001 oil field sale. Excluding the effects of the oil field sale, comparable volumes were up 1.5 Bcfe, or 10% due to new drilling and production enhancements. In addition, the Company’s weighted average well-head sales price realized on produced volumes of $3.40 per Mcfe compared to $3.38 per Mcfe for the same period last year ($0.3 million).

Total operating expenses for the three months ended September 30, 2002 were $29.3 million compared to $28.4 million last year, representing a 3% increase. This 3% increase is primarily due to depletion costs attributed to increased volumes ($0.9 million), legal and insurance costs ($0.9 million) and increased staff in the gathering business ($0.4 million). These factors were partially offset by reduced third-party gathering costs and other operating efficiencies ($1.3 million). Operating costs per Mcfe, consisting of lease operating expense, gathering and compression expense and selling, general and administrative expense, decreased from $0.69 to $0.64, a 7% reduction.

Nine Months Ended September 30, 2002

vs. Nine Months Ended September 30, 2001

Equitable Production’s EBIT for the nine months ended September 30, 2002, was $117.1 million, 19% lower than the $144.0 million earned for the nine months ended September 30, 2001. The segment’s results were negatively affected by lower commodity prices, which resulted in a decrease of $24.4 million, increased minority interest expense of $5.2 million due to the ABP transition, and the loss of volumes associated with the December 2001 oil field sale. These factors were partially offset by increased sales volume due to increased developmental drilling and lower operating costs.

During the nine months ended September 30, 2002, revenues declined $27.9 million, or 12%, from $234.4 million to $206.5 million, primarily due to lower market prices for gas. The Company’s weighted average well-head sales price realized on produced volume fell to $3.36 per Mcfe, compared to $3.98 per Mcfe in the same period in 2001, which represented a 16% decline. The overall production volume increase was a result of new drilling and production enhancements (3.5 Bcfe), partially offset by sales volumes lost in the December 2001 oil field sale (3.2 Bcfe).

Total operating expenses were $84.4 million compared to $91.1 million for the nine months ended September 30, 2002. This 7% reduction was primarily due to reductions in lease operating expenses, severance taxes and selling, general and administrative expenses. Lease operating expense and selling, general and administrative expense reductions are a result of continued operating efficiency improvements, while severance taxes are primarily lower due to declines in the weighted average well-head sales price. Operating costs per Mcfe, consisting of lease operating expense, gathering and compression expense and selling, general and administrative expense, decreased from $0.76 to $0.64, a 16% reduction.

NORESCO

NORESCO provides energy-related systems and services that are designed to reduce its customers’ operating costs and to improve their productivity. The segment’s activities are comprised of energy infrastructure projects including on-site power generation and central boiler/chiller plant, design, construction, and operation; performance contracting; and energy efficiency programs. NORESCO’s customers include governmental, institutional, military, and industrial end-users. NORESCO’s energy infrastructure group has investments in several power plants in the United States, Panama, Costa Rica, and Jamaica.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
OPERATIONAL DATA

Revenue backlog, end of period (thousands)	$	148,769		$	142,383		$	148,769		$	142,383
Construction completed (thousands)	$	36,601		$	26,529		$	88,823		$	68,738

Capital expenditures (thousands)	$	271		$	76		$	635		$	405

Gross profit margin	22.4		%	22.0		%	22.8		%	23.7		%
SG&A as a % of revenue	12.4		%	17.2		%	13.1		%	16.9		%
Project development expenses as a % of revenue	2.0		%	1.4		%	2.4		%	2.3		%

FINANCIAL RESULTS (Thousands)

Energy service contract revenues	$	54,209		$	40,312		$	136,142		$	110,087
Energy service contract costs	42,069			31,444			105,070			83,965
Net operating revenues	12,140			8,868			31,072			26,122

Selling, general and administrative expenses	6,701			6,941			17,789			18,632
Impairment of long-lived asset, net	—			—			5,320			—
Amortization of goodwill	—			937			—			2,854
Depreciation and depletion	367			535			1,248			1,485
Total expenses	7,068			8,413			24,357			22,971

Equity earnings from nonconsolidated investments	715			1,019			2,660			5,778

EBIT	$	5,787		$	1,474		$	9,375		$	8,929

Three Months Ended September 30, 2002

vs. Three Months Ended September 30, 2001

NORESCO’s EBIT increased $4.3 million to earnings of $5.8 million from earnings of $1.5 million in the same period last year. This increase in EBIT is primarily attributable to $2.4 million in gross margin from the termination of a demand side management program and an increase in operations and construction revenue. Total revenue increased by 34.5% to $54.2 million, compared to $40.3 million in 2001.

