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, 2005
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM                TO
COMMISSION FILE NUMBER 1-3551

EQUITABLE RESOURCES, INC.

(Exact name of registrant as specified in its charter)

PENNSYLVANIA	25-0464690
(State of incorporation or organization)	(IRS Employer Identification No.)
225 North Shore Drive, Pittsburgh, Pennsylvania 15212
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: (412) 553-5700
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ý  No  o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes  ý  No  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o  No  ý

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

Class	Outstanding at September 30, 2005
Common stock, no par value	120,872,600 shares

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Index

Part I. Financial Information:
Item 1.	Financial Statements (Unaudited):
	Statements of Consolidated Income for the Three and Nine Months Ended September 30, 2005 and 2004
	Statements of Condensed Consolidated Cash Flows for the Nine Months Ended September 30, 2005 and 2004
	Condensed Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004
	Notes to Condensed Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures About Market Risk
Item 4.	Controls and Procedures
Part II. Other Information:
Item 1.	Legal Proceedings
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.	Exhibits
Signature
Index to Exhibits

2

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2005		2004			2005			2004
	(Thousands, except per share amounts)
Operating revenues	$	264,528	$	205,847		$	973,326		$	846,914
Cost of sales	91,814		63,238			414,470			354,416
Net operating revenues	172,714		142,609			558,856			492,498
Operating expenses:
Operation and maintenance	22,891		20,985			71,599			59,954
Production	15,327		11,111			44,523			32,587
Selling, general and administrative	53,017		24,177			119,354			103,560
Impairment charges	—		—			7,835			—
Depreciation, depletion and amortization	23,505		21,809			70,320			65,186
Total operating expenses	114,740		78,082			313,631			261,287
Operating income	57,974		64,527			245,225			231,211
Gain on sale and tender of available-for-sale securities, net	19,438		—			80,257			3,024
Gain on exchange of Westport for Kerr-McGee shares	—		—			—			217,212
Charitable foundation contribution	—		—			—			(18,226		)
Earnings (losses) from nonconsolidated investments:
International investments	1,505		(3		)	9,352			(39,137		)
Other	220		235			444			613
	1,725		232			9,796			(38,524		)
Other income, net	—		1,602			1,195			2,178
Minority interest income (expense)	94		(105		)	(652		)	(834		)
Interest expense	12,169		12,191			37,602			35,953
Income before income taxes	67,062		54,065			298,219			360,088
Income taxes	20,571		18,382			111,003			123,508
Net income	$	46,491	$	35,683		$	187,216		$	236,580
Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	121,181		122,838			121,359			123,816
Net income	$	0.38	$	0.29		$	1.54		$	1.91
Diluted:
Weighted average common shares outstanding	123,576		125,660			124,016			126,556
Net income	$	0.38	$	0.28		$	1.51		$	1.87
Dividends declared per common share	$	0.21	$	0.19		$	0.63		$	0.53

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

3

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Condensed Consolidated Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2005			2004
	(Thousands)
Cash flows from operating activities:
Net income	$	187,216		$	236,580
Adjustments to reconcile net income to cash (used in) provided by operating activities:
Provision for losses on accounts receivable	5,395			10,552
Depreciation, depletion, and amortization	70,320			65,186
Gain on sale and tender of available-for-sale securities, net	(80,257		)	(3,024		)
Impairment charges	7,835			—
Change in nonconsolidated investments	(7,835		)	40,251
Deferred income taxes	(77,968		)	33,030
Gain on exchange of Westport for Kerr-McGee shares	—			(217,212		)
Charitable foundation contribution	—			18,226
Recognition of prepaid forward production revenue	—			(10,363		)
Amendment of prepaid forward contract	—			(36,792		)
Loss on amendment of prepaid forward contract	—			5,532
Change in undistributed earnings from nonconsolidated investments	(1,920		)	(1,727		)
Increase in accounts receivable and unbilled revenues	(455,656		)	(7,663		)
Increase in inventory	(53,734		)	(49,695		)
Changes in other assets and liabilities	(45,084		)	50,490
Total adjustments	(638,904		)	(103,209		)
Net cash (used in) provided by operating activities	(451,688		)	133,371
Cash flows from investing activities:
Capital expenditures	(194,113		)	(134,975		)
Purchase of interest in Eastern Seven Partners L.P.	(57,500		)	—
Proceeds from sale of Kerr-McGee shares	394,901			42,880
Investment in available-for-sale securities	(3,769		)	—
Proceeds from sale of investment interest in Dona Julia	3,000			—
Proceeds from sale of properties	141,991			—
Distributions from nonconsolidated investments	627			1,152
Net cash provided by (used in) investing activities	285,137			(90,943		)
Cash flows from financing activities:
Dividends paid	(74,615		)	(65,889		)
Proceeds from exercises under employee compensation plans	23,808			24,458
Purchase of treasury stock	(84,501		)	(89,766		)
Loans against construction contracts	20,288			30,931
Repayments and retirement of long-term debt	(10,432		)	(20,895		)
Proceeds from issuance of long-term debt	150,000			—
Increase in short-term loans	142,003			41,399
Net cash provided by (used in) financing activities	166,551			(79,762		)
Net decrease in cash and cash equivalents	—			(37,334		)
Cash and cash equivalents at beginning of period	—			37,334
Cash and cash equivalents at end of period	$	—		$	—
Cash paid during the period for:
Interest, net of amount capitalized	$	40,984		$	37,758
Income taxes paid, net of refund	$	183,635		$	13,990

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

4

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	September 30, 2005			December 31, 2004
	(Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	—
Accounts receivable (less accumulated provision for doubtful accounts: September 30, 2005, $20,496, December 31, 2004, $31,336)	714,782			238,560
Unbilled revenues	137,261			149,060
Inventory	257,619			204,585
Derivative instruments, at fair value	151,511			27,585
Prepaid expenses and other	38,157			32,859
Total current assets	1,299,330			652,649
Equity in nonconsolidated investments	37,080			64,556
Property, plant and equipment	3,136,502			2,967,916
Less: accumulated depreciation and depletion	1,153,019			1,088,129
Net property, plant and equipment	1,983,483			1,879,787
Investments, available-for-sale	94,129			426,772
Deferred income taxes	38,147			—
Other assets	174,123			172,782
Total assets	$	3,626,292		$	3,196,546
LIABILITIES AND STOCKHOLDERS EQUITY
Current liabilities:
Current portion of long-term debt	$	3,623		$	10,582
Short-term loans	437,502			295,499
Accounts payable	172,551			187,797
Derivative instruments, at fair value	1,589,603			350,382
Other current liabilities	184,419			171,057
Total current liabilities	2,387,698			1,015,317
Debentures and medium-term notes	764,296			617,769
Deferred income taxes and investment tax credits	10,243			497,278
Other credits	197,316			191,510
Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares; shares issued: September 30, 2005 and December 31, 2004, 149,008	356,975			356,892
Treasury stock, shares at cost: September 30, 2005, 28,135; December 31, 2004, 26,946 (net of shares and cost held in trust for deferred compensation of 1,331, $13,024 and 1,284, $12,303)	(453,209		)	(389,450		)
Retained earnings	1,200,178			1,087,577
Accumulated other comprehensive loss	(837,205		)	(180,347		)
Total common stockholders’ equity	266,739			874,672
Total liabilities and stockholders’ equity	$	3,626,292		$	3,196,546

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

5

Equitable Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

A.Financial Statements

The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Equitable Resources, Inc. and its consolidated subsidiaries. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of Equitable Resources, Inc. and subsidiaries as of September 30, 2005, and the results of its operations and cash flows for the three- and nine-month periods ended September 30, 2005 and 2004.

The balance sheet at December 31, 2004 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements.

Due to the seasonal nature of the Company’s natural gas distribution and energy marketing businesses and the volatility of natural gas prices, the interim statements for the three- and nine-month periods ended September 30, 2005 are not necessarily indicative of the results that may be expected for the year ending December 31, 2005.

For further information, refer to the consolidated financial statements and footnotes thereto included in Equitable Resources’ Annual Report on Form 10-K for the year ended December 31, 2004, as well as in “Information Regarding Forward Looking Statements” on page 16 of this document.

B.Segment Information

The Company reports its operations in three segments, which reflect its lines of business. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income and earnings from nonconsolidated investments. Interest expense and income taxes are managed on a consolidated basis.

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

6

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(Thousands)
Revenues from external customers:
Equitable Utilities	$	130,566		$	94,297		$	567,538		$	514,248
Equitable Supply	127,252			98,650			352,736			290,403
NORESCO	35,156			37,366			112,484			106,992
Less: intersegment revenues (a)	(28,446		)	(24,466		)	(59,432		)	(64,729		)
Total	$	264,528		$	205,847		$	973,326		$	846,914
Total operating expenses:
Equitable Utilities	$	43,641		$	31,317		$	116,920		$	102,894
Equitable Supply	47,351			39,746			144,312			117,243
NORESCO	6,013			5,487			18,737			17,793
Unallocated expenses	17,735			1,532			33,662			23,357
Total	$	114,740		$	78,082		$	313,631		$	261,287
Operating income:
Equitable Utilities	$	(7,477	)	$	3,680		$	60,582		$	70,680
Equitable Supply	79,901			58,904			208,424			173,160
NORESCO	3,285			3,475			9,881			10,728
Unallocated expenses	(17,735		)	(1,532		)	(33,662		)	(23,357		)
Total operating income	$	57,974		$	64,527		$	245,225		$	231,211
Reconciliation of operating income to net income:
Earnings (losses) from nonconsolidated investments:
Equitable Supply	$	131		$	185		$	261		$	465
NORESCO	1,509			10			9,383			(39,105		)
Unallocated	85			37			152			116
Total	$	1,725		$	232		$	9,796		$	(38,524	)
Gain on sale and tender of available-for-sale securities, net	19,438			—			80,257			3,024
Gain on exchange of Westport for Kerr-McGee shares	—			—			—			217,212
Charitable foundation contribution	—			—			—			(18,226		)
Other income, net	—			1,602			1,195			2,178
Minority interest income (expense) - NORESCO	94			(105		)	(652		)	(834		)
Interest expense	12,169			12,191			37,602			35,953
Income taxes	20,571			18,382			111,003			123,508
Net income	$	46,491		$	35,683		$	187,216		$	236,580

	September 30, 2005		December 31, 2004
	(Thousands)
Segment Assets:
Equitable Utilities	$	1,381,074	$	1,201,400
Equitable Supply	1,971,919		1,514,176
NORESCO (b)	221,911		197,201
Total operating segments	3,574,904		2,912,777
Headquarters assets, including cash and short-term investments	51,388		283,769
Total	$	3,626,292	$	3,196,546

7

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
	(Thousands)
Expenditures for segment assets:
Equitable Utilities	$	18,710	$	13,857	$	40,283	$	43,427
Equitable Supply (c)	53,535		40,003		201,348		90,385
NORESCO	143		193		434		385
Unallocated expenditures (d)	783		387		9,548		778
Total	$	73,171	$	54,440	$	251,613	$	134,975

(a)	Intersegment revenues primarily represent sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities.
(b)	The Company’s goodwill balance as of September 30, 2005 and December 31, 2004 totaled $51.8 million and is entirely related to the NORESCO segment.
(c)	Capital expenditures for the nine months ended September 30, 2005 include $57.5 million for the acquisition of the limited partnership interest in Eastern Seven Partners L.P.
(d)	Unallocated expenditures for the nine months ended September 30, 2005 include costs for the relocation of the Company’s corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh, which are intended to be allocated to the lines of businesses.

