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

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED JUNE 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 July 31, 2002

Common stock, no par value		61,995,385 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 Six Months Ended June 30, 2002 and 2001	2

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

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

		Notes to Condensed Consolidated Financial Statements	6-12

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13-30

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31

Part II. Other Information:

	Item 5.	Submission of Matters to a Vote of Security Holders	32

	Item 6.	Exhibits and Reports on Form 8-K	32

Certification			33

Signature			34

Index to Exhibits			35

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

(Thousands Except Per Share Amounts)

	Three Months Ended June 30,					Six Months Ended June 30,
	2002			2001		2002			2001

Operating revenues	$	268,638		$	345,544	$	612,695		$	1,196,701
Cost of sales	144,620			216,838		327,801			882,404
Net operating revenues	124,018			128,706		284,894			314,297

Operating expenses:
Operation and maintenance	18,412			20,580		35,996			41,227
Production and exploration	6,391			9,544		12,841			19,224
Selling, general and administrative	23,091			30,405		48,948			60,263
Impairment of long-lived assets	5,320			—		5,320			—
Depreciation, depletion and amortization	16,771			17,404		33,538			34,537
Total operating expenses	69,985			77,933		136,643			155,251

Operating income	54,033			50,773		148,251			159,046

Equity (losses) earnings from nonconsolidated investments and minority interest:
Westport	(625		)	3,477		(4,873		)	14,467
Other	(1,517		)	3,362		(1,336		)	5,303
	(2,142		)	6,839		(6,209		)	19,770

Earnings before interest and taxes (EBIT)	51,891			57,612		142,042			178,816

Interest charges	9,259			9,345		18,838			20,812

Income from continuing operations before income taxes and cumulative effect of accounting change	42,632			48,267		123,204			158,004
Income taxes	13,443			16,830		41,643			55,301
Income from continuing operations before cumulative effect of accounting change	29,189			31,437		81,561			102,703
Income from discontinued operations	9,000			—		9,000			—
Cumulative effect of accounting change, net of tax	—			—		(5,519		)	—
Net income	$	38,189		$	31,437	$	85,042		$	102,703

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	63,280			64,636		63,421			64,711
Income from continuing operations before cumulative effect of accounting change	$	0.46		$	0.49	$	1.29		$	1.59
Income from discontinued operations	0.14			—		0.14			—
Cumulative effect of accounting change, net of tax	—			—		(0.09		)	—
Net income	$	0.60		$	0.49	$	1.34		$	1.59
Diluted:
Weighted average common shares outstanding	64,999			66,677		65,033			66,538
Income from continuing operations before cumulative effect of accounting change	$	0.45		$	0.47	$	1.25		$	1.54
Income from discontinued operations	0.14			—		0.14			—
Cumulative effect of accounting change, net of tax	—			—		(0.08		)	—
Net income	$	0.59		$	0.47	$	1.31		$	1.54

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 June 30,						Six Months Ended June 30,
	2002			2001			2002			2001
Cash flows from operating activities:
Net income from continuing operations	$	29,189		$	31,437		$	81,561		$	102,703

Adjustments to reconcile net income to net cash provided by operating activities:
Provision for doubtful accounts	760			2,983			5,029			10,230
Depreciation, depletion, and amortization	16,771			17,404			33,538			34,537
Impairment of assets	5,320			—			5,320			—
Recognition of monetized production revenue	(13,888		)	(26,912		)	(27,624		)	(46,762		)
Deferred income taxes	10,055			17,506			12,255			18,293
Decrease (increase) in undistributed earnings from nonconsolidated investments	252			(5,663		)	3,536			(15,998		)
Changes in other assets and liabilities	34,523			1,099			62,936			25,747
Total adjustments	53,793			6,417			94,990			26,047
Net cash provided by operating activities	82,982			37,854			176,551			128,750

Cash flows from investing activities:
Capital expenditures	(49,644		)	(30,250		)	(86,716		)	(44,475		)
Decrease in restricted cash	61,760			—			62,956			—
Decrease (increase) in equity of unconsolidated entities	192			662			973			(49		)
Proceeds from sale of contract receivables	—			1,323			—			—
Proceeds from sale of property	—			1,620			—			4,525
Net cash provided by (used in) investing activities	12,308			(26,645		)	(22,787		)	(39,999		)

Cash flows from financing activities:
Dividends paid	(10,702		)	(10,390		)	(20,783		)	(19,957		)
Proceeds from exercises under employee compensation plans	7,463			1,778			9,703			3,352
Purchase of treasury stock	(27,195		)	(46,206		)	(44,867		)	(46,206		)
Loans against construction contracts	3,430			—			8,229			31,287
Repayments and retirement of long-term debt	(158		)	—			(315		)	—
Decrease in short-term loans	(64,205		)	(39,805		)	(128,911		)	(105,810		)
Net cash used in financing activities	(91,367		)	(94,623		)	(176,944		)	(137,334		)

Net increase (decrease) in cash and cash equivalents	3,923			(83,414		)	(23,180		)	(48,583		)
Cash and cash equivalents at beginning of period	2,519			86,854			29,622			52,023
Cash and cash equivalents at end of period	$	6,442		$	3,440		$	6,442		$	3,440

Cash paid during the period for:
Interest, net of amount capitalized	$	5,663		$	8,662		$	18,169		$	22,273
Income taxes paid, net of refund	$	12,736		$	23,198		$	11,707		$	10,280

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

ASSETS	June 30, 2002		December 31, 2001
	(Thousands)
Current assets:
Cash and cash equivalents	$	6,442	$	29,622
Restricted cash	—		62,956
Accounts receivable, net	98,521		132,750
Unbilled revenues	83,984		77,080
Inventory	61,707		96,445
Derivative commodity instruments, at fair value	55,912		193,623
Prepaid expenses and other	16,970		20,868

Total current assets	323,536		613,344

Equity in nonconsolidated investments	248,704		253,214

Property, plant and equipment	2,413,598		2,337,344

Less accumulated depreciation and depletion	950,340		923,067

Net property, plant and equipment	1,463,258		1,414,277

Investments, available-for-sale	11,038		—

Other assets	192,554		237,912

Total	$	2,239,090	$	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)

LIABILITIES AND STOCKHOLDERS’ EQUITY	June 30, 2002			December 31, 2001
	(Thousands)
Current liabilities:

Current portion of nonrecourse project financing	$	16,381		$	16,696
Short-term loans	146,536			275,447
Accounts payable	110,981			101,654
Prepaid gas forward sale	55,705			55,705
Derivative commodity instrument, at fair value	42,994			62,002
Other current liabilities	86,058			100,686

Total current liabilities	458,655			612,190

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

Deferred and other credits:
Deferred income taxes	341,056			364,633
Deferred investment tax credits	13,771			14,336
Prepaid gas forward sale	69,672			97,296
Deferred revenue	8,691			6,560
Project financing obligations	79,805			109,209
Other	77,479			72,119
Total deferred and other credits	590,474			664,153

Preferred trust securities	125,000			125,000

Capitalization:
Common stockholders’ equity:
Common stock, no par value, authorized 160,000 shares; shares issued: June 30, 2002 and December 31, 2001, 74,504	282,705			282,920
Treasury stock, shares at cost: June 30, 2002, 11,482; December 31, 2001, 10,634 (net of shares and cost held in trust for deferred compensation of 413, $7,289 and 362, $6,284)	(238,990		)	(203,353		)
Retained earnings	739,272			675,207
Accumulated other comprehensive income, net of taxes	10,724			91,380

Total common stockholders’ equity	793,711			846,154

Total	$	2,239,090		$	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. 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, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six month period ended June 30, 2002 are not necessarily indicative of the results that may be expected for the year ending December 31, 2002.

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.

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 13 of this document.

B. Segment Disclosure – The Company reports operations in three segments, which reflect its lines of business. The Equitable Utilities segment’s activities are comprised of the Company’s state-regulated local distribution operations; natural gas transportation, storage and marketing activities involving the Company’s federally-regulated interstate natural gas pipelines; and supply and transportation services for the natural gas and electricity markets. The Equitable Production segment’s activities are comprised of the development, production, gathering and sale of natural gas. The NORESCO segment’s activities are comprised of distributed on-site generation, combined heat and power, and central boiler/chiller plant development, design, construction, ownership 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 allocated proportionately to operating segments. Headquarters’ costs are billed to operating segments based on 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 included as a reconciling item to consolidated earnings from continuing operations.

	Three Months Ended June 30,						Six Months Ended June 30,
	2002			2001			2002			2001
	(Thousands)
Revenues from external customers:
Equitable Utilities	$	157,089		$	236,979		$	402,842		$	968,536
Equitable Production	65,055			73,254			127,920			158,390
NORESCO	46,494			35,311			81,933			69,775
Total	$	268,638		$	345,544		$	612,695		$	1,196,701

Intersegment revenues:
Equitable Utilities	$	34,654		$	37,860		$	63,463		$	91,534
Equitable Production	2,973			2,302			6,510			7,653
Total	$	37,627		$	40,162		$	69,973		$	99,187

Segment earnings before interest and taxes:
Equitable Utilities	$	15,080		$	5,737		$	68,555		$	54,968
Equitable Production	38,828			44,377			76,075			103,924
NORESCO	(612		)	4,644			3,588			7,456
Total operating segments	$	53,296		$	54,758		$	148,218		$	166,348

Reconciling items:
Equity (losses) earnings in Westport	$	(625	)	$	3,477		$	(4,873	)	$	14,467
Headquarters operating expenses	(780		)	(623		)	(1,303		)	(1,999		)
Interest expense	(9,259		)	(9,345		)	(18,838		)	(20,812		)
Income tax expenses	(13,443		)	(16,830		)	(41,643		)	(55,301		)
Discontinued operations	9,000			—			9,000			—
Cumulative effect of accounting change, net of tax	—			—			(5,519		)	—
Net income	$	38,189		$	31,437		$	85,042		$	102,703

	June 30, 2002		December 31, 2001
	(Thousands)

Segment Assets:
Equitable Utilities	$	935,641	$	937,147
Equitable Production	934,053		1,138,550
NORESCO	219,927		264,960

Total operating segments	2,089,621		2,340,657

Headquarters assets, including investment in Westport, cash and short-term investments	149,469		178,090

Total	$	2,239,090	$	2,518,747

C. Summary of Significant Accounting Policies

Income Taxes – The Company estimates an annual effective income tax rate, based on projected results for the year, and applies this rate to pre-tax income 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.

Impairment of Assets – When events indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews the assets for impairment by comparing the carrying value of the assets with their estimated future undiscounted cash flows. If it is determined that an impairment loss has occurred, the loss would be recognized during that period within income from continuing operations. The impairment loss is calculated as the difference between asset carrying values and the present value of the estimated future net cash flows.

Investments – The Company has evaluated its investment policy in accordance with Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (Statement) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and has determined that all of its investment securities are appropriately classified as available-for-sale. Available-for-sale securities are required to be carried at fair value, with any unrealized gains and losses reported on the balance sheet within a separate component of equity, accumulated other comprehensive income. These investments are intended to cover plugging and abandonment and other liabilities for which the Company self insures and are not expected to be paid in the near future and are therefore considered long-term in nature.

Derivative Instruments – The Company uses 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 and for trading purposes. At contract inception, the Company designates derivative commodity instruments as hedging or trading activities. All derivative commodity instruments are accounted for in accordance with the 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,” an amendment of Statement 133. As a result, the Company recognizes all derivatives as either assets or liabilities on the balance sheet and measures the effectiveness of the hedges, or the degree that the gain/(loss) for the hedging instrument offsets the loss/(gain) on the hedged item, at fair value each reporting period. 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 Corporate Risk Committee. The intended use of the derivatives and their designation as either a fair value hedge or a cash flow hedge determines when the gains or losses on the derivatives are to be reported in earnings or when they are to be reported as a component of other comprehensive income, net of tax, until the hedged item is recognized in earnings. The ineffective portion of the derivative’s change in fair value is recognized in earnings immediately, and is included in operating revenues in the Statements of Consolidated Income. Any ineffective portion that was recognized in earnings from a previous period that is “caught up” in a current period and recognized in other comprehensive income will be reversed out of earnings. At June 30, 2002, the amount of the hedges’ ineffectiveness increased earnings by approximately $0.6 million and is included in operating revenue in the Statements of Consolidated Income.