Revenue backlog in the current year increased slightly by $6.4 million from $142.4 million on September 30, 2001 to $148.8 million on September 30, 2002.

NORESCO’s third quarter 2002 gross margin increased to $12.1 million compared to $8.9 million during the third quarter 2001. Net of the demand side management program termination, gross profit margin decreased as a percentage of revenue from 22.0% in the third quarter 2001 to 19.2% in the third quarter 2002 due to an increased construction mix of larger projects with lower gross margins.

Equity in earnings from power plant investments during the third quarter 2002 declined to $0.7 million from $1.0 million during the third quarter 2001. This reduction is primarily due to lower equity in earnings from power plants in Panama and Rhode Island.

Total expenses were $7.1 million for the third quarter 2002 versus $8.4 million for the same period in 2001. Included in third quarter 2002 was a $1.0 million charge for a reduction in force and office closure. In the same period of 2001, there were $1.8 million in charges for office consolidation and bad debt. Net of these adjustments in both periods and $0.9 million of goodwill amortization in 2001, total costs increased $0.4 million. After adjusting for 2002 and 2001 non-recurring charges, SG&A as a percentage of revenue decreased to 10.5% versus 12.8% for the same period last year.

Nine Months Ended September 30, 2002

vs. Nine Months Ended September 30, 2001

NORESCO’s EBIT increased $0.5 million to $9.4 million from $8.9 million in the same period last year. This increase is primarily attributable to increases in operations and construction activity. Other items also contributing to the increase include a demand side management program termination that contributed $2.4 million to gross margin, a reduction in goodwill amortization of $2.9 million and $1.8 million in charges for office consolidation and bad debt in the third quarter 2001. These items were offset by the write-off of $5.3 million for the Jamaica power plant and $3.1 million in lower equity in earnings from power plant investment projects.

Revenue increased by 23.7% to $136.1 million compared to $110.1 million in 2001, primarily due to an increase in construction activity resulting from an increase in construction backlog at the beginning of 2002 of $128 million versus $91 million at the beginning of 2001. While construction activity increased substantially, revenue backlog increased by $6.4 million from $142.4 million on September 30, 2001 to $148.8 million on September 30, 2002, due to increased sales volumes during the period.

NORESCO’s gross margin increased to $31.1 million compared to $26.1 million during the first nine months of 2001 due to the demand side management program termination of $2.4 million and increases in both operations and construction activity totaling $2.6 million. Net of the demand side management program termination, gross margin as a percentage of revenue decreased to 21.7% in the first nine months of 2002 compared to 23.7% during the same period in 2001. Gross margins fluctuate on a quarterly basis based on the gross margin mix of the construction completed for the period and operations and maintenance gross margins.

NORESCO invested $7.4 million, for a 91% ownership stake, in a greenfield power plant project in Jamaica in 1998. The plant has not operated at expected levels and remediation efforts have been ineffective. As a result, in the second quarter, the Company wrote off its entire remaining investment in the project totaling $5.3 million in accordance with Statement No. 144.

Equity in earnings from power plant investments during the nine months ended September 30, 2002 declined $3.1 million to $2.7 million from $5.8 million during the first nine months of 2001. This reduction is primarily due to reduced equity in earnings from power plants in Panama and Rhode Island.

Total expenses, including the Jamaica power plant write-down, were $24.4 million versus $23.0 million for the same period in 2001. Excluding the Jamaica write-down of $5.3 million and the $1.0 million charge for reduction in force and office closure in 2002 and the elimination of $2.9 million of goodwill amortization and $1.8 million for office consolidation and bad debt in 2001, total expenses decreased slightly to $18.1 million compared to $18.3 million in the same period in 2001.

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 accounts 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. Equitable Resources continues to own 13.9 million shares, which represents approximately 27% of Westport’s total shares outstanding at September 30, 2002. Equitable Resources’ investment in Westport was $143.5 million as of September 30, 2002 and the aggregate market value of this investment was approximately $254 million as of September 30, 2002. The Company has recognized a loss of $4.6 million year to date classified as equity earnings from nonconsolidated investments in the Statements of Consolidated Income on its equity investment in Westport.