C.Derivative Instruments

Natural Gas Hedging Instruments

The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Exchange-traded instruments are generally settled with offsetting positions. Over the Counter (OTC) arrangements require settlement in cash. The fair value of these derivative commodity instruments was a $146.0 million asset and a $1.5 billion liability as of September 30, 2005, and a $26.8 million asset and a $350.4 million liability as of December 31, 2004. These amounts are included in the Condensed Consolidated Balance Sheets as derivative instruments, at fair value. The net amount of derivative instruments, at fair value, changed from a net liability of $323.6 million at December 31, 2004 to a net liability of $1.4 billion at September 30, 2005, primarily as a result of the increase in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 436.0 Bcf and 432.6 Bcf as of September 30, 2005 and December 31, 2004, respectively, and primarily related to natural gas swaps. The open positions at September 30, 2005 had maturities extending through December 2012.

The Company deferred net losses of $839.9 million and $197.3 million in accumulated other comprehensive loss, net of tax, as of September 30, 2005 and December 31, 2004, respectively, associated with the effective portion of the change in fair value of its derivative instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $387.5 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of September 30, 2005 will be recognized in earnings during the next twelve months. This recognition occurs through a reduction in the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.

For the three months ended September 30, 2005, ineffectiveness associated with the Company’s derivative instruments designated as cash flow hedges increased earnings by approximately $0.5 million while it decreased earnings by approximately $0.4 million for the three months ended September 30, 2004. These amounts are included in operating revenues in the Statements of Consolidated Income.

The Company conducts trading activities through its unregulated marketing group. The function of the Company’s trading business is to contribute to the Company’s earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy.

The absolute notional quantities of the futures and swaps held for trading purposes at September 30, 2005 totaled 14.4 Bcf and 54.3 Bcf, respectively.

8

Below is a summary of the activity of the fair value of the Company’s derivative commodity contracts with third parties held for trading purposes during the nine months ended September 30, 2005 (in thousands).

Fair value of contracts outstanding as of December 31, 2004	$	481
Contracts realized or otherwise settled	(504		)
Other changes in fair value	(410		)
Fair value of contracts outstanding as of September 30, 2005	$	(433	)

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, 2005.

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

Source of Fair Value	Maturity Less than 1 Year			Maturity 1-3 Years			Maturity 4-5 Years		Maturity in Excess of 5 Years		Total Fair Value
	(Thousands)
Prices actively quoted (NYMEX) (1)	$	(302	)	$	49		$	—	$	—	$	(253	)
Prices provided by other external sources (2)	15			(195		)	—		—		(180		)
Net derivative (liabilities) assets	$	(287	)	$	(146	)	$	—	$	—	$	(433	)

(1) Contracts include futures and fixed price swaps

(2) Contracts include basis swaps

When the net fair value of any of the swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company recorded such deposits in the amount of $382.7 million as accounts receivable in its Condensed Consolidated Balance Sheet as of September 30, 2005.

When the Company enters into exchange-traded natural gas contracts, exchanges require participants, including the Company, to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related contract and are subject to change at the exchanges’ discretion. The Company recorded such margin deposits in the amount of $167.2 million as accounts receivable in its Condensed Consolidated Balance Sheet as of September 30, 2005.

As part of the purchase of the limited partnership interest in Eastern Seven Partners, L.P. (ESP), as discussed in Note N, the Company assumed derivative liabilities of $47.3 million for the fair value of ESP’s hedges. These hedges were effectively closed out at acquisition by the purchase of offsetting positions. The Company does not treat these derivatives as hedging instruments under Statements of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The fair value of these derivative instruments at September 30, 2005 was a $38.6 million liability. These amounts are included in the Condensed Consolidated Balance Sheet as derivative instruments, at fair value.

In May 2005, the Company sold certain non-core gas properties, as discussed in Note N. As part of this transaction, the Company closed out certain cash flow hedges associated with forecasted production at these locations by purchasing offsetting positions. The Company does not treat these derivatives as hedging instruments under SFAS 133. The fair value of these derivative instruments at September 30, 2005 was a $22.0 million liability. These amounts are included in the Condensed Consolidated Balance Sheet as derivative instruments, at fair value.

D.Investments

In September 2005, the Company sold approximately 0.4 million Kerr-McGee Corporation (Kerr-McGee) shares for total proceeds of $40.6 million. The sale of those shares resulted in a pre-tax gain to the Company of $19.4 million.

As of September 30, 2005, the Company held approximately 0.7 million Kerr-McGee shares, which were held for sale. See Note R.

The Company recorded pre-tax dividend income related to the Kerr-McGee shares of $1.2 million and $1.6 million for the nine months ended September 30, 2005 and 2004, respectively. This dividend income is recorded in other income, net on the Statements of Consolidated Income.

9

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

In July 2004, the Company entered into three 7.5 year secured variable share forward transactions in association with the Westport Resources Corporation (Westport)/Kerr-McGee merger, each covering 2.0 million shares of Kerr-McGee common stock. The related collars effectively limited the Company’s cash flow exposure upon the forecasted disposal of 6.0 million Kerr-McGee shares.

In May 2005, the Company terminated the three variable share forward transactions. In connection with the termination, the Company incurred a termination cost of $95.8 million and sold 4.3 million Kerr-McGee shares to its three counterparties to cover its counterparties’ respective hedged positions. The Company received $227.4 million in pre-tax net proceeds from the sale of the Kerr-McGee shares net of the termination cost. In addition, the Company unconditionally tendered 1.7 million Kerr-McGee shares at $85.00 per share to Kerr-McGee in connection with Kerr-McGee’s Dutch auction tender offer to purchase its own shares. Accordingly, as a result of its tender of shares, the Company received approximately $49 million in pre-tax proceeds on the sale of approximately 0.6 million shares.

In the second quarter of 2004, Westport and Kerr-McGee completed a merger. Under the terms of the merger agreement, the Company received 0.71 shares of Kerr-McGee for each Westport share owned, or 8.2 million shares of Kerr-McGee. Accordingly, the Company recognized a gain of $217.2 million on the exchange of the Westport shares for Kerr-McGee shares in the second quarter of 2004.

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

On June 30, 2004, the Company committed to contribute 357,000 Kerr-McGee shares to Equitable Resources Foundation, Inc. This resulted in the Company recording a charitable foundation contribution expense of $18.2 million during the second quarter of 2004, with a corresponding one-time tax benefit of $6.8 million.

As of September 30, 2005, the investments classified by the Company as available-for-sale included a $69.3 million investment in Kerr-McGee and $24.8 million of debt and equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures through a wholly-owned subsidiary.

E.Comprehensive Loss

Total comprehensive loss, net of tax, was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(Thousands)
Net income	$	46,491		$	35,683		$	187,216		$	236,580
Other comprehensive loss:
Net change in cash flow hedges:
Natural gas (Note C)	(398,818		)	(102,216		)	(642,645		)	(171,191		)
Interest rate	29			358			87			368
Gain on exchange of Westport stock	—			—			—			(143,360		)
Unrealized gain (loss) on investments, available-for-sale (Note D):
Westport	—			—			—			43,731
Kerr-McGee	2,334			35,765			(14,411		)	33,875
Other	218			(403		)	111			(281		)
Total comprehensive loss	$	(349,746	)	$	(30,813	)	$	(469,642	)	$	(278	)

10

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

	September 30, 2005			December 31, 2004
	(Thousands)
Net unrealized loss from hedging transactions	$	(840,743	)	$	(198,185	)
Unrealized gain on available-for-sale securities	23,229			37,529
Minimum pension liability adjustment	(19,691		)	(19,691		)
Accumulated other comprehensive loss	$	(837,205	)	$	(180,347	)

F.Stock-Based Compensation

Restricted stock grants in the aggregate amount of 75,400 shares were awarded to various employees during the first nine months of 2005. The related expense recognized during the nine-month period ended September 30, 2005 was $2.5 million and is classified as a selling, general and administrative expense in the Statements of Consolidated Income.