C. Summary of Significant Accounting Policies

Cash Flow Hedges – The derivative financial instruments that comprise the amount recorded in other comprehensive income on the Consolidated Balance Sheets have been designated and qualify as cash flow hedges. These instruments hedge the Company’s 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. The Company’s derivative financial instruments accounted for as cash flow hedges were recorded as a $44.0 million asset and a $9.0 million liability at June 30, 2002, and are reflected on the Consolidated Balance Sheets as a component of derivative commodity instruments at fair value. The difference between these derivatives and the amounts reported on the Consolidated Balance Sheets represent the Company’s derivative contracts held for trading purposes. The effective portion of the derivatives designated as a cash flow hedge remains in other comprehensive income until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues on the Statements of Consolidated Income. If a derivative designated as a cash flow hedge is terminated before settlement date of the hedged item, other comprehensive income recorded up to that date would remain accrued provided that the forecasted sale remains probable to occur, and, going forward, the fair value change of the derivative(s) will be recorded in earnings. At June 30, 2002, the Company estimated that $15.8 million of net unrealized gains on derivative instruments currently reflected in accumulated other comprehensive income will be recognized as earnings during the next twelve months due to physical settlement.

D. 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 the 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.

E. Investments – Investments as of June 30, 2002 consist of approximately $11.0 million of debt and equity instruments, which are classified as non-current available-for-sale securities. The unrealized holding losses related to these securities as of June 30, 2002 are $0.6 million. No income has been realized in 2002.

F. Accumulated Other Comprehensive Income – The components of the changes to Accumulated Other Comprehensive Income are as follows shown net of tax (in thousands):

Accumulated other comprehensive income, December 31, 2001	$	91,380
Net change of current period hedging transactions	(80,082		)
Unrealized loss on available-for-sale securities	(574		)
Accumulated other comprehensive income, June 30, 2002	$	10,724

G. In September 2000, the FASB issued 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 must be 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 June 30, 2002, the Company had recorded a liability of $79.9 million with the related assets included in unbilled revenues and other assets. For the six month period ending June 30, 2002, approximately $36.1 million of receivables met the criteria for sales treatment generating a recognized gain of $1.1 million. The derecognition of the $36.1 million in receivables and liabilities was considered a non-cash transaction and is not reflected on the Statements of Consolidated Cash Flows.

H. 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 the six months ended June 30, 2002.

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 $0.08 per diluted share, to reduce the carrying value of the goodwill to its estimated fair value as the level of future cash flows from the NORESCO segment are expected to be less than originally anticipated. In accordance with Statement No. 142, this impairment adjustment has been reported as the cumulative effect of an accounting change in the Company’s Statements of Consolidated Income retroactive to the first quarter 2002. The impairment adjustment reduced the Company’s reported first quarter 2002 net income of $52.4 million, or $0.80 per diluted share to $46.9 million, or $0.72 per diluted share. The Company expects to perform the required annual test of the carrying value of goodwill for impairment, during the fourth quarter.

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 six months ended June 30, 2002 and 2001 would have been as follows:

	Net Income (in millions)				Diluted EPS
	2002		2001		2002		2001
Net income	$	85.0	$	102.7	$	1.31	$	1.54
Add goodwill amortization	—		1.8		—		0.03
Adjusted net income	$	85.0	$	104.5	$	1.31	$	1.57

Net income for the six months ended June 30, 2001 would have been $1.8 million, or $0.03 per share, higher if goodwill amortization had been discontinued effective January 1, 2001.

I. 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, included in selling, general and administrative expense for the six-month period ended June 30, 2002, is $2.3 million.

A restricted stock grant in the amount of 73,800 shares was also awarded during the first quarter of 2002. The related expense recognized during the six months ended June 30, 2002 was $0.2 million and is included in 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. 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 six months ended June 30, 2002 consistent with the methodology prescribed in Statement No. 123 “Accounting for Stock-Based Compensation,” net income and diluted earnings per share would have been reduced by an estimated $7.5 million or $0.12 per diluted share for the entire year 2002. The estimate of compensation cost is based upon the use of the Black-Scholes option pricing model. The Black-Scholes model is considered a “theoretical” or “probability” model used to estimate what an option would sell for in the market today. The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.

J. Effective January 1, 2002, the Company adopted Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Statement No. 144 provides a single accounting model for long-lived assets to be disposed of and significantly changes the criteria that would have to be met to classify an asset as held-for-sale. The provisions of this new standard are generally to be applied prospectively.

During the second quarter 2002, the Company evaluated the ongoing value of the Jamaica power plant project. The Company owns 91.24% of the equity in the project and therefore consolidates the project in its financial statements. The Jamaican power plant project has not operated to expected levels and remediation efforts have been ineffective. The Company recorded a long-lived asset impairment of $5.3 million to write these assets down to their fair value. Fair value was based on expected future cash flows to be generated by the Jamaican power plant, discounted at the risk-free rate of interest.

K. In July 2001, the FASB 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. During 2002, management will assess the impact of this Statement and has not yet determined its impact, if any, on the earnings and financial position of the Company.

L. In November 1995, the Company monetized certain Appalachian gas properties, the production from which qualifies for the nonconventional fuels tax credit, to a partnership, Appalachian Basin Partners (ABP). The Company recorded the proceeds as deferred revenue, which was recognized as production occurred. The Company retained a partnership interest in the properties that increased substantially at the end of 2001 when the performance target was met. 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 approximately 4.4 Bcf in the first half of 2002, while equity production increased by the same amount. The Company consolidated the partnership beginning January 1, 2002, and the remaining portion not owned by the Company was recorded as a minority interest. The minority interest for the six months ended June 30, 2002 was $3.4 million and is recorded in equity earnings from nonconsolidated investments within the Statements of Consolidated Income and minority interest within the other current liabilities on the Consolidated Balance Sheets. The Company will also begin receiving a greater percentage of the nonconventional fuels tax credit based on its increased ownership.

M. Reclassification – Certain previously reported amounts have been reclassified to conform with the 2002 presentation.

N. Income Taxes – Late in 2001, the Company’s interest in ABP increased. The Company also began receiving a greater percentage of the nonconventional fuels tax credit causing a reduction in the effective tax rate.