As discussed in the 2001 Annual Report, the Production segment sold an interest in oil and gas properties to a partnership, Eastern Seven Partners, L.P. The Company retained a 1% interest and negotiated arms-length, market-based rates for gathering, marketing and operating fees with the partnership in order to deliver its natural gas to the market. The Company treats oil and gas partnership interests as equity in nonconsolidated investments.

Also discussed in the 2001 Annual Report, the Production segment sold an interest in oil and gas properties to a trust, Appalachian Natural Gas Trust (ANGT). The Company retained a 1% interest and has separately negotiated arms-length, market-based rates with ANGT for gathering, marketing and operating fees to deliver their natural gas to the market. Additionally, the Company has given, 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. The Company treats its interest in ANGT as equity in nonconsolidated investments.

The NORESCO segment has equity ownership interests in independent power plant projects located domestically and in selected international countries. All of these projects sell the majority of their output under long-term power purchase agreements (PPA) with customers who agree to purchase the energy generated by the plant. The length of these contracts range from 5 to 30 years. These projects generally are financed on a project basis with non-recourse financings established at the foreign subsidiary level.

In 2001, one of the Company’s domestic power plant projects for which the Company owns a 50% interest, Capital Center Energy, began incurring 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 document covenant violations, particularly if resolution of the issue is further delayed. NORESCO's equity interest in this non-recoursed financed project is $3.9 million.

One of the Company’s two Panamanian projects, for which the Company owns a 45% interest, is a party to a five-year PPA, which expires in February 2003. Contemporaneous with the expiration of the PPA, the debt on the project will be fully paid. The Company believes the project has value beyond the term of its PPA and is actively pursuing new PPA’s for the project. New fixed capacity contracts are awarded each year for terms ranging from one to five years. The Company expects to make a decision by year-end on whether to enter into long-term off-take arrangements or sell power into the market.

The Company owns a 50% interest in a second Panamanian electric generation project. The project had previously agreed to retrofit a 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 regulators while it evaluates a land acquisition/rezoning proposal, which, if accepted and executed, would obviate the 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. The expected additional Company cost 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 project has experienced poor financial performance during the first half of 2002 due to adverse weather (abnormally high rainfall), other adverse market-related conditions, and reduced plant availability related to planned and unplanned outages during the first quarter. These factors temporarily 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 third quarter 2002 has experienced improvement in operational and financial performance. Continued operational and financial improvement is expected through the end of 2002. Despite the debt service coverage ratio issues, cashflow and payment of debt service are expected to be adequate through 2003.

CAPITAL RESOURCES AND LIQUIDITY

Operating Activities

Cash flows provided by operating activities totaled $189.7 million, a $74.0 million increase from the $115.7 million recorded in the prior year period. The increase is primarily the result of the effect of the movement in commodity prices in 2002 as compared to 2001 on working capital items and other assets and liabilities in addition to a decrease in two non-cash related items included in net income. The two items are a $29.9 million decrease in monetized production revenue that is primarily the result of the fact that ABP sales were recorded as monetized sales in 2001 but have been recorded as equity production sales in 2002, and a $24.0 million decrease in undistributed earnings from nonconsolidated investments that is primarily the result of decreased earnings recognized by Westport.

Investing Activities

Cash flows used in investing activities in the first nine months of 2002 were $91.2 million compared to $75.8 million in the prior year. The change from the prior year is primarily attributable to an increase in capital expenditures of $71.8 million, offset by a decrease in restricted cash. Capital expenditures in both years represent growth projects in the Equitable Production segment, and replacements, improvements and additions to plant assets in the Equitable Utilities segment. Production and Utilities accounted for approximately $106 million and $48 million, respectively, of the expenditures in 2002. Additionally, proceeds relating to the sale of oil-dominated fields within the Production segment had been held in a restricted cash account at December 31, 2001 for use in a like kind exchange for certain identified assets. During 2002, the restrictions lapsed and the cash has been made available for operations.

On July 18, 2002, the Board of Directors of the Company increased the capital budget by $4.0 million. Specifically, the capital budget of the Production segment was increased by $14.0 million for acceleration of a well automation project and infrastructure improvements. The Board also reduced the capital budget of NORESCO by $10.0 million. NORESCO contemplated investing this capital in domestic energy infrastructure projects, which have not materialized due to weak economic conditions.