The Company continually monitors its stock price and relative return in order to assess the impact on the projected payout under each Executive Performance Incentive Program (the “Programs”). The Company’s share price assumptions used to determine the accrual for the Programs are $39.06 per share at the end of 2005 (for the 2003 Program) and $40.00 per share at the end of 2008 (for the 2005 Program). As a result of the Company’s significant stock appreciation during the second and third quarters of 2005, the Company recognized an expense of $15.3 million for the three months ended September 30, 2005 and an expense of $29.9 million for the nine months ended September 30, 2005 associated with the Programs. The related long-term incentive expenses are included in selling, general and administrative expenses in the Statements of Consolidated Income. A portion of the long-term incentive expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note B.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock Based Compensation” (SFAS No. 123) to its employee stock-based awards.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(Thousands)
Net income, as reported	$	46,491		$	35,683		$	187,216		$	236,580
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects	10,924			2,098			22,157			10,973
Deduct: Total stock-based employee compensation expense determined by the fair value method for all awards, net of related tax effects	(11,134		)	(2,923		)	(23,576		)	(13,891		)
Pro forma net income	$	46,281		$	34,858		$	185,797		$	233,662
Earnings per share:
Basic, as reported	$	0.38		$	0.29		$	1.54		$	1.91
Basic, pro forma	$	0.38		$	0.28		$	1.53		$	1.89
Diluted, as reported	$	0.38		$	0.28		$	1.51		$	1.87
Diluted, pro forma	$	0.37		$	0.28		$	1.50		$	1.85

G.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 that affects the estimated annual effective income tax rate are reflected as adjustments in the current period. Separate effective income tax rates are calculated for net income from continuing operations and any other separately reported net income items, such as discontinued operations, extraordinary items and cumulative effects of accounting changes.

Congress passed the American Jobs Creation Act of 2004, which the President signed into law on October 22, 2004. On September 29, 2005, the Treasury Department and the Internal Revenue Service issued proposed regulations providing deferred compensation guidance under the new legislation. During the third quarter of 2005, the Company continued its review of the legislation’s impact on its executive compensation plans. In anticipation that the Company’s executive compensation plans are expected to be changed by the Compensation Committee of the Board of Directors by

11

December 31, 2005, the Company adjusted its valuation allowance against the deferred tax benefit associated with the projected payout of these programs to $10.3 million.

The $10.3 million valuation allowance is included in the annual income tax expense related to continuing operations. The effective tax rate for the nine months ended September 30, 2005 was therefore 37.2%. The Company currently estimates the annual effective income tax rate to be approximately 36.4%, or 33.8% excluding the $10.3 million charge. The estimated annual effective income tax rate as of September 30, 2004 was 34.3%.

H.Pension and Other Postretirement Benefit Plans

The Company has defined benefit pension and other postretirement benefit plans covering represented employees that generally provide benefits of stated amounts for each year of service. During the third quarter of 2005, the Company settled its pension obligation with the United Steelworkers of America, Local Union 12050 representing 182 employees. As a result of this settlement, which was accounted for under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement expense of $12.7 million during the three months ended September 30, 2005. The settlement expense was primarily the result of accelerated recognition of unrecognized losses. As part of this settlement, the affected employees were provided the option to either roll over the lump-sum value of their pension benefit to the Company’s defined contribution plan or to receive an insured monthly annuity benefit at the time they retire. Additionally, this pension settlement expense is a selling, general and administrative expense included within operating expense of the Equitable Utilities business segment (see Note B). The Company’s ongoing pension obligation decreased by approximately $12.9 million as a result of the settlement.

The Company made a cash contribution of approximately $11.1 million to the pension plan in the second quarter of 2005 to fully fund the participants’ cash balance portion of the pension plan which was settled effective December 31, 2004. The Company made an additional contribution of approximately $1.5 million during the third quarter of 2005 in order to purchase annuities for participants choosing to receive benefits under an insurance contract. The Company expects to make a cash contribution of approximately $8.6 million to its pension plan during the fourth quarter of 2005 to fully fund the previously discussed settlement of the United Steelworkers of America, Local Union 12050 obligation.

The Company’s costs related to its defined benefit pension and other postretirement benefit plans for the three and nine months ended September 30, 2005 and 2004 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended September 30,
	2005			2004			2005			2004
	(Thousands)
Components of net periodic benefit cost
Service cost	$	225		$	398		$	135		$	120
Interest cost	1,379			1,743			792			818
Expected return on plan assets	(1,971		)	(2,457		)	—			—
Amortization of prior service cost	192			235			(11		)	(11		)
Recognized net actuarial loss	209			186			552			500
Settlement loss	13,809			983			—			—
Net periodic benefit cost	$	13,843		$	1,088		$	1,468		$	1,427
	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2005			2004			2005			2004
	(Thousands)
Components of net periodic benefit cost
Service cost	$	675		$	1,193		$	405		$	362
Interest cost	4,513			5,228			2,376			2,455
Expected return on plan assets	(6,062		)	(7,371		)	—			—
Amortization of prior service cost	575			705			(32		)	(32		)
Recognized net actuarial loss	698			559			1,655			1,500
Settlement loss	15,990			1,949			—			—
Net periodic benefit cost	$	16,389		$	2,263		$	4,404		$	4,285

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I.Recently Issued Accounting Standards

Stock Compensation

On December 16, 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123R). This guidance replaced previously existing requirements under SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), and Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB Opinion No. 25). Under SFAS No. 123(R), an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The compensation cost of the award would generally be measured based on the grant-date fair value of the award. The Company will be required to adopt SFAS No. 123(R) beginning with its 2006 fiscal year.

The Company has determined that the impact of SFAS No. 123(R) will not be material to its financial statements. In accordance with SFAS No. 123, the Company has historically disclosed the impact on the Company’s net income and earnings per share had the fair value based method been adopted.  Had the Company adopted SFAS No. 123(R) in prior periods, the impact of that standard on periods presented in these Condensed Consolidated Financial Statements would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in Note F.

Asset Retirement Obligations

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47). This interpretation clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity incurring the obligation. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN No. 47 will be effective for the Company at the end of the fiscal year ended December 31, 2005. FIN No. 47 is not expected to have a significant impact on the Company’s financial position or results of operations.

Accounting for Uncertain Tax Positions

In July 2005, the FASB issued an exposure draft of a proposed Interpretation, “Accounting for Uncertain Tax Positions – an Interpretation of FASB Statement No. 109.”   The proposed Interpretation would apply to all open tax positions accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes,” including those acquired in business combinations, and was proposed to be effective for the Company for the fiscal year ending December 31, 2005. The final interpretation has not been issued yet and may therefore not be effective for the fiscal year ending December 31, 2005. The Company will evaluate the impact of any change in accounting standard on the Company’s financial position and results of operations when the final interpretation is issued.

J.International Investments

During the second quarter of 2004, several negative circumstances caused the Company to revisit its international investments for additional impairments and to accelerate its plans to exit the international power generation business. As a result, the Company performed an impairment analysis of its equity interests in international projects during the second quarter of 2004. The Company recorded impairment charges totaling $40.2 million in the second quarter of 2004.

These charges included various costs and obligations related to exiting NORESCO’s investments in international power plant projects. These various costs and obligations were reviewed during the first nine months of 2005 and were reduced by $7.2 million primarily as a result of bringing the remaining power plant located in Panama into compliance with local noise restrictions without incurring costs that had previously been expected, the financial condition of the project, and the elimination of liquidity support.

The Company recorded earnings on its international investments in the amount of $1.5 million during the third quarter of 2005, due to the award of a new contract to sell electricity that has provided for improved forecasted cash flows for the power plant project in Panama.

K.Prepaid Natural Gas Forward Contract

In 2000, the Company entered into two prepaid natural gas sales contracts pursuant to which the Company was required to sell and deliver natural gas during the term of the contracts. The first contract was for five years; the

13

second contract was for three years and was completed at the end of 2003. These contracts were recorded as prepaid forward sales and were recognized in income as deliveries occurred.

In June 2004, the Company amended the remaining prepaid natural gas contract, which was viewed as debt by the rating agencies. The amendment required the Company to repay the net present value of the portion of the prepayment related to the undelivered quantities of natural gas in the original contract. The Company repaid the counterparty $36.8 million, removed the prepaid forward sale from the balance sheet and recorded a loss of $5.5 million in other income, net in the Statements of Consolidated Income for the nine months ended September 30, 2004, reflecting the difference between the net present value of the underlying quantities and the remaining unamortized balance recorded as deferred revenue.

L.Insurance Settlement

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

M.Office Consolidation / Impairment Charges

In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The relocation resulted in the early termination of several operating leases and the early retirement of assets and leasehold improvements at several locations. In accordance with SFAS No. 146, “Accounting for Costs associated with Exit or Disposal Activities,”the Company recognized a loss of $5.3 million on the early termination of operating leases during the second quarter of 2005 for facilities deemed to have no economic benefit to the Company. The Company also recognized a loss on impairment of assets of $2.5 million during the nine months ended September 30, 2005 in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” associated with the office consolidations.

N.Other Events

The Company retained Lincoln Partners LLC to assist it in considering strategic alternatives for its NORESCO segment, including but not limited to a sale, merger or other business combination.

On September 30, 2005, the Company issued $150 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015. The notes were approved by the Pennsylvania Public Utility Commission (PA PUC) on October 27, 2005. The effective annual interest rate on the $150 million of notes is 5.06%.

On August 11, 2005, the Company entered into a $650 million, 5-year revolving credit agreement, which may be used for working capital, capital expenditures, share repurchases and other lawful purposes including support of the Company’s commercial paper program. This agreement replaces the Company’s previous $500 million, three-year revolving credit agreement. Subject to certain terms and conditions the Company may on a one-time basis request that the lenders’ commitments be increased to an aggregate amount of up to $1 billion. The new facility has a maturity date of August 10, 2010 upon satisfaction of certain requirements relating to approval of the facility by the PA PUC which was received on October 27, 2005. Additionally, the Company may request two one-year extensions of the maturity date.

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for approximately $147 million. The proceeds were subject to $5.7 million of purchase price adjustments. The sale resulted in a decrease of 59 Bcf of proved developed reserves and 7 Bcf of proved undeveloped reserves.

In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million. The purchase added approximately 30 Bcfe of reserves.

O.Stock Split

On July 13, 2005, the Board of Directors of the Company declared a two-for-one stock split payable September 1, 2005, to shareholders of record on August 12, 2005. In connection with the stock split, the Company amended its articles of incorporation to reflect the increased number of authorized shares of common stock. All share and per share information has been retroactively adjusted to reflect the stock split.

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P.Share Repurchase Authorization Increase

On July 13, 2005, the Board of Directors of the Company increased the Company’s share repurchase authorization by 6.4 million shares to 50.0 million shares.