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 related to such matters as the impact of FASB Statement 142, “Goodwill and Other Intangible Assets;” the future value of the Petroelectrica de Panama project; the ability to complete or obtain extensions for noise retrofit work, the expected financial and operations improvements, and the ability to remedy a loan default on the IGC/ERI Pan-Am Thermal project; the expected payment for plugging and abandonment in the near future; the energy and derivatives strategy and other financial or 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 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, changes in accounting rules or 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’s consolidated net income for the quarter ended June 30, 2002 totaled $38.2 million, or $0.59 per diluted share, compared to $31.4 million, or $0.47 per diluted share, reported for the same period a year ago.

The increase in earnings for the June 2002 quarter is mainly attributable to a gain from discontinued operations, increased throughput due to colder weather at the Utility segment, and decreased operating costs at all three business units. The increase was further attributable to the absence of a $4.3 million charge related to a workforce reduction in June 2001 at the Utility segment. These increases were partially offset by a long-lived asset impairment at the NORESCO segment combined with the loss of income related to production volumes of oil-dominated fields that were sold in 2001 and decreased commodity prices within the Production segment.

RESULTS OF OPERATIONS

EQUITABLE UTILITIES

Equitable Utilities’ operations are comprised of the sale and transportation of natural gas to retail customers at state-regulated rates, interstate transportation and storage of natural gas subject to federal regulation, and the unregulated marketing of natural gas.

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 marketing revenues and sales volumes.

	Three Months Ended June 30,						Six Months Ended June 30,
	2002			2001			2002			2001

OPERATIONAL DATA

Capital expenditures	$	12,985		$	9,170		$	22,305		$	16,737

Total expenses/net revenues (%)	66.95		%	86.99		%	47.88		%	58.04		%

FINANCIAL RESULTS (Thousands)

Utility revenues	$	56,858		$	64,285		$	191,852		$	277,928
Marketing revenues	134,885			210,554			274,453			782,142
Total operating revenues	191,743			274,839			466,305			1,060,070

Purchased gas costs and revenue related taxes	146,111			230,736			334,773			929,070
Net operating revenues	45,632			44,103			131,532			131,000

Operating and maintenance expense	12,596			14,765			24,220			29,647
Selling, general and administrative expense	11,369			17,195			25,652			33,695
Depreciation, depletion and amortization	6,587			6,406			13,105			12,690
Total expenses	30,552			38,366			62,977			76,032

EBIT	$	15,080		$	5,737		$	68,555		$	54,968

Three Months Ended June 30, 2002

vs. Three Months Ended June 30, 2001

Total net operating revenues increased $1.5 million, or 3% for the three months ended June 30, 2002 compared to the prior year quarter. The increase in net revenues is primarily due to colder weather. EBIT increased $9.4 million to $15.1 million for the current period compared to $5.7 million for the same period in 2001. The improved results are attributable to the absence of a $4.3 million charge related to a workforce reduction in June 2001, higher net revenues from colder weather in the June 2002 quarter and lower operating costs from on-going cost reduction initiatives.

In the second quarter 2002, the Pennsylvania Public Utility Commission authorized Equitable Gas Company 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.

Six Months Ended June 30, 2002

vs. Six Months Ended June 30, 2001

Total net operating revenues increased slightly by $0.5 million in 2002 compared to the six months ended June 30, 2001. The increase is related to improved marketing operations margins despite the decline in gross revenues. The improved margins, in the context of sharply lower gross revenues, was a result of the Company’s decision to focus on storage and asset management activities and de-emphasize the low margin trading-oriented activities. The increase in marketing net revenues was partially offset by reduced distribution net revenues from warm temperatures in the first quarter 2002. EBIT increased 25% to $68.6 million for the current period compared to $55.0 million for the same period in 2001. Excluding the one-time charge related to the workforce reduction, EBIT increased $9.3 million or 16% due principally to on-going cost reduction initiatives and improved marketing margins.

Distribution Operations

	Three Months Ended June 30,				Six Months Ended June 30,
	2002		2001		2002		2001

OPERATIONAL DATA

Degree days (normal = Qtr – 712, YTD – 3,728)	632		504		3,041		3,322

O & M, and SG&A (excluding other taxes) per customer	$	60.34	$	66.55	$	130.77	$	146.30

Volumes (MMcf)
Residential	3,876		3,077		15,092		16,193
Commercial and industrial	6,147		4,239		16,562		14,606
Total gas sales and transportation	10,023		7,316		31,654		30,799

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	28,491	$	26,223	$	87,744	$	92,725

Operating expenses	17,273		19,047		37,079		41,488
Depreciation and amortization	4,902		4,315		9,736		8,589

EBIT	$	6,316	$	2,861	$	40,929	$	42,648

Three Months Ended June 30, 2002

vs. Three Months Ended June 30, 2001

Heating degree days in the June 2002 quarter were 632 or 25% colder than the 504 degree days recorded in the prior year quarter. Although the second quarter is not typically impacted by weather, the colder temperatures resulted in a net revenue increase of approximately $1.9 million compared to the prior year quarter. The heating degree days were 11% warmer than the 30-year normal of 712, based on the 30-year average determined by the National Oceanic and Atmospheric Administration. Residential volumes increased by 26% due to the colder than prior quarter weather. Commercial and industrial volumes were 45% 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.

Operating expenses of $17.3 million for the 2002 quarter decreased compared to the June 2001 quarter operating expenses of $19.0 million. The reduced operating costs are due to on-going cost reduction initiatives and decreased collection-related costs attributable to lower gas prices compared to prior year.

Six Months Ended June 30, 2002

vs. Six Months Ended June 30, 2001

Weather in the distribution service territory for the six months ended June 30, 2002, was 18% warmer than normal and 8% warmer than last year, primarily associated with warm temperatures in the first quarter 2002. Residential volumes decreased 7% from prior year, while commercial and industrial volumes increased 13% 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.

Net operating revenues for the six months ended June 30, 2002, decreased to $87.7 million from $92.7 million, or 5% from the same period last year.

Operating expenses for the six months ended June 30, 2002 decreased $4.4 million, or 11%, 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 in the current year, and from continued Utility process improvement initiatives.