Financing Activities

Cash flows used in financing activities during the first nine months of 2002 were $121.4 million compared to $91.7 million in the prior year period. The increase is primarily the result of a reduction in proceeds received from financial institutions associated with the transfer of contract receivables during 2002. Excluding proceeds received from the transfer of contract receivables, cash flows used in financing activities during 2002 were relatively consistent with 2001 and primarily related to Equitable Resources 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, 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. The Company is exploring various strategic alternatives including the sale of the Company’s interest in the project.

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 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 September 30, 2002, the Company has the authority to arrange for a commercial paper program up to $650 million.

Hedging

In addition to the interest rate hedges previously discussed, 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 almost nil for the remainder of 2002 and about $0.01 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 September 30, 2002, the Company hedged approximately 5 Bcf of natural gas basis exposure through March 2004.

Commitments and Contingencies

On October 17, 2002, a jury verdict was rendered against the Company in a civil lawsuit in Knott County Circuit Court, Kentucky. The plaintiff claimed that a well pump house accident that injured him was caused by the Company’s natural gas well adjacent to his property. The jury entered a verdict for $50,000 for medical expenses and lost wages and $270 million for pain and suffering and punitive damages. Although the Company is insured, it considers the claim to be without merit and will vigorously pursue all post-verdict motions and appellate remedies. There is a possibility, although deemed unlikely, that the Company may be required to provide cash to support a portion of the bond during the appeals process.

There are various other claims and legal proceedings against the Company arising from 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 meritous defenses to any claims and intends to pursue them vigorously. Management 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 although they could be material to the reported results of operations for the period in which they occur.

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. This is expected to result in additional contributions to the Company’s pension plan over the next two fiscal years. Additionally, this has contributed to a steady increase in the amount of pension expense recognized by the Company as a result of a lower asset base, an increase in the amount of unrecognized actuarial losses, and decreases to the expected rate of return on pension plan assets. Total pension expense recognized by the Company in 2001, excluding special termination benefits and curtailment losses, totaled $3.8 million. Total pension expense expected to be recognized by the Company in 2002, exclusive of any special termination benefits and curtailment losses, totals $4.2 million and is expected to increase by over $1.5 million in 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 1.5 million stock option grant awarded during the nine months ended September 30, 2002 consistent with the methodology prescribed in Statement No. 123 “Accounting for Stock-Based Compensation,” net income and diluted earnings per share for the nine months ended September 30, 2002 would have been reduced by an estimated $7.5 million or $0.12 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 and exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.

The FASB has issued an Exposure Draft entitled, “Accounting for Stock-Based Compensation - Transition and Disclosure,” that would amend Statement No. 123. The Exposure Draft, if issued, would provide three methods of transition for companies that voluntarily adopt the fair value method of recording expenses related to employee stock options. In addition, the Exposure Draft proposes clearer and more prominent disclosures about the cost of stock-based employee compensation and an increase in the frequency of those disclosures. The Company cannot evaluate the ultimate impact of the new Exposure Draft until it becomes final. Nevertheless, if the Exposure Draft is issued as is currently proposed, the Company will contemplate transitioning its accounting for stock-based compensation from APB No. 25 to the amendment to Statement No. 123.

Special Purpose Entities

The FASB recently issued an Exposure Draft of a Proposed Interpretation entitled “Consolidation of Certain Special-Purpose Entities, an interpretation of Accounting Research Bulleting (ARB) No. 51, Consolidated Financial Statements.” The Exposure Draft provides a framework for determining whether a special-purpose entity (SPE) should be evaluated for consolidation based on voting interests (as is currently required under ARB No. 51) or significant financial support provided to the SPE. The Exposure Draft states that the primary beneficiary, determined either through voting interests or providing significant financial support, is deemed to be the parent and would be required to consolidate the SPE.

The Exposure Draft contemplates immediate application to SPE’s created after the issuance date of the final Interpretation. For SPE’s created before that date, the provisions would be applied to those SPE’s still existing as of the beginning of the first fiscal year or interim period beginning after March 15, 2003. The Exposure Draft is expected to be finalized by the end of the year.

The Company cannot evaluate the ultimate impact of the Exposure Draft until it becomes final. Nevertheless, if the Exposure Draft is issued as currently proposed, the Company believes that the most significant impact may relate to the Company’s accounting for its equity interest in Appalachian Natural Gas Trust (ANGT).