Q.Reclassification

Certain previously reported amounts have been reclassified to conform to the 2005 presentation. These reclassifications did not affect reported net income or cash flows.

R.Subsequent Events

In October 2005, the Company sold approximately 0.7 million Kerr-McGee shares for total proceeds of $65.6 million. The sale of these shares resulted in a pre-tax gain of $30.0 million. Following this sale, the Company has no further interest or ownership in any Kerr-McGee shares.

In October 2005, the Board of Directors of the Company authorized an increase in the Company’s short term borrowing authorization from $650 million to $1.0 billion.

15

Equitable Resources, Inc. and Subsidiaries

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

INFORMATION REGARDING FORWARD LOOKING STATEMENTS

Disclosures in this Quarterly Report on Form 10-Q contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “should,” “anticipate,” “estimate,” “forecasts,” “approximate,” “expect,” “may,” “will,” “project,” “intend,” “plan,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned “Outlook” in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s drilling program, production volumes, and earnings. 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:

•the impact of adverse weather conditions on commodity prices, Equitable Utilities’ operations, and Equitable Supply’s  well drilling program

•the volatility of the price of natural gas and the effect of changing prices on the Company’s revenues, hedging, well drilling activities, production taxes, and collections

•the need for, and availability and cost of, financing, including changes to the Company’s debt ratings by S&P and Moody’s

•the implementation and execution of operational enhancements and cost control initiatives

•the effect of curtailments or other disruptions in production and gathering

•the substance, timing and availability of regulatory and legislative actions, initiatives and proceedings

•the Company’s success in implementing acquisition or divestiture activities

•the ability of the Company to develop, produce, gather, and market reserves, including its ability to substantially increase well drilling activity

•the inherent uncertainty of estimating gas reserves and projecting future rates of production and reserve development

•the ability of the Company to acquire and apply technology to its operations

•the impact of competitive factors, including consolidation in the utility industry

•the ability of the Company to maintain good working relations with its represented employees and to retain its key personnel

•changes in the market price of the common stock of Equitable Resources, Inc. and its peer group

•general economic and political conditions

•changes in accounting rules or their interpretation, and

•other factors discussed in other reports filed by the Company from time to time.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.

CORPORATE OVERVIEW

Three Months Ended September 30, 2005
vs. Three Months Ended September 30, 2004

Equitable Resources’ consolidated net income for the three months ended September 30, 2005 totaled $46.5 million, or $0.38 per diluted share, compared to $35.7 million, or $0.28 per diluted share, reported for the same period a year ago. In the third quarter of 2005, the Company sold 0.4 million Kerr-McGee shares for a gain of $19.4 million.

Operating income for the quarter decreased to $58.0 million in 2005 from $64.5 million in 2004 primarily due to increased long-term incentive expenses associated with the Company’s Executive Performance Incentive Programs and a charge for the termination and settlement of a defined benefit pension plan for employees in the Equitable Utilities segment. For further discussion of the Company’s long-term incentive expense, see the “Incentive Compensation” section in the Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The impact of these items was offset somewhat by an increase in average natural gas prices and an increase in sales volumes from production primarily related to the acquisition of the limited partnership interest in ESP.

16

Nine Months Ended September 30, 2005
vs. Nine Months Ended September 30, 2004

Equitable Resources’ consolidated net income for the nine months ended September 30, 2005 totaled $187.2 million, or $1.51 per diluted share, compared to $236.6 million, or $1.87 per diluted share, reported for the same period a year ago. Several unusual factors both in 2005 and 2004 impacted the Company’s earnings. In 2005, the Company sold for a gain a substantial portion of its Kerr-McGee shares and reduced its obligations related to its exit from the international power generation market. This was partially offset by the pension settlement charge discussed previously, increased incentive compensation expense, the impact on income taxes from anticipated changes to the Executive Performance Incentive Programs and impairment charges related to office consolidation. In 2004, the gain recorded as a result of the Westport/Kerr-McGee merger and the proceeds received from an insurance settlement were offset by impairment charges related to the Company’s international investments, the charitable foundation contribution expense, and an amendment of the Company’s prepaid natural gas forward contract.

Operating income for the period increased to $245.2 million from $231.2 million, a 6.1% increase. This increase was primarily the result of an increase in average natural gas prices and an increase in sales volumes from production primarily related to the acquisition of the limited partnership interest in ESP. These increases to operating income were offset by the pension settlement, incentive compensation, and office consolidation impairment charges described previously, as well as additional expenses related to the operation of ESP, increased operating costs resulting from higher natural gas prices and increased depreciation, depletion and amortization expense from an increase in the unit depletion rate.

The Company has reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. Equitable’s management believes that presentation of this information provides useful information to management and investors regarding the financial condition, operations and trends of each of Equitable’s segments without being obscured by the financial condition, operations and trends for other segments or by the effects of corporate allocations of interest and income taxes. In addition, management uses these measures for budget planning purposes.

EQUITABLE UTILITIES

OVERVIEW

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

17

RESULTS OF OPERATIONS

EQUITABLE UTILITIES

	Three Months Ended September 30,								Nine Months Ended September 30,
	2005			2004			%		2005			2004			%
OPERATIONAL DATA
Heating Degree days (30 year normal average:
Qtr – 124; YTD – 3,759) (a)	34			88			(61.4	)	3,465			3,533			(1.9	)
Residential sales and transportation volumes (MMcf)	1,292			1,496			(13.6	)	16,838			18,292			(7.9	)
Commercial and industrial volumes (MMcf)	3,153			4,375			(27.9	)	18,258			22,130			(17.5	)
Total throughput (MMcf) – Distribution Operations	4,445			5,871			(24.3	)	35,096			40,422			(13.2	)
Total throughput (Bbtu) – Pipeline Operations	13,055			15,750			(17.1	)	45,961			54,384			(15.5	)
Net operating revenues (thousands):
Distribution Operations:
Residential	$	11,856		$	12,459		(4.8	)	$	72,771		$	75,829		(4.0	)
Commercial & industrial	4,903			5,730			(14.4	)	33,553			35,946			(6.7	)
Other	1,519			1,272			19.4		6,036			4,557			32.5
Total Distribution Operations	18,278			19,461			(6.1	)	112,360			116,332			(3.4	)
Pipeline Operations	10,311			11,112			(7.2	)	37,275			38,239			(2.5	)
Energy Marketing	7,575			4,424			71.2		27,867			19,003			46.6
Total net operating revenues	$	36,164		$	34,997		3.3		$	177,502		$	173,574		2.3
Total operating expenses as a % of net operating revenues	120.68		%	89.48		%			65.87		%	59.28		%
Operating income (thousands):
Distribution Operations	$	(16,362	)	$	(3,777	)	333.2		$	22,898		$	37,316		(38.6	)
Pipeline Operations	1,811			3,502			(48.3	)	11,065			15,817			(30.0	)
Energy Marketing	7,074			3,955			78.9		26,619			17,547			51.7
Total operating income	$	(7,477	)	$	3,680		(303.2	)	$	60,582		$	70,680		(14.3	)
Depreciation, depletion and amortization (DD&A):
Distribution Operations	$	4,830		$	5,454		(11.4	)	$	14,058		$	16,187		(13.2	)
Pipeline Operations	2,154			2,020			6.6		6,260			5,952			5.2
Energy Marketing	18			43			(58.1	)	56			128			(56.3	)
Total DD&A	$	7,002		$	7,517		(6.9	)	$	20,374		$	22,267		(8.5	)
Capital expenditures (thousands)	$	18,710		$	13,857		35.0		$	40,283		$	43,427		(7.2	)
FINANCIAL DATA (Thousands)
Utility revenues (regulated)	$	41,899		$	37,632		11.3		$	332,113		$	302,265		9.9
Marketing revenues	88,667			56,665			56.5		235,425			211,983			11.1
Total operating revenues	130,566			94,297			38.5		567,538			514,248			10.4
Utility purchased gas costs (regulated)	13,310			7,059			88.6		182,478			147,694			23.6
Marketing purchased gas costs	81,092			52,241			55.2		207,558			192,980			7.6
Net operating revenues	36,164			34,997			3.3		177,502			173,574			2.3
Operating expenses:
O&M	14,465			12,959			11.6		42,982			37,365			15.0
Selling, general and administrative (SG&A)	22,174			10,841			104.5		49,723			43,262			14.9
DD&A	7,002			7,517			(6.9	)	20,374			22,267			(8.5	)
Impairment charges	—			—			—		3,841			—			100.0
Total operating expenses	43,641			31,317			39.4		116,920			102,894			13.6
Operating income	$	(7,477	)	$	3,680		(303.2	)	$	60,582		$	70,680		(14.3	)

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

18

Three Months Ended September 30, 2005
vs. Three Months Ended September 30, 2004

Equitable Utilities’ incurred an operating loss of $7.5 million for the three months ended September 30, 2005 compared to operating income of $3.7 million for the three months ended September 30, 2004. The net change in operating income was primarily a result of a $12.7 million charge in the current quarter for the termination and settlement of a defined benefit pension plan.

Net operating revenues were $36.2 million for the three months ended September 30, 2005 compared to $35.0 million for the three months ended September 30, 2004. The $1.2 million increase in net operating revenues was due to a $3.2 million increase in energy marketing revenues, including the recognition of certain amounts previously deferred, and a $0.3 million increase in gathering revenues, offset somewhat by decreases of $1.2 million in Distribution Operations’ revenues and $0.8 million in Pipeline Operations revenues. Distribution Operations’ residential sales and transportation volumes decreased 204 MMcf from the three months ended September 30, 2004 to the three months ended September 30, 2005 primarily due to warmer September weather and a slight decrease in baseload usage. Distribution Operations’ commercial and industrial volumes decreased 1,222 MMcf from the three months ended September 30, 2004 to the three months ended September 30, 2005 primarily due to decreased purchases by two large industrial end use customers. Because these industrial sales generate small margins, the decreased volumes did not  significantly impact net operating revenues. Pipeline Operations’ total transportation throughput decreased 2,695 Bbtu from the three months ended September 30, 2004 to the three months ended September 30, 2005 primarily due to a reduction in firm transportation volumes resulting from the expiration of certain capacity contracts in the second quarter of 2005. The available capacity was remarketed by Pipeline Operations as lending and parking services. Revenue will be recognized when physical delivery occurs on these lending and parking services.