Pipeline Operations

	Three Months Ended June 30,					Six Months Ended June 30,
	2002		2001			2002		2001

OPERATIONAL DATA

Transportation throughput (MMbtu)	21,971		18,290			38,690		36,776

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	12,010	$	12,900		$	29,528	$	31,103

Operating expenses	5,875		11,270			11,035		18,229
Depreciation and amortization	1,582		1,996			3,162		3,952

EBIT (Losses before interest and taxes)	$	4,553	$	(366	)	$	15,331	$	8,922

Three Months Ended June 30, 2002

vs. Three Months Ended June 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 of net operating revenues of $0.8 million, and a $0.5 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 June 30, 2002, were essentially flat.

Transportation throughput increased significantly over the prior year quarter. This increase was caused by increased deliveries at the Distribution segment due to colder weather and increased process load. 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 $5.9 million for the 2002 quarter compared to $11.3 million for the 2001 quarter, a decrease of $5.4 million. As previously described, the 2001 operating expenses included a one-time $4.3 million charge related to the pipeline operations workforce reduction and included $0.5 million for gathering operations costs. Excluding these items, normalized operating expenses were $6.0 million in the 2002 quarter as compared to $7.0 million for the same quarter a year ago. The decrease in operating costs resulted from the on-going savings realized from workforce reductions, compressor station automation and a lease buyout during 2001.

Six Months Ended June 30, 2002

vs. Six Months Ended June 30, 2001

Excluding the impact of the transfer of the gathering assets of $1.7 million, net operating revenues for the six months ended June 30, 2002, were $31.2 million compared to $31.1 million for the same period in 2001.

Excluding the $4.3 million one-time charge for the workforce reductions in 2001 and the $1.1 million reduction of operating costs in 2002 due to the gathering asset transfer, operating expenses declined by $1.8 million, or 13%, to $12.1 million. The decrease in operating costs resulted from the on-going savings realized from workforce reductions, compressor station automation and a lease buyout.

Equitable Marketing

	Three Months Ended June 30,				Six Months Ended June 30,
	2002		2001		2002		2001

OPERATIONAL DATA

Marketed gas sales (MMbtu)	37,716		44,658		88,073		130,407

Net operating revenues/MMbtu	$	0.1360	$	0.1115	$	0.1619	$	0.0550

FINANCIAL RESULTS (Thousands)

Net operating revenues	$	5,131	$	4,979	$	14,260	$	7,171

Operating expenses	817		1,643		1,758		3,624
Depreciation and amortization	103		94		207		149

EBIT	$	4,211	$	3,242	$	12,295	$	3,398

Three Months Ended June 30, 2002

vs. Three Months Ended June 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 marketing revenues and sales volumes. The marketing net operating revenues for the current quarter were essentially flat compared to the prior year.

Operating expenses for the current quarter of $0.8 million decreased 50% 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.

Six Months Ended June 30, 2002

vs. Six Months Ended June 30, 2001

Net operating revenues for the six months ended June 30, 2002 increased $7.1 million, or two-fold from the same period last year. Excluding the prior year one-time loss of $2.6 million on transactions marked to market that were previously treated as hedges, the net operating revenues increased $4.5 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 six-month period decreased by $1.8 million, or 50% from the six months ended June 2001. The decrease 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 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 November 1995, the Company monetized Appalachian gas properties qualifying for nonconventional fuels tax credit to a partnership, Appalachian Basin Partners (ABP). The Company recorded the proceeds as deferred revenue, which was recognized as production occurred. The Company retained a partnership interest in the properties that increased substantially at the end of 2001 when the performance target was met. Beginning in 2002, the Company no longer included the ABP volumes as monetized sales, but instead as equity production sales. As a result, monetized volumes sold decreased by approximately 4.4 Bcfe during the first half of 2002 while equity production increased by a similar amount. The 31% interest in these properties owned by the ABP limited partners resulted in a reduction of EBIT in the amount of $1.9 million and $3.4 million, respectively, for the three and six month periods ended June 30, 2002. ABP sales volumes attributed to the minority interest owners, which are accounted for as net equity sales, were 0.6 Bcfe and 1.3 Bcfe, respectively, for the three and six months ended June 30, 2002. These amounts are reflected in equity earnings of nonconsolidated investments on the Statements of Consolidated Income for the three and six months ended June 30, 2002. The Company also began receiving a greater percentage of the nonconventional fuels tax credit, included as a reduction of income tax expense.

In July 2001, Equitrans filed an order with the FERC to transfer five natural gas pipeline gathering systems located in West Virginia and Pennsylvania to the Equitable Production business segment. On February 13, 2002, the FERC approved the order that resulted in the transfer of 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 Production.

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 $0.8 million in service revenue through the first two 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. During 2002, management will assess the impact of this Statement and has not yet determined the impact, if any, on the earnings and financial position of the Company.

	Three Months Ended June 30,					Six Months Ended June 30,
	2002			2001		2002			2001

OPERATIONAL DATA (excluding Gulf Operations)

Production:
Net equity sales, natural gas and equivalents (MMcfe)	11,309			9,632		22,733			18,593

Average (well-head) sales price ($/Mcfe)	$	3.52		$	3.63	$	3.36		$	4.34

Monetized sales (MMcfe)	3,510			5,699		6,981			11,380
Average (well-head) sales price ($/Mcfe)	$	3.28		$	4.07	$	3.26		$	4.20

Weighted average (well-head) sales price ($/Mcfe)	$	3.46		$	3.79	$	3.34		$	4.29
Company usage (MMcfe)	1,447			1,284		2,787			2,482

Lease operating expense excluding severance tax ($/Mcfe)	$	0.26		$	0.34	$	0.28		$	0.35
Severance tax ($/Mcfe)	$	0.12		$	0.19	$	0.10		$	0.21
Depletion ($/Mcfe)	$	0.39		$	0.38	$	0.39		$	0.39

Production Services:
Gathered volumes (MMcfe)	28,917			27,665		59,532			52,420
Average gathering fee ($/Mcfe)	$	0.50		$	0.52	$	0.50		$	0.59
Gathering and compression expense ($/Mcfe)	$	0.20		$	0.21	$	0.20		$	0.22
Gathering and compression depreciation ($/Mcfe)	$	0.10		$	0.10	$	0.09		$	0.10

Total operated volumes (MMcfe)	22,291			23,003		44,797			45,529
Volumes handled (MMcfe)	31,920			31,166		65,168			59,023
Selling, general and administrative ($/Mcfe handled)	$	0.17		$	0.21	$	0.17		$	0.22