The Company currently has a 1% equity interest in ANGT. ANGT was formed through a $36.2 million cash contribution from the Company and a $261.5 million cash contribution from Appalachian NPI, LLC (ANPI). The total proceeds received by ANGT of $297.7 million were used to purchase a net profits interest in certain properties of the Company’s Production segment. ANPI’s contribution to ANGT was funded by $10.0 million in cash capital contributions from its owners (institutional investors) and $251.5 million in proceeds from a debt issuance. The assets of ANPI, including its interest in ANGT, collateralize ANPI’s debt. The Company has given, 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. Additionally, the Company has separately negotiated arms-length, market-based rates with ANGT for gathering, marketing, and operating fees to deliver their gas to market.

In accordance with current accounting guidance, the Company records its interest in ANGT under the equity method of accounting and does not consolidate ANPI. If the Exposure Draft on SPE’s is issued as currently written, the Company may be deemed to be the primary beneficiary of ANPI and consequently be required to consolidate ANPI effective April 1, 2003. The consolidation of ANPI is not expected to have an effect on the amount of net income reported by the Company or the economic position of the Company. The consolidation of ANPI would, however, have an effect on the Company’s Consolidated Balance Sheets. As of September 30, 2002, ANPI has approximately $288.3 million of assets (the majority of which are related to net property and equipment), and $251.8 million of liabilities (of which approximately $214.4 million is related to long-term debt).

In addition to potentially affecting the Company’s current accounting for ANGT and ANPI, the Exposure Draft may also have an affect on how the Company accounts for transfers of financial assets currently accounted for under Statement No. 140. The Company is currently assessing this item and has not yet determined the potential impact.

Contracts Involved in Energy Trading and Risk Management Activities

On October 25, 2002, the FASB’s Emerging Issues Task Force (EITF) reached a consensus to rescind EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” As a result, only energy contracts that meet the definition of a derivative in Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, will be carried at fair value. The EITF also issued a consensus to expand EITF 02-3’s requirement to classify gains and losses on energy trading contracts net on a company’s income statement to include all derivative contracts that are entered into for trading purposes. The EITF’s consensus is to be applied to all contracts entered into after October 25, 2002. For any contracts existing 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. Management is currently assessing the impact of this consensus and has not yet determined the impact that the implementation of this consensus will have on the earnings and financial position of the Company.

Nonconventional Fuel Tax Credits

The Company expects to benefit by approximately $0.10 per share during 2002 due to nonconventional fuels tax credits (Section 29 tax credits). These credits are due to expire at the end of 2002 and it is currently unclear as to whether legislation will be enacted to allow this benefit to exist in the future.

Dividend

On October 17, 2002, the Board of Directors of Equitable Resources declared a regular quarterly cash dividend of 17 cents per share, payable December 1, 2002 to shareholders of record on November 15, 2002.

Acquisitions and Dispositions

In December of 2001, the Company executed a purchase and sale agreement for the sale of the Company’s oil-dominated fields. This transaction is in line with management’s strategic objectives to focus on core natural gas related activities. The sale resulted in a decrease of 63 Bcfe of proved developed producing reserves and 5 Bcfe of proved undeveloped reserves for proceeds of approximately $60.0 million. No gain or loss was recognized on the sale in accordance with the Company’s accounting policies. The proceeds had been held in a restricted cash account at December 31, 2001 for the use in a potential like kind exchange for certain identified assets. During 2002, the restrictions lapsed and the cash has been made available for operations.

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, 2001 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 September 30, 2002. 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 September 30, 2002.

	Payments Due by Period
	Total		2002-2003		2004-2005		2006-2007		2008+
	(Thousands)
Interest expense	$	684,247	$	38,622	$	57,276	$	55,141	$	533,208
Long-term debt	287,469		24,250		30,500		13,000		219,719
Unconditional purchase obligations	201,042		31,507		48,248		45,631		75,656
Total contractual cash obligations	$	1,172,758	$	94,379	$	136,024	$	113,772	$	828,583

Included in long-term debt is a current portion of non-recourse project financing in the amount of $16.2 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.

Certain Trading Activities Accounted for at Fair Value

Below is a summary of the activity for the fair value of contracts outstanding for the nine months ended September 30, 2002 (in thousands).

Fair value of contracts outstanding at December 31, 2001	$		4,159
Contracts realized or otherwise settled	(9,894			)
Other changes in fair value	(1,281			)
Fair value of contracts outstanding at September 30, 2002	$	(7,016		)

The following table presents maturities and the fair valuation source for the Company’s derivative commodity instruments that are held for trading purposes as of September 30, 2002.