Operating expenses totaled $43.6 million for the three months ended September 30, 2005 compared to $31.3 million for the three months ended September 30, 2004. Operating expenses increased by $12.3 million primarily due to the $12.7 million pension charge described previously. SG&A expenses increased by $11.3 million primarily due to the $12.7 million pension charge offset by a $1.3 million reduction in bad debt expense, due to improved collections. DD&A expense decreased $0.5 million due to increases in the estimated useful lives for Equitable Gas’ main lines and service lines based on a PA PUC mandated asset service life study approved in the fourth quarter of 2004. Offsetting these improvements, a $1.5 million increase in O&M expense was primarily due to increased costs for fringe benefits ($0.5 million), pipeline gathering operations ($0.4 million), distribution customer collections ($0.3 million), and increased vehicle operation and maintenance costs in both the Distribution Operations and Pipeline Operations ($0.4 million).

Capital expenditures totaled $18.7 million for the three months ended September 30, 2005 compared to $13.9 million for the three months ended September 30, 2004. This $4.8 million increase was primarily due to the current year implementation of automated meter reading equipment on residential and commercial meters. This $17.5 million project commenced in the second quarter of 2005 and is expected to be completed in 2006.

Nine Months Ended September 30, 2005
vs. Nine Months Ended September 30, 2004

Equitable Utilities’ operating income totaled $60.6 million for the nine months ended September 30, 2005 compared to $70.7 million for the nine months ended September 30, 2004. The net change in operating income was primarily a result of the $12.7 million pension settlement expense and $3.8 million impairment charge in connection with the Company’s office consolidation incurred in the second quarter of 2005 offset by increased energy marketing revenues and reduced bad debt expense.

Net operating revenues were $177.5 million for the nine months ended September 30, 2005 compared to $173.6 million for the nine months ended September 30, 2004. The $3.9 million increase in net operating revenues was due to increased energy marketing and gathering revenues, partially offset by reductions in residential and industrial sales and pipeline transportation volumes. Heating degree days were 3,465 for the nine months ended September 30, 2005, which was substantially the same as the 3,533 heating degree days for the nine months ended September 30, 2004. Distributions Operations’ residential sales and transportation volumes decreased 1,454 MMcf from the nine months ended September 30, 2004 to the nine months ended September 30, 2005 primarily due to the slightly warmer weather and a small decrease in baseload usage. Distributions Operations’ commercial and industrial volumes decreased 3,872 MMcf from the nine months ended September 30, 2004 to the nine months ended September 30, 2005 primarily due to decreased demand from large industrial customers. Pipeline Operations’ total transportation throughput decreased 8,423 Bbtu from the nine months ended September 30, 2004 to the nine months ended September 30, 2005 primarily due to the expiration of certain firm transportation contracts. Revenue will be recognized when physical delivery occurs on these lending and parking services.

19

Operating expenses totaled $116.9 million for the nine months ended September 30, 2005 compared to $102.9 million for the nine months ended September 30, 2004. Operating expenses increased by $14.0 million primarily due to the pension settlement expense of $12.7 million and the office consolidation impairment charge of $3.8 million, both described previously. SG&A expenses increased $6.5 million primarily due to the $12.7 million pension charge and the $3.8 million office consolidation impairment charge offset by a $5.9 million reduction in bad debt expense, of which $2.0 million was attributable to an above normal reserve rate in the second quarter of 2004, with the balance a result of progress made on collections. The $1.9 million decrease in DD&A was primarily due to increased asset lives, from the mandated asset study described previously. These expense reductions over the nine month period are partially offset by a $5.6 million increase in O&M, primarily due to increases in fringe benefit rates ($2.1 million), customer collections expenses ($1.4 million), field gathering expenses ($0.8 million), and vehicle maintenance expenses ($0.6 million).

OUTLOOK

The interstate pipeline operations of Equitrans, L.P. (Equitrans) are subject to rate regulation by the Federal Energy Regulatory Commission (FERC). As a condition of Equitrans’ last FERC-approved rate settlement, the Company was obligated to file a rate case. The rate case applications filed to meet Equitrans’ filing obligation address several issues including establishing an appropriate return on the Company’s capital investments, the Company’s pension funding levels and accruing for post-retirement benefits other than pensions. The Company’s filed request for rate relief was for an aggregate annual amount of approximately $17.2 million.

Equitrans began charging the proposed rates, subject to refund, for its core services on September 1, 2004, and for its non-core services on December 1, 2004, consistent with orders issued by the FERC. Accordingly, Equitrans has set up a reserve, which will be adjusted upon ultimate resolution of the rate case.

Effective January 1, 2005, the Company reorganized its gathering business, subject to receipt of applicable approvals. This reorganization is consistent with the Company’s initiative to separate its production and gathering businesses in order to ensure that all gathering costs are appropriately captured and gathering rates charged to customers include a proper return. As a result, Equitrans effectively acquired certain gathering assets located in West Virginia from its affiliate, Equitable Field Services, LLC. The assets acquired by Equitrans overlap and are interconnected with gathering assets already owned and operated by Equitrans. The majority of the volumes that flow on these gathering assets are delivered to Equitrans’ transmission system. On January 28, 2005, Equitrans filed a limited rate case application with the FERC to consolidate the rates and operations of the Company’s interconnected and overlapping gathering facilities located in West Virginia and southern Pennsylvania, including the assets acquired on January 1, 2005. On February 28, 2005, in accordance with the Natural Gas Act, the FERC accepted and suspended the Company’s filing with the consolidated gathering rates to be effective August 1, 2005, subject to refund and to the outcome of a hearing. On August 1, 2005, Equitrans placed its suspended rates into effect as per the FERC’s order issued February 28, 2005.

On March 4, 2005, Equitrans requested and received approval to consolidate all of its rate applications pending before the FERC. Throughout the second and third quarters of 2005, numerous settlement conferences have been held with all active parties to the case, including the FERC’s staff, and given the progress made during these negotiations, multiple extensions to the procedural schedule (including the testimony filing and hearing dates) have been sought and obtained by Equitrans. On September 21, 2005, an agreement in principle was achieved with all but one of Equitrans’ storage and transmission customers (leaving only the issues associated with Equitrans’ gathering rates outstanding). Negotiations on gathering rate issues have been ongoing and are nearing completion. Equitrans is continuing to advance settlement discussions in this proceeding with the goal of achieving a comprehensive resolution of these cases.

Equitable Gas Company, the Company’s regulated distribution operation, continues to work with state regulators to shift the manner in which costs are recovered from traditional cost of service rate making to performance-based rate making. Performance-based incentives provide an opportunity for Equitable Gas to make short-term releases of unutilized pipeline capacity, i.e. “capacity releases,” for a fee or to participate in the bundling of gas supply and pipeline capacity for “off-system” sales. An “off-system” sale involves the purchase and delivery of gas to a customer at mutually agreed-upon points on facilities not owned by the Company. Equitable Gas’ performance-based purchased gas cost credit incentive and a second PA PUC approved performance-based initiative related to balancing services were available through September 2005. Effective September 30, 2005, an Opinion and Order issued by the PA PUC modified the performance-based purchased gas cost credit design on a prospective basis, providing Equitable Gas with a 25% sharing level of capacity releases and off-system sales, and terminating the Company’s balancing service performance-based incentive. Equitable Gas has filed a petition for reconsideration and clarification with the PA PUC and is awaiting a final Order.

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The gas cost rates effective for Equitable Gas residential and commercial customers beginning October 1, 2005 include historically high natural gas commodity prices, resulting in residential rates as much as 40% higher than those in place in 2004. These increases will present a significant challenge to the Company’s low-income customers, especially during the coming winter months. The Company is working with federal and state government officials, industry associations and local foundations to identify sources of funds to assist low income customers in paying their heating bills. If significant funds are not identified and made available, natural gas commodity prices remain high and/or the Pittsburgh region experiences an unusually cold winter, Equitable Gas Company’s bad debt expense could increase over current levels. The Company will closely monitor its collections rates and adjust its reserve for uncollectible accounts as necessary.

Equitable Gas submits quarterly and annual purchased gas cost filings to the PA PUC, the Kentucky Public Service Commission and the West Virginia Public Service Commission. These filings are generally reviewed for adherence to least-cost purchasing practices. The PA PUC’s Bureau of Audits also reviews the accuracy of the Company’s accounting of purchased gas costs and the Company’s reconciliation of gas costs charged to customers. During July 2005, the PA PUC Staff completed an audit consisting of the 2002-2003 period. This audit contained no significant findings. The PA PUC Bureau of Audits is currently conducting an on-site purchased gas cost audit for the 2004 period. The audit of the 2004 period is expected to be concluded by the end of 2005, and an initial audit report is expected to be available during the first quarter of 2006.

Equitable Gas and the United Steelworkers of America, Local Union 12050, which represents 182 employees of the Utilities segment’s Equitable Gas operation, agreed to a three-year collective bargaining agreement, effective September 24, 2005. The new agreement will supersede the collective bargaining agreement that expired on April 15, 2003.

EQUITABLE SUPPLY

OVERVIEW

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

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for proceeds of approximately $147 million. The proceeds were subject to $5.7 million of purchase price adjustments. The sale resulted in a decrease of 59 Bcf of proved developed reserves and 7 Bcf of proved undeveloped reserves. The sold properties produced approximately 10,000 Mcf per day. The gathering systems consisted of approximately 500 miles of gathering pipeline. In accordance with SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” this sale of only a portion of the gas properties may be treated as a normal retirement with no gain or loss recognized if doing so does not significantly affect the unit of production amortization rate. Given the size of the transaction, no gain or loss was recognized on the sale. The unit of production depletion rate (or DD&A rate) decreased by $0.04 per Mcfe prospectively as a result of this transaction.

In January 2005, the Company purchased the limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million. The purchase added approximately 30 Bcfe of reserves.