Operating costs per unit ($/Mcfe)	$	0.63		$	0.76	$	0.65		$	0.79

Capital expenditures (thousands)	$	36,476		$	20,792	$	64,047		$	27,260

FINANCIAL RESULTS (thousands)

Revenue from production	$	51,313		$	58,175	$	99,143		$	128,522
Services:
Revenue from gathering fees	14,414			14,310		30,007			30,812
Other revenues	2,301			3,071		5,280			6,709
Total revenues	68,028			75,556		134,430			166,043

Gathering and compression expenses	5,816			5,815		11,776			11,580
Lease operating expense	4,265			5,695		9,009			11,234
Severance tax	1,970			3,227		3,380			6,888
Depreciation, depletion and amortization	9,711			9,518		19,470			18,866
Selling, general and administrative	5,399			6,498		10,987			12,994
Exploration, including dry hole expense	156			622		452			1,102
Total operating expenses	27,317			31,375		55,074			62,664

Equity earnings from nonconsolidated investments and minority interest	(1,883		)	196		(3,281		)	545

EBIT from operations	$	38,828		$	44,377	$	76,075		$	103,924

Three Months Ended June 30, 2002

vs. Three Months Ended June 30, 2001

Equitable Production’s EBIT for the three months ended June 30, 2002, was $38.8 million, 13% lower than the $44.4 million earned for the three months ended June 30, 2001. The decrease in the segment’s results was attributable to lower commodity prices, overall volume declines due to the oil field sale in December 2001 and increased minority interest expense of $1.9 million due to the transition of ABP noted in the previous section. These factors were partially offset by lower operating costs.

Revenues for the second quarter 2002 decreased 10% to $68.0 million compared to $75.6 million in 2001. The revenue decrease was primarily due to a 9% decline in the Company’s weighted average well-head sales price realized on produced volumes of $3.46 per Mcfe compared to $3.79 per Mcfe for the same period last year. Overall production volumes declined by 0.5 Bcfe, which was a direct result of 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 0.5 Bcfe, or 3% due to new drilling.

Operating expenses for the three months ended June 30, 2002 were $27.3 million compared to $31.4 million last year, representing a 13% decrease. This 13% reduction is primarily due to reductions in lease operating expenses and selling, general and administrative expense, as a result of on-going operating efficiency improvements. Operating costs per mcfe, consisting of lease operating expense, gathering and compression expense and selling, general and administrative expense, decreased from $0.76 to $0.63, a 17% reduction. The total value of the operating cost savings was $2.5 million.

Six Months Ended June 30, 2002

vs. Six Months Ended June 30, 2001

Equitable Production’s EBIT for the six months ended June 30, 2002, was $76.1 million, 27% lower than the $103.9 million earned for the six months ended June 30, 2001. The segment’s results were negatively affected by lower commodity prices, overall volume declines due to the oil field sale in December 2001 and increased minority interest expense of $3.4 million due to the ABP transition. These factors were partially offset by lower operating costs.

During the six months ended June 30, 2002, revenues declined $31.6 million, or 19%, from $166.0 million to $134.4 million, primarily due to lower market prices for gas and minor decreases in overall production. The overall production volume decline was a direct result of production volumes lost (2.0 Bcfe) in the December 2001 oil field sale. Comparable volumes, those net of the oil field sale, were up 1.7 Bcfe or 6%, due to new drilling. The Company’s weighted average well-head sales price realized on produced volume fell to $3.34 per Mcfe, compared to $4.29 per Mcfe in the same period in 2001, which represented a 22% decline.

Operating expenses were $55.1 million compared to $62.7 million for the six months ended June 30, 2002. This 12% 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 $0.79 to $0.65, an 18% reduction. The total value of the operating cost savings was $4.0 million.

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, 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, and Costa Rica.

	Three Months Ended June 30,						Six Months Ended June 30,
	2002			2001			2002			2001
OPERATIONAL DATA

Revenue backlog, end of period (thousands)	$	157,410		$	90,844		$	157,410		$	90,844
Construction completed (thousands)	$	30,917		$	21,487		$	52,222		$	42,209

Capital expenditures (thousands)	$	183		$	136		$	364		$	330

Gross profit margin	22.3		%	25.6		%	23.1		%	24.7		%
SG&A as a % of revenue	12.0		%	17.4		%	13.5		%	16.8		%
Project development expenses as a % of revenue	2.6		%	2.6		%	2.6		%	2.9		%

FINANCIAL RESULTS (Thousands)

Energy service contract revenues	$	46,494		$	35,311		$	81,933		$	69,775
Energy service contract costs	36,136			26,263			63,001			52,521
Net operating revenues	10,358			9,048			18,932			17,254

Selling, general and administrative expenses	5,572			6,145			11,088			11,689
Impairment of long-lived asset, net	5,320			—			5,320			—
Amortization of goodwill	—			954			—			1,918
Depreciation and depletion	444			471			881			950
Total expenses	11,336			7,570			17,289			14,557

Equity earnings from nonconsolidated investments	366			3,166			1,945			4,759

EBIT (Losses before interest and taxes)	$	(612	)	$	4,644		$	3,588		$	7,456

Three Months Ended June 30, 2002

vs. Three Months Ended June 30, 2001

NORESCO’s EBIT decreased $5.2 million to a loss of $0.6 million from earnings of $4.6 million in the same period last year. This decrease in EBIT is primarily attributable to a write-off of $5.3 million for the Jamaica power plant, partially offset by the elimination of $1.0 million in amortization of goodwill. Total revenue increased by 32% to $46.5 million, compared to $35.3 million in 2001, due to an increase in performance contracting construction activity.

NORESCO made a non-recourse investment of $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 down the project by $5.3 million in accordance with Statement No. 144.

Revenue backlog in the current year increased $66.6 million from $90.8 at June 30, 2001 to $157.4 million at June 30, 2002 due to increased backlog in both energy infrastructure and performance contracting projects. A significant portion of the increase is due to a contract signed during the quarter for a large domestic energy infrastructure project located in California.

NORESCO’s second quarter 2002 gross margin increased to $10.4 million compared to $9.0 million during the second quarter 2001 due to an increase in construction volume activity. Gross margin as a percentage of revenue decreased from 25.6% in the second quarter 2001 to 22.3% in the second quarter 2002. 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.