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

Source of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years			Maturity in Excess of 5 Years		Total Fair Value
	(Thousands)

Prices actively quoted (NYMEX)(1)	$	2,037		$	(2,231	)	$	(105	)	$	—	$	(299	)
Prices provided by other external sources(2)	(6,748		)	2,560			1,539			16		(2,633		)
Prices based on models and other valuation methods(3)	(536		)	(1,932		)	(1,616		)	—		(4,084		)
Net derivative (liabilities) assets	$	(5,247	)	$	(1,603	)	$	(182	)	$	16	$	(7,016	)

(1) Contracts include futures and fixed price swaps

(2) Contracts include physical, transport and basis swaps

(3) Contracts include demand charges and other fees

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 Production 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 of approximately 225.3 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 $91.5 million at September 30, 2002.

With respect to derivative contracts held by the Company for trading purposes, as of September 30, 2002, a decrease of 10% in the market price of natural gas would increase the fair market value by approximately $6.3 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

The Chief Executive Officer and the Chief Financial Officer of the Company (its principal executive officer and principal financial officer, respectively) have concluded, based on their evaluation as of a date within 90 days prior to the date of the filing of this Report, that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in the reports filed or submitted by it under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by the Company in such reports is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

There were no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of such evaluation.

PART II. OTHER INFORMATION

Item 1. Legal Proceeding

On October 17, 2002, a jury verdict in the civil lawsuit of Fairon Johnson and Sandra Johnson versus Equitable Resources, Inc. and Kentucky West Virginia Gas Company, L.L.C. was rendered against the Company in Knott County Circuit Court, Kentucky. The plaintiff claimed that a well pump house accident that injured him was caused by the Company’s natural gas well adjacent to his property. The jury entered a verdict for $50,000 for medical expenses and lost wages and $270 million for pain and suffering and punitive damages. Although the Company is insured, it considers the claim to be without merit and will vigorously pursue all post-verdict motions and appellate remedies.

Item 6. Exhibits and Report on Form 8-K

(a) Exhibits:

10.09 (c)		Amendment No. 2 to Employment Agreement with Murry S. Gerber

10.10		Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Murry S. Gerber

10.13 (c)		Amendment No. 2 to Employment Agreement with David L. Porges

10.14		Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and David L. Porges

10.16		Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Gregory R. Spencer

10.18		Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Johanna G. O’Loughlin

10.24		Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and James M. Funk

10.26		Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Philip P. Conti

10.31		Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Joseph E. O’Brien

10.38		1999 Equitable Resources, Inc. Long-Term Incentive Plan as Amended and Restated May 18, 2001

(b) Report on Form 8-K during the quarter ended September 30, 2002:

Form 8-K current report dated August 8, 2002 submitting the SEC sworn statements from the Company’s Principal Executive Officer, Murry S. Gerber, and Principal Financial Officer, David L. Porges, pursuant to Securities and Exchange Commission Order No. 4-460.

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: November 6, 2002

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: November 6, 2002

	/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;

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

Date: November 6, 2002

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

CERTIFICATION

In connection with the Quarterly Report of Equitable Resources, Inc. (the “Company”) on Form 10-Q for the period ending September 30, 2002, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned certify pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Murry S. Gerber		November 6, 2002
Murry S. Gerber, Chairman,
President and Chief Executive Officer


/s/ David L. Porges		November 6, 2002
David L. Porges, Executive Vice President
and Chief Financial Officer

INDEX TO EXHIBITS

Exhibit No.	Document Description

10.09 (c)	Amendment No. 2 to Employment Agreement with Murry S. Gerber	Filed Herewith

10.10	Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Murry S. Gerber	Filed Herewith

10.13 (c)	Amendment No. 2 to Employment Agreement with David L. Porges	Filed Herewith

10.14	Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and David L. Porges	Filed Herewith

10.16	Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Gregory R. Spencer	Filed Herewith

10.18	Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Johanna G. O’Loughlin	Filed Herewith

10.24	Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and James M. Funk	Filed Herewith

10.26	Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Philip P. Conti	Filed Herewith

10.31	Change of Control Agreement dated September 1, 2002 by and between Equitable Resources, Inc. and Joseph E. O’Brien	Filed Herewith

10.38	1999 Equitable Resources, Inc. Long-Term Incentive Plan as Amended and Restated May 18, 2001	Filed Herewith

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