21

RESULTS OF OPERATIONS

EQUITABLE SUPPLY

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005		2004		%		2005					2004		%
OPERATIONAL DATA
Capital expenditures (thousands) (a)	$	53,535	$	40,003	33.8		$		201,348			$	90,385	122.8
Production:
Total sales volumes (MMcfe)	18,670		17,002		9.8		55,492					50,842		9.1
Average (well-head) sales price ($/Mcfe)	$	5.43	$	4.43	22.6		$			4.98		$	4.40	13.2
Company usage, line loss (MMcfe)	1,334		1,378		(3.2	)	3,681					3,613		1.9
Natural gas inventory usage, net (MMcfe)	—		80		(100.0	)	(51				)	9		(666.7	)
Natural gas and oil production (MMcfe) (b)	20,004		18,460		8.4		59,122					54,464		8.6
Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.29	$	0.28	3.6		$			0.31		$	0.27	14.8
Production taxes ($/Mcfe)	$	0.48	$	0.32	50.0		$			0.44		$	0.32	37.5
Production depletion ($/Mcfe)	$	0.58	$	0.53	9.4		$			0.60		$	0.54	11.1
Gathering:
Gathered volumes (MMcfe)	29,227		30,737		(4.9	)	91,339					94,610		(3.5	)
Average gathering fee ($/Mcfe) (c)	$	0.81	$	0.58	39.7		$			0.77		$	0.59	30.5
Gathering and compression expense ($/Mcfe)	$	0.29	$	0.26	11.5		$			0.31		$	0.24	29.2
Gathering and compression depreciation ($/Mcfe)	$	0.13	$	0.11	18.2		$			0.11		$	0.11	—
(in thousands)
Production operating income	$	71,642	$	54,939	30.4		$		187,079			$	157,870	18.5
Gathering operating income	8,259		3,965		108.3		21,345					15,290		39.6
Total operating income	$	79,901	$	58,904	35.6		$		208,424			$	173,160	20.4
Production depletion	$	11,526	$	9,798	17.6		$	35,425				$	29,239	21.2
Gathering and compression depreciation	3,760		3,450		9.0		10,485					10,057		4.3
Other DD&A	779		643		21.2		2,731					2,427		12.5
Total DD&A	$	16,065	$	13,891	15.7		$	48,641				$	41,723	16.6

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	Three Months Ended September 30,					Nine Months Ended September 30,
	2005		2004		%	2005		2004		%
FINANCIAL DATA (Thousands)
Production revenues	$	103,450	$	80,706	28.2	$	282,266	$	234,721	20.3
Gathering revenues	23,802		17,944		32.6	70,470		55,682		26.6
Total operating revenues	$	127,252	$	98,650	29.0	$	352,736	$	290,403	21.5
Operating expenses:
LOE, excluding production taxes	$	5,784	$	5,124	12.9	$	18,500	$	14,955	23.7
Production taxes (d)	9,543		5,987		59.4	26,023		17,632		47.6
Gathering and compression (operation and maintenance)	8,425		8,027		5.0	28,622		22,596		26.7
SG&A	7,534		6,717		12.2	22,007		20,337		8.2
DD&A	16,065		13,891		15.7	48,641		41,723		16.6
Impairment charges	—		—		—	519		—		100.0
Total operating expenses	$	47,351	$	39,746	19.1	$	144,312	$	117,243	23.1
Operating income	$	79,901	$	58,904	35.6	$	208,424	$	173,160	20.4
Other income, net	$	—	$	—		$	—	$	576
Earnings from nonconsolidated investments	$	131	$	185		$	261	$	465

(a)Capital expenditures for the nine months ended September 30, 2005 include $57.5 million for the acquisition of the limited partnership interest in ESP which was separately approved by the Board of Directors of the Company in addition to the total amount originally authorized for the 2005 capital budget program. In October 2005, the Board of Directors authorized a $28 million dollar increase in Equitable Supply’s 2005 capital budget. This will allow the Company to enter into advance commitments to facilitate prompt commencement of drilling activities in 2006.

(b)Natural gas and oil production represents the Company’s interest in gas and oil production measured at the well-head.

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

(d)Production taxes include severance and production-related ad valorem and other property taxes.

Three Months Ended September 30, 2005
vs. Three Months Ended September 30, 2004

Equitable Supply’s operating income totaled $79.9 million for the three months ended September 30, 2005 compared to $58.9 million for the three months ended September 30, 2004. The $21.0 million increase in operating income is primarily due to an increase in average well-head sales price, an increase in sales volumes as a result of the purchase of ESP and an increase in gathering revenues, partially offset by increased operating expenses.

Total operating revenues were $127.3 million for the three months ended September 30,  2005 compared to $98.7 million for the three months ended September 30, 2004. The $28.6 million increase in total operating revenues was primarily due to a 23% increase in the average well-head sales price, a 10% increase in production total sales volumes and a 33% increase in gathering revenues. The $1.00 per Mcfe increase in the average well-head sales price was attributable to increased market prices on unhedged volumes. The 10% increase in production sales volumes was primarily the result of the purchase of ESP and increased base sales volumes, partially offset by the sale of certain non-core gas properties in May 2005. Base sales volumes are defined as the portion of sales volumes that exclude the effect of the purchase of ESP and the sale of certain non-core properties. The 33% increase in revenues from gathering fees was due to a 40% increase in the average gathering fee, partially offset by a 5% decline in gathered volumes. The increase in the average gathering fee was related to the Company’s current strategy to migrate to a business model in which Equitable will charge shippers’ rates. The decrease in gathered volumes in 2005 is primarily due to the sale of certain non-core gathering assets in May 2005 and third-party customer volume shut-ins caused by extended unexpected maintenance projects on interstate pipelines. These factors were partially offset by increased gathered volumes for production in 2005. The increases in production and gathering revenues were partially offset by the prior year recognition of a gain of $2.7 million in the three months ended September 30, 2004 that resulted from the renegotiation of a processing agreement.

23

Operating expenses totaled $47.4 million for the three months ended September 30, 2005 compared to $39.7 million for the three months ended September 30, 2004. A significant portion of the $7.7 million increase was due to additional costs during the three months ended September 30, 2005 of $4.0 million resulting from the purchase of ESP in January 2005. The $4.0 million of costs were primarily related to production taxes ($1.3 million), DD&A ($1.1 million), LOE ($0.8 million), gathering and compression expenses ($0.6 million) and SG&A ($0.2 million). Excluding the ESP costs, the $3.7 million increase in operating expenses was primarily due to increases of $2.3 million in production taxes, $1.1 million in DD&A, and $0.6 million in SG&A. The increase of $2.3 million in production taxes was due to increased property taxes and severance taxes. The increase in property taxes was a direct result of increased prices and sales in prior years, as property taxes in several of the taxing jurisdictions where the Company’s wells are located are calculated based on historical gas commodity prices and sales volumes. The increase in severance taxes (a production tax directly imposed on the value of gas extracted) was primarily due to higher current gas commodity prices and sales volumes in the various taxing jurisdictions that impose such taxes. Excluding the effects of the purchase of ESP, the $1.1 million increase in DD&A was mainly due to a $0.05 per Mcf increase in the unit depletion rate ($0.9 million). The $0.05 per Mcf increase in the unit depletion rate was primarily due to the net development capital additions in 2004 on a relatively consistent proved reserve base. The $0.6 million increase in SG&A was mainly the result of increased legal and professional fees, resulting from the defense of claims related to pipeline incidents, and bad debt reserves.

Capital expenditures totaled $53.5 million for the three months ended September 30, 2005 compared to $40.0 million for the three months ended September 30, 2004. The $13.5 million increase was due to the size of the 2005 drilling and development plan.

Nine Months Ended September 30, 2005

vs. Nine Months Ended September 30, 2004

Equitable Supply’s operating income totaled $208.4 million for the nine months ended September 30, 2005 compared to $173.2 million for the nine months ended September 30, 2004. The $35.2 million increase in operating income is primarily due to an increase in average well-head sales price, an increase in sales volumes as a result of the purchase of ESP and an increase in gathering revenues, partially offset by increased operating expenses.

Total operating revenues were $352.7 million for the nine months ended September 30, 2005 compared to $290.4 million for the nine months ended September 30, 2004. The $62.3 million increase in total operating revenues was primarily due to a 13% increase in the average well-head sales price, a 9% increase in production total sales volumes, and a 27% increase in gathering revenues. The $0.58 per Mcfe increase in the average well-head sales price was attributable to increased market prices on unhedged volumes. The 9% increase in production total sales volumes was primarily the result of the purchase of ESP, offset by the sale of certain non-core gas properties and reduced base sales volumes. The 27% increase in revenues from gathering fees was due to a 31% increase in the average gathering fee, partially offset by a 3% decline in gathered volumes. The increase in average gathering fee was related to the aforementioned business strategy implemented in 2005. The decrease in gathered volumes in 2005 is primarily due to the sale of certain non-core gathering assets in the second quarter of 2005 and third-party customer volume shut-ins caused by extended unexpected maintenance projects on interstate pipelines. The increases in production and gathering revenues were partially offset by the $2.7 million gain from the renegotiation of a processing agreement in 2004.

Operating expenses totaled $144.3 million for the nine months ended September 30, 2005 compared to $117.2 million for the nine months ended September 30, 2004. A significant portion of this  $27.1 million increase was due to additional costs of $11.5 million resulting from the purchase of ESP in January 2005. The $11.5 million of costs were primarily related to DD&A ($3.6 million), production taxes ($3.3 million), LOE ($3.1 million), gathering and compression expenses ($1.3 million) and SG&A expenses ($0.2 million). Excluding the ESP costs, the $15.6 million increase in operating expenses was primarily due to increases of $5.1 million in production taxes, $4.7 million in gathering and compression expenses, $3.3 million in DD&A, $1.5 million in SG&A, $0.5 million in impairment charges and $0.5 million in LOE. The increase of $5.1 million in production taxes was due to increased property taxes and severance taxes. The increase in property taxes was a direct result of increased historical gas commodity prices and sales volumes as previously discussed. The increase in severance taxes was primarily due to higher current gas commodity prices and sales volumes as previously discussed. The increase of $4.7 million in gathering and compression expenses was primarily attributable to increased field labor and related employment costs, compressor station operation and repair costs and compressor electricity charges resulting from newly installed electric compressors, partially offset by the sale of certain non-core gathering assets in May 2005. The gathering and compression increases are consistent with the Company’s strategic decision to focus on improving gathering and compression and metering effectiveness. Excluding the purchase of ESP, the $3.3 million increase in DD&A was mainly due to a $0.06 per Mcf increase in the unit depletion rate ($3.4 million). The increase of $1.5 million in SG&A was the result of increased legal expenses, resulting from the defense of claims relating to pipeline incidents, and bad debt reserves. The impairment charges in the nine months ended September 30, 2005 were related to the Company’s relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh.

24

Capital expenditures totaled $201.3 million for the nine months ended September 30, 2005 compared to $90.4 million for the nine months ended September 30, 2004. The 2005 expenditures included $57.5 million for the acquisition of the limited partnership interest in ESP. Excluding the ESP acquisition, the $53.4 million increase was due to the size of the 2005 drilling and development plan. Through September 30, 2005, Equitable Supply has drilled 310 gross wells compared to 237 gross wells through September 30, 2004.

The decrease in other income of $0.6 million was the result of a $6.1 million settlement of a disputed property insurance coverage claim, offset by a $5.5 million expense related to the Company’s amendment of its prepaid natural gas contract in 2004.

OUTLOOK

The Company’s strategy recognizes that, in the current price environment, profit maximization is better achieved by primarily focusing on developing new opportunities, and secondarily focusing on cost control. The Company believes that the margin leverage from realizable gas prices outweighs the increase in unit cost structure necessary to implement this strategy. By providing a stable base infrastructure for the current natural gas wells, the Company can benefit from the higher gas prices by obtaining accelerated volumes from the current wells and by increasing the number of wells it intends to drill in the remainder of 2005 and beyond. The Company expects to drill 440 wells in 2005 compared to 314 in 2004. Subsequent to the purchase of ESP and the sale of non-core assets and at a NYMEX price of $6.00, the Company believes that it has available on acreage it controls, at least 6,300 net drilling locations on unproved properties. This is in addition to 1,424 net proved undeveloped drilling locations. The 2005 drilling program is expected to impact year-over-year volume comparisons in the fourth quarter of 2005. The execution of this model, as anticipated, has resulted in higher operating expense. In addition to these actions, the Company continues to focus on ensuring that costs incurred in its gathering activities, both operating and capital, plus a reasonable rate of return on its gathering assets, are recovered in rates for transporting gas on its gathering systems. In certain instances, increasing the rates that Equitable Gathering charges to parties who transport gas on its gathering systems requires regulatory action. As a consequence, the Company expects the process of increasing gathering rates to extend beyond 2005.

NORESCO

OVERVIEW

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

25

RESULTS OF OPERATIONS

NORESCO

	Three Months Ended September 30,								Nine Months Ended September 30,
	2005			2004			%		2005			2004			%
OPERATIONAL DATA
Revenue backlog, end of period (thousands)	$	39,060		$	92,946				$	39,060		$	92,946
Gross profit margin	26.4		%	24.0		%			25.4		%	26.7		%
SG&A as a % of revenue	16.4		%	14.0		%			16.0		%	15.9		%
Capital expenditures (thousands)	$	143		$	193				$	434		$	385
FINANCIAL DATA (Thousands)
Energy service contract revenues	$	35,156		$	37,366		(5.9	)	$	112,484		$	106,992		5.1
Energy service contract costs	25,858			28,404			(9.0	)	83,866			78,471			6.9
Net operating revenue (gross profit margin)	9,298			8,962			3.7		28,618			28,521			0.3
Operating expenses:
SG&A	5,772			5,242			10.1		17,990			17,047			5.5
DD&A	241			245			(1.6	)	747			746			0.1
Total operating expenses	6,013			5,487			9.6		18,737			17,793			5.3
Operating income	$	3,285		$	3,475		(5.5	)	$	9,881		$	10,728		(7.9	)
Earnings (losses) from nonconsolidated investments:
International investments	$	1,505		$	(3	)			$	9,352		$	(39,137	)
Other	$	4		$	13				$	31		$	32
Minority interest	$	94		$	(105	)			$	(652	)	$	(834	)

Three Months Ended September 30, 2005
vs. Three Months Ended September 30, 2004

NORESCO’s operating income totaled $3.3 million for the three months ended September 30, 2005 compared to $3.5 million for the three months ended September 30, 2004. The decrease was primarily due to an increase in incentive expense and bad debt expense partially offset by an increase in the profitability of the projects constructed during the quarter.

Total revenues were $35.2 million for the three months ended September 30, 2005 compared to $37.4 million for the three months ended September 30, 2004. The decrease was primarily due to a decrease in construction activity of federal projects. Gross profit margin was $9.3 million for the three months ended September 30, 2005 compared to $9.0 million for the three months ended September 30, 2004. Gross profit margin as a percentage of revenue was 26.4% for the three months ended September 30, 2005 compared to 24.0% for the three months ended September 30, 2004, reflecting a change in the mix of projects constructed during those periods, offset by the early termination of an operations contract in 2004 for $0.6 million.

Total operating expenses were $6.0 million for the three months ended September 30, 2005 compared to $5.5 million for the three months ended September 30, 2004. The increase was primarily due to an increase in incentive expense and a decrease in bad debt reserves in the third quarter of 2004 as result of collections on past due receivables.

Due to the award of a new contract to sell electricity that has provided for improved forecasted cash flows for the power plant in Panama, NORESCO recorded equity earnings on its international investments in the amount of $1.5 million during the third quarter of 2005. NORESCO continues to evaluate its investments and future obligations associated with exiting the international market.

26

Revenue backlog was $39.1 million at September 30, 2005 compared to $92.9 million at September 30, 2004. The decrease in backlog was primarily due to the failure to enter into new federal government contracts.

Nine Months Ended September 30, 2005
vs. Nine Months Ended September 30, 2004

NORESCO’s operating income for the nine months ended September 30, 2005 was $9.9 million compared to $10.7 million for the nine months ended September 30, 2004. The decrease was primarily due to increases in incentive expense, bad debt expense and project development costs.

Total revenues were $112.5 million for the nine months ended September 30, 2005 compared to $107.0 million for the nine months ended September 30, 2004, primarily due to increased construction activity on non-federal projects. Gross profit margin was $28.6 million for the nine months ended September 30, 2005 compared to $28.5 million for the nine months ended September 30, 2004. Gross profit margin as a percentage of revenue was 25.4% for the nine months ended September 30, 2005 compared to 26.7% for the nine months ended September 30, 2004, reflecting a change in the mix of projects constructed during those nine-month periods.

Total operating expenses were $18.7 million for the nine months ended September 30, 2005 compared to $17.8 million for the nine months ended September 30, 2004. The increase was primarily due to an increase in bad debt expense as a result of improved collection efforts in 2004, and an increase in project development costs.

During the second quarter of 2004, the Company evaluated its international investments for impairments and accelerated its plans to exit its international operations. The Company recorded impairment charges totaling $40.2 million during the nine months ended September 30, 2004. NORESCO continues to evaluate these obligations for changes in conditions. NORESCO reduced these obligations by $7.2 million during the nine months ended September 30, 2005.

OUTLOOK

NORESCO’s backlog at the end of the third quarter of 2005 declined to $39 million due to delays in federal government contracting since the enabling legislation was re-established in September 2004. NORESCO signed contracts with total sales values of $4 million in the third quarter of 2005 and $40 million during the first nine months of 2005.

The Company retained Lincoln Partners LLC to assist it in considering strategic alternatives for its NORESCO segment, including but not limited to a sale, merger, or other business combination.

CAPITAL RESOURCES AND LIQUIDITY

Operating Activities

Cash flows used in operating activities during the first nine months of 2005 totaled $451.7 million, compared to $133.4 million provided by operating activities in the prior year period, a net increase of $585.1 million in cash flows used in operating activities.

The single most significant event from an operating activity perspective during the nine months and the quarter ended September 30, 2005 was the increase in cash remittances to financial institutions for margin deposit requirements on the Company’s natural gas hedge agreements. The recent historic increase in natural gas prices, in part caused by hurricanes in the Gulf Coast region, has required the Company to post a much higher amount of margin than historically posted. The Company recorded such deposits in the amount of $549.9 million as accounts receivable in its Condensed Consolidated Balance Sheet as of September 30, 2005 compared to $36.9 million as of December 31, 2004. As further detailed under the caption Financing Activities below, the Company has taken steps to ensure it has adequate liquidity for working capital and margin requirement needs.

The Company’s tax payments increased in the first nine months of 2005 by $169.6 million over the comparable 2004 period primarily as a result of the sale of the Kerr-McGee shares for a significant gain. See Note D to the Condensed Consolidated Financial Statements for additional information on the sales of Kerr-McGee shares.

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Investing Activities

Cash flows provided by investing activities in the first nine months of 2005 were $285.1 million compared to $90.9 million used in investing activities in the same period of the prior year. The change from the prior year was attributable to proceeds of $394.9 million received from the sales and tender of 6.3 million shares of the Company’s investment in Kerr-McGee during the second and third quarters of 2005. Additionally, the Company received proceeds of $142.0 million from the sale of non-core gas properties and gathering assets during the nine months ended September 30, 2005. The Company expended $57.5 million in capital expenditures for the acquisition of the limited partnership interest in ESP and $194.1 million in other capital expenditures in 2005.

In October 2005, the Board of Directors authorized a $28 million dollar increase in Equitable Supply’s 2005 capital budget. This will allow the Company to enter into advance commitments to facilitate prompt commencement of drilling activities in 2006.

Financing Activities

As mentioned previously, the recent significant increase in natural gas prices, has required the Company to post a much higher amount of margin than historically posted. This resulted in the Company utilizing $100.6 million more of its commercial paper program during the first nine months of 2005 than in the same period of the prior year. The amount of commercial paper outstanding at September 30, 2005 was $437.5 million.

On August 11, 2005, the Company entered into a $650 million, 5-year revolving credit agreement, which may be used for working capital, capital expenditures, share repurchases and other lawful purposes including support of the Company’s commercial paper program. This agreement replaces the Company’s previous $500 million, three-year revolving credit agreement. Subject to certain terms and conditions the Company may on a one-time basis request that the lenders’ commitments be increased to an aggregate amount of up to $1 billion. The new facility has a maturity date of August 10, 2010 upon satisfaction of certain requirements relating to approval of the facility by the PA PUC which was received on October 27, 2005. Additionally, the Company may request two one-year extensions of the maturity date. The facility’s size may be increased on a one-time basis to an aggregate amount of up to $1 billion, and the facility’s term can be extended by up to two years. In October 2005, the Board of Directors of the Company authorized the Company to increase its commercial paper program from $650 million to $1.0 billion.

In addition, as part of the Company’s on-going evaluation of its financial structure, on September 30, 2005, the Company issued $150 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015. The notes were approved by the PA PUC on October 27, 2005. While the debt issuance was intended primarily for the purpose of financing long-term capital expenditures, the proceeds of the notes were initially used to reduce the Company’s outstanding commercial paper. The effective annual interest rate on the $150 million of notes is 5.06%.

On July 13, 2005, the Board of Directors of Equitable Resources increased the Company’s share repurchase authorization by 6.4 million shares to 50.0 million shares. During the nine months ended September 30, 2005, the Company repurchased 2.6 million shares of Equitable Resources, Inc. common stock as part of its share repurchase program.

The Company believes that as of September 30, 2005 it has adequate borrowing capacity to meet its financing requirements and that the cash generated by operations, together with its borrowing capacity, will be adequate to meet the Company’s cash obligations.

Security Ratings

The table below reflects the current credit ratings for the outstanding debt instruments of the Company. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.

Rating Service	Unsecured Medium-Term Notes	Commercial Paper
Moody’s Investors Service	A-2	P-1
Standard & Poor’s Ratings Services	A -	A-2

The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will

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remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. If the rating agencies downgrade the Company’s ratings, particularly below investment grade, it may significantly limit the Company’s access to the commercial paper market and borrowing costs would increase. In addition, the Company would likely be required to pay a higher interest rate in future financings, incur increased margin deposit requirements, and the potential pool of investors and funding sources would decrease.

The Company’s debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most important default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’s current credit facility’s financial covenants require a total debt-to-total capitalization ratio of no greater than 65%. As of September 30, 2005, the Company is in compliance with all existing debt provisions and covenants.

Commodity Risk Management

The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and Over the Counter (OTC) natural gas swap agreements and options (collectively, derivative commodity instruments) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The preponderance of derivative commodity instruments currently utilized by the Company are fixed price swaps or NYMEX-traded forwards.

During the third quarter, the Company increased its hedge position for 2005 through 2012. The new hedges are collars, which protect revenues from decreases in natural gas prices below a floor but also limits the upside exposure to increases in prices to a cap. The approximate volumes and prices of the Company’s hedges for the last quarter of 2005 through 2007 are:

Swaps	2005**			2006		2007
Total Volume (Bcf)	15			59		56
Average Price per Mcf (NYMEX)*	$	4.89		$	4.77	$	4.74
Collars	2005		*	2006		2007
Total Volume (Bcf)	2			7		7
Average Floor Price per Mcf (NYMEX)*	$	7.35		$	7.35	$	7.35
Average Cap Price per Mcf (NYMEX)*	$	10.84		$	10.84	$	10.84

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

** October through December

With respect to hedging the Company’s exposure to changes in natural gas commodity prices, the Company’s current hedged position provides price protection for a substantial portion of expected production for the years 2005 through 2008, and a significant portion of expected equity production for the years 2009 through 2012. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is less than $0.01 per diluted share for the remainder of 2005 and approximately $0.01 to $0.02 per diluted share per year for 2006 through 2008. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices. See Note C to the Company’s Condensed Consolidated Financial Statements for further discussion.

Commitments and Contingencies

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

The Company maintains a $2.9 million liability for a guarantee in support of a 50% owned non-recourse financed energy project in Panama. The guarantee covers a project loan debt service requirement.

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Incentive Compensation

The Company has shifted its compensation focus from stock options to performance-based stock units and time-restricted stock awards. Management and the Board of Directors believe that such an incentive compensation approach more closely aligns management’s incentives with shareholder rewards than is the case with traditional stock options. The Company has long utilized time-restricted stock in its compensation plans, but only began issuing performance-restricted units in 2002 and has now fully transitioned to a long-term incentive approach that is limited to performance-restricted stock or units and time-restricted stock. No stock options have been awarded since 2003.

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

	Nine Months Ended September 30,
	2005		2004
	(Millions)
Short-term incentive compensation expense	$	9.2	$	14.3
Long-term incentive compensation expense	33.5		16.6
Total incentive compensation expense	$	42.7	$	30.9

The long-term incentive compensation expenses are primarily associated with Executive Performance Incentive Programs (“the Programs”) that were instituted starting in 2002. The long-term incentive expenses during the first nine months of 2005 were higher than the long-term incentive expenses during the same period of 2004 primarily due to a higher estimated share price for the Programs being expensed, as a result of the Company’s share price appreciation, and a greater number of shares granted under the current Programs.

The Company continually monitors its stock price and relative return in order to assess the impact on the ultimate payouts under the Programs. These long-term incentive compensation expenses are included in selling, general and administrative expenses in the Statements of Consolidated Income. Additionally, the majority of the long-term incentive compensation expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note F to the Condensed Consolidated Financial Statements for further discussion of the Programs.

As a result of the merger of Westport/Kerr-McGee during the first nine months of 2004, the Company recorded a significant increase in net income. Accordingly, the short-term incentive compensation expense was significantly increased during that period.

Dividend

On October 19, 2005, the Board of Directors declared a regular quarterly cash dividend of 21 cents per share, payable December 1, 2005, to shareholders of record on November 10, 2005.

Critical Accounting Policies

The Company’s critical accounting policies are described in the notes to the Company’s consolidated financial statements for the year ended December 31, 2004 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, 2005. The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the Condensed 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.

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

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

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

With respect to the derivative commodity instruments held by the Company for purposes other than trading as of September 30, 2005, the Company continued to execute its hedging strategy by utilizing forward contracts, swap agreements and collar agreements covering approximately 346.4 Bcf of natural gas. These derivatives have hedged a portion of expected equity production through 2012. See the “Commodity Risk Management” and “Capital Resources and Liquidity” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q for further discussion. A decrease of 10% in the market price of natural gas from the September 30, 2005 levels would increase the fair value of natural gas instruments by approximately $294.4 million. An increase of 10% in the market price of natural gas would decrease the fair value by approximately $324.4 million.

With respect to the derivative commodity instruments held by the Company for trading purposes as of September 30, 2005, an increase or decrease of 10% in the market price of natural gas from the September 30, 2005 levels would not have a significant impact on the fair value.

The Company determined the change in the fair value of the derivative commodity instruments using a method similar to its normal change in fair value as described in Note 1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. The Company assumed a 10% change in the price of natural gas from its levels at September 30, 2005. The price change was then applied to the derivative commodity instruments recorded on the Company’s Condensed Consolidated Balance Sheet, resulting in the change in fair value.

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

See Note C regarding Derivative Instruments in the notes to the Condensed Consolidated Financial Statements and the “Commodity Risk Management” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q for further information.

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Item 4.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

There have been no material developments in legal proceedings involving the Company or its subsidiaries since those reported in Part II Item 1. Legal Proceedings in the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005.

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

The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that have occurred in the three months ended September 30, 2005.

Period	Total number of shares (or units) purchased (a)	Average price paid per share (or unit)		Total number of shares (or units) Purchased as part of publicly announced plans or programs	Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs (b)
July 2005 (July 1 – July 31)	206,956	$	34.61	203,400	10,049,800
August 2005 (August 1 – August 31)	298,049	$	35.37	294,400	9,755,400
September 2005 (September 1 – September 30)	373,295	$	38.29	370,000	9,385,400
Total	878,300			867,800

(a)Includes 10,500 shares for Company-directed purchases made by the Company’s 401(k) plans. All other purchases were open market purchases made pursuant to the Company’s publicly disclosed repurchase program. The Company routinely enters into “10b5-1 plans,” or trading plans, to facilitate continuity of its share repurchase program through earnings blackout periods.

(b)Equitable’s Board of Directors previously authorized a share repurchase program with a maximum of 50.0 million shares and no expiration date. The program was initially publicly announced on October 7, 1998 with subsequent amendments announced on November 12, 1999, July 20, 2000 and April 15, 2004 and July 13, 2005.

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Item 6. Exhibits

3.01	Equitable Resources, Inc.’s Restated Articles of Incorporation (amended through July 18, 2005)
4.01	Equitable Resources, Inc.’s Revolving Credit Agreement dated as of August 11, 2005
31.1	Certification by Murry S. Gerber pursuant to Rule 13a-14(a) or Rule 15d-14(a)
31.2	Certification by David L. Porges pursuant to Rule 13a-14(a) or Rule 15d-14(a)
32	Certification by Murry S. Gerber, David L. Porges, and Philip P. Conti pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

Date:  October 27, 2005

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INDEX TO EXHIBITS

Exhibit No.	Document Description	Incorporated by Reference
3.01	Equitable Resources, Inc.’s Restated Articles of Incorporation (amended through July 18, 2005)	Filed as Exhibit 3.01 to Form 8-K filed on July 18, 2005
4.01	Equitable Resources, Inc.’s Revolving Credit Agreement dated as of August 11, 2005	Filed Herewith
31.1	Certification by Murry S. Gerber pursuant to Rule 13a-14(a) or Rule 15d-14(a)	Filed Herewith
31.2	Certification by David L. Porges pursuant to Rule 13a-14(a) or Rule 15d-14(a)	Filed Herewith
32	Certification by Murry S. Gerber, David L. Porges, and Philip P. Conti pursuant to 18 U.S.C Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed Herewith

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