Equity in earnings from power plant investments during the second quarter 2002 declined to $0.4 million from $3.2 million during the second quarter 2001. This reduction is primarily due to lower equity in earnings from one power plant in Panama.

Total expenses including the Jamaica power plant write-down were $11.3 million for the second quarter 2002 versus $7.6 million for the same period in 2001. Excluding the Jamaica write-down of $5.3 million in 2002 and the elimination of the $1.0 million of goodwill amortization in 2001, total expenses for the second quarter 2002 of $6.0 million compared to $6.6 million in the second quarter 2001 were essentially flat.

Six Months Ended June 30, 2002

vs. Six Months Ended June 30, 2001

NORESCO’s EBIT decreased $3.9 million to $3.6 million from $7.5 million in the same period last year. This decrease is primarily attributable a write-off of $5.3 million for the Jamaica power plant, partially offset by $1.9 million in reduced goodwill amortization. Revenue increased by 17% to $81.9 million compared to $69.8 million in 2001, which is due to an increase in construction activity.

NORESCO’s gross margin increased to $18.9 million compared to $17.3 million during the first half of 2001 primarily due to an increase in construction activity. Gross margin as a percentage of revenue decreased to 23.1% in the first half of 2002 compared to 24.7% 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.

Equity in earnings from power plant investments during the six months ended June 30, 2002 declined to $1.9 million from $4.8 million during the first half 2001. This reduction is primarily due to reduced equity in earnings from one power plant in Panama.

Total expenses including the Jamaica power plant write-down were $17.3 million versus $14.6 million for the same period in 2001. Excluding the Jamaica write-down of $5.3 million in 2002 and the elimination of $1.9 million of goodwill amortization in 2001, total expenses were $12.0 million compared to $12.7 million in the same period in 2001.

EQUITY IN NONCONSOLIDATED INVESTMENTS

On April 10, 2000, Equitable merged its Gulf of Mexico operations with Westport Oil and Gas Company for approximately $50 million in cash and approximately 49% minority interest in the combined company, named Westport Resources Corporation. Equitable accounted for this investment under the equity method of accounting. In October 2000, Westport completed an initial public offering (IPO) of its shares. Equitable 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 continues to own 13.9 million shares, which represents approximately 27% of Westport’s total shares outstanding at June 30, 2002. Equitable’s investment in Westport was $143.2 million as of June 30, 2002 and the aggregate market value of this investment was $228.0 million as of June 30, 2002. The Company has recognized a loss of $4.9 million year to date in the equity earnings from nonconsolidated investments on the Statements of Consolidated Income.

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. The Company retained a 1% interest and negotiated arms-length, market-based rates for gathering, marketing and operating fees with the trust in order to deliver their natural gas to the market. Additionally, the Company also receives a market-based fee for providing a restricted line of credit to the trust that is limited by the fair market value of their remaining services. The Company treats oil and gas trust interests 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 whereby they 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, Capital Center Energy, began incurring billing disputes. The Company has reserved for the amounts in dispute pending resolution of the issues. These disputes adversly affect the cash flows and the financial stability of the project and could trigger project loan document covenant violations, particularly if resolution of the issues is further delayed.

One of the Company’s two Panamanian projects is a party to a five-year PPA with Petroelectrica de Panama, which expires in February 2003. Coterminous 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. 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 the plant to conform to environmental noise standards by a target date of August 31, 2001. Unforeseen events have delayed the final completion date of the required retrofits. The project has obtained an extension from the creditor sponsor and Panamanian regulators until September 2, 2002. Currently, the Company is pursuing other options should the retrofits not bring the plant into compliance including; regulatory waiver, land acquisition, and/or rezoning. The Company is coordinating with the creditor sponsor to timely obtain any additional regulatory extensions which may be required.

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 working with the creditor sponsor on this matter and has experienced improvement in operational and financial performance. It expects continued recovery by the end of 2002.

CAPITAL RESOURCES AND LIQUIDITY

Operating Activities

The results of operations of Equitable are impacted by the seasonal nature of Equitable Utilities’ distribution operations and the volatility of oil and gas commodity prices. As such, net income decreased due primarily to lower commodity prices as well as from a loss in the Company’s unconsolidated investment in Westport.

Cash flows from operating activities in the first half of 2002 were $176.6 million, an increase of $47.8 million, from $128.8 million in the prior year period. Payments made to reduce payables in the first half of 2001 were inflated primarily due to high commodity prices experienced at the end of 2000 and beginning of 2001.

Items included in net income but not affecting operating cash flows include decreased undistributed earnings from the Company’s unconsolidated investments and continued deferred revenue recognition of monetized production revenue. Additionally, in December 2000, the Company entered into several prepaid natural gas sales in order to limit its exposure to commodity volatility, to reduce counterparty risk and to raise capital. The cash from these transactions was recorded as operating activity in the Statements of Cash Flows upon receipt and the subsequent recognition of revenue on the Statements of Consolidated Income as the gas is delivered is a non-cash item, which is properly included in operating activity.

Investing Activities

Cash flows used by investing activities in the first half of 2002 were $22.8 million compared to $8.7 million in the prior year. The change from the prior year is attributable to an increase in capital expenditures of $42.2 million and timing differences in the recognition of proceeds from the sales of contract receivables, both of which are 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 $64.0 million and $22.3 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. Subsequently, 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 six months of 2002 were $176.9 million compared to $168.6 million in the prior year period. In 2002, Equitable continued to reduce its short-term debt and buy back shares of its outstanding common 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 at expected levels and remediation efforts have been ineffective. As a result, in the second quarter of 2002, the Company wrote down the project by $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 $325 million of available credit, and a 364-day credit agreement providing $325 million of available credit that expire in 2003 and 2002, respectively. As of June 30, 2002, the Company has the authority and credit backing to support a $650 million commercial paper program.

Hedging

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

With respect to hedging the Company’s exposure to changes in natural gas commodity prices, management’s objective is to provide price protection for the majority of expected production for the years 2002 through 2005, and over 25% of expected equity production for the years 2006 through 2008. Its preference is to use derivative instruments that create a price floor, in order to provide downside protection while allowing the Company to participate in upward price movements. This is accomplished with the use of a mix of costless collars, straight floors and some fixed price swaps. This mix allows the Company to participate in a range of prices, while protecting shareholders from significant price deterioration. The Company also engages in basis swaps to mitigate the fixed price exposure inherent in its firm capacity commodity commitments. During the quarter ended June 30, 2002 the Company hedged approximately 27 Bcf of natural gas basis exposure through March 2008.

Dividend

On July 18, 2002, the Board of Directors of Equitable Resources declared a regular quarterly cash dividend of 17 cents per share, payable September 1, 2002 to shareholders of record on August 16, 2002.

Schedule of Certain Contractual Obligations

Below is a table that details the future projected payments for the Company’s significant contractual obligations as of June 30, 2002.

	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(Thousands)

Interest expense	$	692,185	$	15,877	$	87,959	$	55,141	$	533,208
Long-term debt	287,631		—		44,800		13,000		229,831
Unconditional purchase obligations	182,212		10,452		60,557		36,906		74,297

Total contractual cash obligations	$	1,162,028	$	26,329	$	193,316	$	105,047	$	837,336

Included in long-term debt is a current portion of non-recourse project financing in the amount of $16.4 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.

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 63.0 Bcfe of proved developed producing reserves and 5.0 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 like kind exchange for certain identified assets. Subsequently, the restrictions lapsed and the cash has been made available for operations.

Certain Trading Activities Accounted for at Fair Value

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

Fair value of contracts outstanding at December 31, 2001	$	4,159
Contracts realized or otherwise settled	(8,791		)
Other changes in fair value	526
Fair value of contracts outstanding at June 30, 2002	$	(4,106	)

The following table presents maturities and the fair valuation source for the Company’s derivative commodity instruments that are held for trading purposes as of June 30, 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)	$	(2,994	)	$	(1,280	)	$	—		$	—	$	(4,274	)
Prices provided by other external sources(2)	(495		)	3,011			1,775			73		4,364
Prices based on models and other valuation methods(3)	(547		)	(1,763		)	(1,886		)	—		(4,196		)
Net derivative (liabilities) assets	$	(4,036	)	$	(32	)	$	(111	)	$	73	$	(4,106	)

(1) Contracts include futures and fixed price swaps

(2) Contracts include physical, transport and basis swaps

(3) Contracts include demand charges and other fees

Critical Accounting Policies

Unconsolidated Investment in Westport – The Company files its financial statements earlier than Westport. As a result, Westport's financial results included in their filings may differ from those used by the Company to record its investment. Any differences that result are recorded by the Company in subsequent periods.

Sale Treated as Normal Retirement – When a portion of production property is sold, may be treated as a normal retirement with no gain or loss recognized, rather than an asset sale. This would occur when the quantity of reserves sold is not significant with respect to total reserves retained or when the selling price per unit of reserves sold does not differ significantly from the cost depletion rate.

Stock Based Compensation – The Company will contemplate applying Statement 123 for stock option expense by the end of 2002 and is currently evaluating the best method of determining that expense.

The FASB issued an exposure draft for a proposed interpretation of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” and Statement No. 94, “Consolidation of All Majority-Owned Subsidiaries,” that would address the consolidation of special-purpose entities (SPEs). The proposed effective date would be applied to those SPEs still in existence as of the beginning of the first fiscal year or interim period beginning after March 15, 2003. The proposed interpretation would require existing unconsolidated SPEs that lack sufficient independent economic substance to be consolidated by primary beneficiaries if they do not effectively disperse risks among parties involved. SPEs that effectively disperse risks would not be consolidated unless a single party holds an interest or combination of interests that effectively recombines risks that were previously dispersed. The Company will make a determination of the impact once the interpretation has been finalized.

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 227.8 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 $95.4 million at June 30, 2002.

With respect to derivative contracts held by the Company for trading purposes, as of June 30, 2002, a decrease of 10% in the market price of natural gas would increase the fair market value by approximately $6.0 million.

See also Footnote C regarding Derivative Instruments and Cash Flow Hedges in the Notes to Condensed Consolidated Financial Statements. Additionally see Hedging in the Capital Resources and Liquidity section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

PART II. OTHER INFORMATION

Item 5. Submission of Matters to a Vote of Security Holders

a). The Annual Meeting of Shareholders was held on May 16, 2002.

c). Brief description of matters voted upon:

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

Director	Shares Voted For	Shares Withheld

Phyllis A. Domm, Ed.D.	56,795,513	699,726
David L. Porges	57,134,624	360,615
James E. Rohr	56,737,795	757,444
David S. Shapira	56,809,658	685,581

The following Directors terms continue after the Annual Meeting of Shareholders:
until 2003 – E. Lawrence Keyes, Jr., Thomas A. McConomy, Malcolm M. Prine;
until 2004 – Murry S. Gerber, George L. Miles, Jr., J. Michael Talbert

(2) Ratified appointment of Ernst & Young, LLP, as independent auditors for the year ended December 31, 2002. Vote was 55,509,689 shares for; 1,904,463 shares against and 81,087 shares abstained.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits:

10.1		Equitable Resources, Inc. 2002 Executive Performance Incentive Share Plan

10.2		Equitable Resources, Inc. 2002 Short-Term Incentive Plan

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

Form 8-K current report dated June 11, 2002 announcing the anticipated retirement in the second half of 2003 of Gregory R. Spencer as Senior Vice President and Chief Administrative Officer of Equitable Resources, Inc.

CERTIFICATION

In connection with the Quarterly Report of Equitable Resources, Inc. (the "Company") on Form 10-Q for the period ending June 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	August 8, 2002
Murry S. Gerber, Chairman,
President and Chief Executive Officer




/s/ David L. Porges	August 8, 2002
David L. Porges, Executive Vice President
and Chief Financial Officer

Signature

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

		EQUITABLE RESOURCES, INC.
		(Registrant)


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

Date: August 8, 2002

INDEX TO EXHIBITS

Exhibit No.	Document Description


10.1	Equitable Resources, Inc. 2002 Executive Performance Incentive Share Plan	Filed Herewith

10.2	Equitable Resources, Inc. 2002 Short-Term Incentive Plan	Filed Herewith

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

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

Equitable Resources, Inc. and Subsidiaries

Equitable Resources, Inc. and Subsidiaries

Distribution Operations

Pipeline Operations

Equitable Marketing

Production: