Edgar Filing: EQUITABLE RESOURCES INC /PA/

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006

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 or other jurisdiction 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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b–2 of the Exchange Act.

Large Accelerated Filer x Accelerated Filer o Non-Accelerated Filer 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 x

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

Class		Outstanding at September 30, 2006

Common stock, no par value		120,722,379 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, 2006 and 2005

		Statements of Condensed Consolidated Cash Flows for the Nine Months Ended September 30, 2006 and 2005

		Condensed Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005

		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 1A.		Risk Factors

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

Item 6.		Exhibits

Signature

Index to Exhibits

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Consolidated Income (Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006			2005
	(Thousands, except per share amounts)
Operating revenues	$	232,801	$	229,372	$	914,127		$	860,842
Cost of sales	72,155		65,956		367,085			330,604
Net operating revenues	160,646		163,416		547,042			530,238

Operating expenses:
Operation and maintenance	25,282		22,891		74,252			71,599
Production	16,176		15,327		47,965			44,523
Selling, general and administrative	32,904		47,245		90,659			101,364
Office consolidation impairment charges	—		—		(2,908		)	7,835
Depreciation, depletion and amortization	25,149		23,264		74,163			69,573
Total operating expenses	99,511		108,727		284,131			294,894

Operating income	61,135		54,689		262,911			235,344

Gain on sale and tender of available-for-sale securities, net	—		19,438		—			80,257

Equity in earnings of nonconsolidated investments	70		216		120			413

Other income, net	—		—		—			1,195

Interest expense	12,290		10,932		35,242			33,107

Income from continuing operations before income taxes	48,915		63,411		227,789			284,102
Income taxes	17,120		17,600		79,726			105,547
Income from continuing operations	31,795		45,811		148,063			178,555
Income from discontinued operations, net of tax of $2,971 and $5,456 for the three and nine months ended September 30, 2005, respectively	—		680		—			8,661
Net income	$	31,795	$	46,491	$	148,063		$	187,216

Earnings per share of common stock:
Basic:
Weighted average common shares outstanding	120,172		121,181		119,929			121,359
Income from continuing operations	$	0.26	$	0.37	$	1.23		$	1.47
Income from discontinued operations	—		0.01		—			0.07
Net income	$	0.26	$	0.38	$	1.23		$	1.54
Diluted:
Weighted average common shares outstanding	122,103		123,576		121,961			124,016
Income from continuing operations	$	0.26	$	0.37	$	1.21		$	1.44
Income from discontinued operations	—		0.01		—			0.07
Net income	$	0.26	$	0.38	$	1.21		$	1.51
Dividends declared per common share	$	0.22	$	0.21	$	0.65		$	0.63

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Statements of Condensed Consolidated Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2006			2005
	(Thousands)
Cash flows from operating activities:
Net income	$	148,063		$	187,216
Adjustments to reconcile net income to cash provided by (used in) operating activities:
Income from discontinued operations, net of tax	—			(8,661		)
Provision for losses on accounts receivable	1,504			5,165
Depreciation, depletion, and amortization	74,163			69,573
Gain on sale and tender of available-for-sale securities, net	—			(80,257		)
Office consolidation impairment charges	(2,908		)	7,835
Deferred income taxes	15,435			(77,912		)
Excess tax benefits from share-based payment arrangements	(6,090		)	—
Increase in inventory	(33,845		)	(52,844		)
Decrease in accounts receivable and unbilled revenues	176,283			78,255
Decrease (increase) in margin deposits	317,574			(512,982		)
Decrease in accounts payable	(62,439		)	(11,382		)
Changes in other assets and liabilities	(77,284		)	(23,324		)
Total adjustments	402,393			(606,534		)
Net cash provided by (used in) continuing operating activities	550,456			(419,318		)
Net cash used in discontinued operating activities	—			(31,743		)
Net cash provided by (used in) operating activities	550,456			(451,061		)

Cash flows from investing activities:
Capital expenditures	(253,490		)	(193,679		)
Investment in available-for-sale securities	(2,314		)	(3,769		)
Proceeds from sale of Kerr-McGee shares	—			394,901
Proceeds from sale of properties	—			141,991
Purchase of interest in Eastern Seven Partners, L.P.	—			(57,500		)
Net cash (used in) provided by continuing investing activities	(255,804		)	281,944
Net cash (used in) provided by discontinued investing activities	(724		)	2,566
Net cash (used in) provided by investing activities	(256,528		)	284,510

Cash flows from financing activities:
Dividends paid	(78,290		)	(74,615		)
Purchase of treasury stock	—			(84,501		)
Proceeds from exercises under employee compensation plans	17,002			23,808
Excess tax benefits from share-based payment arrangements	6,090			—
Repayments and retirements of long-term debt	(3,000		)	(10,000		)
Proceeds from issuance of long-term debt	—			150,000
(Decrease) increase in short-term loans	(310,696		)	142,003
Net cash (used in) provided by continuing financing activities	(368,894		)	146,695
Net cash provided by discontinued financing activities	—			19,856
Net cash (used in) provided by financing activities	(368,894		)	166,551

Net decrease in cash and cash equivalents	(74,966		)	—
Cash and cash equivalents at beginning of period	74,966			—
Cash and cash equivalents at end of period	$	—		$	—

Cash paid during the period for:
Interest, net of amount capitalized	$	36,686		$	40,984
Income taxes, net of refund	$	38,717		$	183,635

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

EQUITABLE RESOURCES, INC. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets (Unaudited)

	September 30, 2006			December 31, 2005
	(Thousands)
ASSETS

Current assets:
Cash and cash equivalents	$	—		$	74,966
Accounts receivable (less accumulated provision for doubtful accounts:
September 30, 2006, $20,537; December 31, 2005, $23,329)	116,157			249,397
Unbilled revenues	14,411			58,958
Margin deposits with financial institutions	258			317,832
Inventory	323,766			289,921
Derivative instruments, at fair value	153,548			42,899
Prepaid expenses and other	69,962			60,732
Assets held for sale from discontinued operations	—			2,518
Total current assets	678,102			1,097,223
Equity in nonconsolidated investments	35,060			35,555
Property, plant and equipment	3,469,144			3,236,097
Less: accumulated depreciation and depletion	1,216,096			1,152,892
Net property, plant and equipment	2,253,048			2,083,205
Investments, available-for-sale	29,276			25,194
Other assets	94,973			101,108
Total assets	$	3,090,459		$	3,342,285

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	10,000		$	3,000
Short-term loans	54,604			365,300
Accounts payable	180,179			242,618
Derivative instruments, at fair value	656,827			1,264,204
Other current liabilities	165,714			217,374
Total current liabilities	1,067,324			2,092,496

Debentures and medium-term notes	753,434			763,434

Deferred income taxes and investment tax credits	302,726			24,042
Other credits	97,796			107,845

Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares; shares issued: September 30, 2006 and December 31, 2005, 149,008	363,881			358,684
Treasury stock, shares at cost: September 30, 2006, 28,284; December 31, 2005, 29,102 (net of shares and cost held in trust for deferred compensation of 158, $2,705 and 142, $2,429)	(483,733		)	(496,511		)
Retained earnings	1,317,668			1,247,895
Accumulated other comprehensive loss	(328,637		)	(755,600		)
Total common stockholders’ equity	869,179			354,468
Total liabilities and stockholders’ equity	$	3,090,459		$	3,342,285

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

Equitable Resources, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements (Unaudited)

A. Financial Statements

The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with United States generally accepted accounting principles 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 United States generally accepted accounting principles 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, 2006, and the results of its operations and cash flows for the three and nine month periods ended September 30, 2006 and 2005.

Certain Condensed Consolidated Financial Statements and related footnote disclosures have been reclassified to reflect the operating results and cash flows of the discontinued NORESCO segment for the three and nine month periods ended September 30, 2005, as discontinued operations. Additionally, certain previously reported amounts have been reclassified to conform to the current year presentation.

The balance sheet at December 31, 2005 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by United States generally accepted accounting principles for complete financial statements.

Due to the seasonal nature of the Company’s natural gas distribution and energy marketing businesses and the volatility of natural gas prices, the interim statements for the three and nine month periods ended September 30, 2006 are not necessarily indicative of the results that may be expected for the year ending December 31, 2006.

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, 2005, as well as in “Information Regarding Forward Looking Statements” on page 17 of this document.

B. Segment Information

The Company reports its operations in two segments, which reflect its lines of business. The Equitable Utilities segment’s 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. The Equitable Supply segment’s activities comprise the development, production, gathering, marketing and sale of natural gas and a small amount of associated oil and the extraction and sale of natural gas liquids. In December 2005, the Company discontinued and sold the operations of its NORESCO segment, which provided energy efficiency solutions to customers including governmental, military, institutional, commercial and industrial end-users.

Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments and other income, net. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005

Revenues from external customers:
Equitable Utilities	$	125,603		$	113,712		$	599,328		$	550,684
Equitable Supply	120,991			127,252			362,767			352,736
Less: intersegment revenues (a)	(13,793		)	(11,592		)	(47,968		)	(42,578		)
Total	$	232,801		$	229,372		$	914,127		$	860,842
Total operating expenses:
Equitable Utilities	$	35,686		$	43,641		$	105,417		$	116,920
Equitable Supply	57,761			47,351			162,111			144,312
Unallocated expenses	6,064			17,735			16,603			33,662
Total	$	99,511		$	108,727		$	284,131		$	294,894
Operating income:
Equitable Utilities	$	3,969		$	(7,477	)	$	78,858		$	60,582
Equitable Supply	63,230			79,901			200,656			208,424
Unallocated expenses	(6,064		)	(17,735		)	(16,603		)	(33,662		)
Total	$	61,135		$	54,689		$	262,911		$	235,344

Reconciliation of operating income to net income:

Equity in earnings of nonconsolidated investments:
Equitable Supply	$	71		$	131		$	53		$	261
Unallocated	(1		)	85			67			152
Total	$	70		$	216		$	120		$	413

Gain on sale and tender of available-for-sale securities, net	—			19,438			—			80,257
Other income, net (b)	—			—			—			1,195
Interest expense	12,290			10,932			35,242			33,107
Income taxes	17,120			17,600			79,726			105,547
Income from continuing operations	31,795			45,811			148,063			178,555
Income from discontinued operations, net of tax of $2,971 and $5,456 for the three and nine months ended September 30, 2005, respectively	—			680			—			8,661
Net income	$	31,795		$	46,491		$	148,063		$	187,216

	September 30,		December 31,
	2006		2005
	(Thousands)
Segment Assets:
Equitable Utilities	$	1,400,278	$	1,412,215
Equitable Supply	1,651,991		1,844,883
Total operating segments	3,052,269		3,257,098
Headquarters assets, including cash and short-term investments	38,190		82,669
Total operating assets	3,090,459		3,339,767
Assets held for sale from discontinued operations	—		2,518
Total assets	$	3,090,459	$	3,342,285

	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005

Expenditures for segment assets:
Equitable Utilities	$	16,463	$	18,710	$	45,543	$	40,283
Equitable Supply (c)	82,871		53,535		205,398		201,348
Unallocated expenditures	740		783		2,549		9,548
Total	$	100,074	$	73,028	$	253,490	$	251,179

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

(b) Unallocated other income, net for the nine months ended September 30, 2005 relates to pre-tax dividend income of $1.2 million for Kerr-McGee Corporation shares.

(c) Capital expenditures for the nine months ended September 30, 2005 include $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners, L.P.

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 $153.5 million asset and a $624.9 million liability as of September 30, 2006, and a $36.0 million asset and a $1.2 billion liability as of December 31, 2005. 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 $1.2 billion at December 31, 2005 to a net liability of $471.4 million at September 30, 2006, primarily as a result of the decrease 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 434.9 Bcf and 383.5 Bcf as of September 30, 2006 and December 31, 2005, respectively, and primarily related to natural gas swaps. The open positions at September 30, 2006 had maturities extending through December 2013.

The Company deferred net losses of $315.3 million and $741.0 million in accumulated other comprehensive loss, net of tax, as of September 30, 2006 and December 31, 2005, 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 $61.6 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of September 30, 2006 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, 2006 and 2005, ineffectiveness associated with the Company’s derivative instruments designated as cash flow hedges increased earnings by approximately $0.4 million and $0.5 million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.

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

The absolute notional quantities of the futures and swaps held for trading purposes at September 30, 2006 totaled 9.1 Bcf and 34.0 Bcf, respectively.

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, 2006 (in thousands).

Fair value of contracts outstanding as of December 31, 2005	$	(330	)
Contracts realized or otherwise settled	286
Other changes in fair value	(88		)
Fair value of contracts outstanding as of September 30, 2006	$	(132	)

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, 2006.

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)	$	(20	)	$	—	$	—	$	—	$	(20	)
Prices provided by other external sources (2)	(131		)	19		—		—		(112		)
Net derivative (liabilities) assets	$	(151	)	$	19	$	—	$	—	$	(132	)

(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 $0.3 million as margin deposits with financial institutions in its Condensed Consolidated Balance Sheet as of September 30, 2006.

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 had no such margin deposits in its Condensed Consolidated Balance Sheet at September 30, 2006.

The fair value of derivative instruments assumed as part of the purchase of the limited partnership interest in Eastern Seven Partners, L.P. (ESP) in January 2005 was a $15.1 million liability at September 30, 2006. The fair value of derivative instruments associated with forecasted production at non-core gas properties sold in May 2005 was a $15.9 million liability at September 30, 2006. 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). These amounts are included in the Condensed Consolidated Balance Sheet as derivative instruments, at fair value. See Note L for further discussion of the related transactions.

D. Investments

As of September 30, 2006, the investments classified by the Company as available-for-sale consist of approximately $29.3 million of equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures.

Any unrealized gains or losses with respect to investments classified as available-for-sale are recognized within the Consolidated Balance Sheets as a component of equity, accumulated other comprehensive loss. The Company utilizes the specific identification method to determine the cost of all investment securities sold.

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.

In May 2005, the Company terminated 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 at an average price of $75.43 per share to cover its counterparties’ respective hedged positions. The Company received $227.4 million in pre-tax 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 April 2005, the Company sold approximately 1.0 million unhedged Kerr-McGee shares for total proceeds of $77.9 million. The sale of these remaining shares resulted in a pre-tax gain to the Company of $26.7 million.

In the first nine months of 2005, the Company recorded dividend income on its investment in Kerr-McGee of $1.2 million, which is recorded in other income, net on the Statement of Consolidated Income for the nine months ended September 30, 2005.

E. Comprehensive Income (Loss)

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006		2005
	(Thousands)
Net income	$	31,795	$	46,491		$	148,063	$	187,216
Other comprehensive income (loss):
Net change in cash flow hedges:
Natural gas (Note C)	176,718		(398,818		)	425,672		(642,645		)
Interest rate	29		29			87		87
Unrealized gain (loss) on available-for-sale securities:
Kerr-McGee	—		2,334			—		(14,411		)
Other	838		218			1,204		111
Total comprehensive income (loss)	$	209,380	$	(349,746	)	$	575,026	$	(469,642	)

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

	September 30,			December 31,
	2006			2005
	(Thousands)
Net unrealized loss from hedging transactions	$	(316,045	)	$	(741,804	)
Unrealized gain on available-for-sale securities	2,774			1,570
Minimum pension liability adjustment	(15,366		)	(15,366		)
Accumulated other comprehensive loss	$	(328,637	)	$	(755,600	)

F. Share-Based Compensation

The Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R) as of January 1, 2006. The Company previously accounted for share-based compensation transactions using the intrinsic value method of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Under SFAS No. 123R, 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 is generally measured based on the grant-date fair value of the award.

The Company adopted SFAS No. 123R using the modified prospective method. Under the modified prospective method, compensation cost is recognized beginning with the effective date and prior period results are not restated. As such, compensation cost related to all share-based awards was recorded as selling, general and administrative expense in the Company’s Statement of Consolidated Income for the nine months ended September 30, 2006.

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. 123R to employee share-based awards for the three and nine months ended September 30, 2005.

	Three Months Ended September 30, 2005			Nine Months Ended September 30, 2005
	(Thousands)
Net income, as reported	$	46,491		$	187,216
Add: Gross share-based employee compensation expense included in reported net income	16,352			33,455
Deduct: Income tax benefit from share-based employee compensation expense included in reported net income	(5,428		)	(11,298		)
Deduct: Total share-based employee compensation expense determined under fair value method for all awards, net of related tax effects	(11,134		)	(23,576		)
Pro forma net income	$	46,281		$	185,797
Earnings per share:
Basic, as reported	$	0.38		$	1.54
Basic, pro forma	$	0.38		$	1.53

Diluted, as reported	$	0.38		$	1.51
Diluted, pro forma	$	0.37		$	1.50

Adoption of SFAS No. 123R had the effect of reducing operating income and income from continuing operations before income taxes by $0.7 million for the nine month period ended September 30, 2006. Prior to the adoption of SFAS No. 123R, the Company presented all tax benefits for deductions resulting from the exercise of share-based awards as cash flows from operating activities in its Statements of Condensed Consolidated Cash Flows. SFAS No. 123R requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a cash flow from financing activities, rather than as a cash flow from operating activities. This requirement reduced cash flows from operating activities and increased cash flows from financing activities by $6.1 million for the nine months ended September 30, 2006. Total net cash flows were not impacted by the adoption of SFAS No. 123R.

Cash received from exercises under all share-based payment arrangements for employees and directors for the nine month periods ended September 30, 2006 and 2005, was $17.0 million and $23.8 million, respectively. The actual tax benefit realized for tax deductions from share-based payment arrangements for the nine month periods ended September 30, 2006 and 2005, was $7.9 million and $17.2 million, respectively.

The Company typically funds restricted share obligations from treasury stock at the date of grant and has a policy of issuing shares from treasury stock to satisfy option exercises.

Executive Performance Incentive Programs

The vesting of the units granted under the 2005 Executive Performance Incentive Program (2005 Program) will occur contingent upon a combination of the level of total shareholder return relative to a fixed group of peer companies and the Company’s average absolute return on total capital during the four year performance period. The Company anticipates, based on current estimates, that a certain level of performance will be met. The 2005 Program expense for the nine months ended September 30, 2006 and 2005 was $15.6 million and $13.2 million, respectively, and is classified as selling, general and administrative expense in the Statements of Consolidated Income. A portion of the 2005 Program expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note B.

Restricted Stock Awards

The Company granted 93,200 and 75,400 restricted stock awards during the nine months ended September 30, 2006 and 2005, respectively, to key executives of the Company. These awards will be fully vested at the end of the three-year period commencing the date of grant. The fair value of each share is equal to the market price of the Company’s common stock on the date of grant. The weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’s stock, was $35.80 and $29.48, for the nine months ended September 30, 2006 and 2005, respectively. The total fair value of restricted stock awards vested during the nine months ended September 30, 2006 and 2005 was $1.5 million and $1.8 million, respectively. Compensation expense recorded by the Company related to restricted stock awards was $2.5 million and $2.0 million for the nine month periods ended September 30, 2006 and 2005, respectively.

As of September 30, 2006, there was $5.7 million of total unrecognized compensation cost related to nonvested restricted stock awards. That cost is expected to be recognized over a weighted average period of approximately 12.5 months.

A summary of restricted stock activity as of September 30, 2006, and changes during the nine months then ended, is presented below:

Restricted Stock	Non- Vested Shares		Weighted Average Fair Value		Weighted Average Remaining Contractual Term	Aggregate Fair Value

Outstanding at January 1, 2006	520,435		$	22.82		$	11,877,895
Granted	93,200		$	35.80		$	3,336,425
Vested	(77,115	)	$	18.91		$	(1,458,367	)
Forfeited	(12,680	)	$	28.86		$	(365,928	)
Outstanding at September 30, 2006	523,840		$	25.56	12.5 months	$	13,390,025

Stock Options

The fair value of the Company’s option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the nine month periods ended September 30, 2006 and 2005. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Company’s stock. Expected volatilities are based on historical volatility of the Company’s stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.

	Nine Months Ended September 30,
	2006	2005
Risk-free interest rate	4.59% to 5.04%	3.74% to 4.34%
Dividend yield	2.34% to 2.38%	2.75% to 2.83%
Volatility factor	.212 to .226	.258 to .262
Expected term	7 years	7 years

The Company granted 56,257 and 68,898 stock options during the nine months ended September 30, 2006 and 2005, respectively, all of which comprised options granted for reload rights associated with previously-awarded options. The weighted average grant date fair value of these reload option grants was $9.07 and $7.65 for the nine month periods ended September 30, 2006 and 2005, respectively. The total intrinsic value of options exercised during the nine month periods ended September 30, 2006 and 2005 was $20.8 million and $46.0 million, respectively.

As of September 30, 2006, there was no unrecognized compensation cost related to outstanding nonvested stock options as all outstanding options were fully vested.

A summary of option activity as of September 30, 2006, and changes during the nine months then ended, is presented below:

Nonqualified Stock Options	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value

Outstanding at January 1, 2006	5,110,421		$	16.32
Granted	56,257		$	35.93
Exercised	(1,054,342	)	$	17.06
Forfeited	(4,716	)	$	17.46
Outstanding at September 30, 2006	4,107,620		$	16.40	5.0 years	$	76,416,624
Exercisable at September 30, 2006	4,107,620		$	16.40	5.0 years	$	76,416,624

Nonemployee Directors’ Stock Incentive Plan

At September 30, 2006, 160,904 options were outstanding under the 1999 Nonemployee Directors’ Stock Incentive Plan at prices ranging from $6.59 to $29.67 per share, and 537,200 options had been exercised under this plan since plan inception. The exercise price for each award is equal to the market price of the Company’s common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant.

The Company has also historically granted to non-employee directors stock units which vested upon award. The value of the stock units will be paid in cash on the earlier of the director’s death or retirement from the Company’s Board of Directors. A total of 72,960 non-employee director stock units were outstanding as of September 30, 2006. A total of 18,000 stock units were granted to non-employee directors during each of the nine month periods ended September 30, 2006 and 2005.

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. The Company currently estimates the annual effective income tax rate from continuing operations as of September 30, 2006 to be 35.0%. The estimated annual effective income tax rate as of September 30, 2005 was 33.8%, excluding the tax benefit disallowances recorded in 2005 under Section 162(m) of the Internal Revenue Code.

H. Pension and Other Postretirement Benefit Plans

The Company’s costs related to its defined benefit pension and other postretirement benefit plans for the three and nine months ended September 30, 2006 and 2005 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended September 30,
	2006			2005			2006			2005
	(Thousands)
Components of net periodic benefit cost
Service cost	$	107		$	225		$	138		$	135
Interest cost	1,097			1,379			725			792
Expected return on plan assets	(1,533		)	(1,971		)	—			—
Amortization of prior service cost	92			192			(34		)	(11		)
Recognized net actuarial loss	267			209			536			552
Settlement loss	283			13,809			—			—
Net periodic benefit cost	$	313		$	13,843		$	1,365		$	1,468

	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2006			2005			2006			2005
	(Thousands)
Components of net periodic benefit cost
Service cost	$	323		$	675		$	414		$	405
Interest cost	3,291			4,513			2,175			2,376
Expected return on plan assets	(4,599		)	(6,062		)	—			—
Amortization of prior service cost	278			575			(102		)	(32		)
Recognized net actuarial loss	801			698			1,608			1,655
Settlement loss	265			15,990			—			—
Net periodic benefit cost	$	359		$	16,389		$	4,095		$	4,404

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). As a result of the settlement, the Company’s ongoing pension obligation decreased by $12.5 million.

I. Recently Issued Accounting Standards

Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact that SFAS No. 157 will have on its consolidated financial statements.

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” an amendment to SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” and SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106.” SFAS No. 158 requires an employer to recognize a benefit plan’s funded status in its statement of financial position, measure a benefit plan’s assets and obligations as of the end of the employer’s fiscal year and recognize the changes in the benefit plan’s funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158’s requirement to recognize the funded status of a benefit plan and the new disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. The Company is currently evaluating the impact that SFAS No. 158 will have on its consolidated financial statements.

Accounting for Uncertain Tax Positions

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Tax Positions – an Interpretation of FASB Statement No. 109.” The Interpretation applies to all open tax positions accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes.” This Interpretation is intended to result in increased relevance and comparability in financial reporting of income taxes and to provide more information about the uncertainty in income tax assets and liabilities. This Interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of this Interpretation on the Company’s financial position and results of operations.

Earnings Per Share

In September 2005, the FASB issued an exposure draft of a proposed amendment to SFAS No. 128, “Earnings Per Share.” The proposed amendment would clarify guidance for calculating earnings per share in regards to mandatorily convertible instruments, the treasury stock method, contracts that may be settled in cash or shares and contingently issuable shares. The FASB has delayed issuance of the final amendment until it completes additional deliberations. The Company will evaluate the impact of any change in accounting standard when the final interpretation is issued.

J. Discontinued Operations

In the fourth quarter of 2005, the Company sold its NORESCO domestic business for $82 million before customary purchase price adjustments.

In the second quarter of 2006, the Company completed the sale of the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited (Pan Am), previously included in the NORESCO business segment, for total proceeds of $2.6 million.

Total operating revenues reclassified to discontinued operations for the three and nine month periods ended September 30, 2005 were $35.2 million and $112.5 million, respectively.

K. 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.

During the second quarter of 2006, the Company began to utilize certain of the leased space previously deemed to have no economic benefit to the Company to make space available for the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. transition planning activities. The Company reversed approximately $2.4 million of the associated early termination liability for these leases during the second quarter of 2006. Additionally, the Company recorded a $0.5 million reduction in the early termination liability during the second quarter of 2006 resulting from a revision of the amount of estimated cash flows for one of its operating leases.

L. Other Events

On April 5, 2006, the Federal Energy Regulatory Commission (FERC) approved a settlement to resolve all issues raised in Equitrans, L.P.’s rate case filings. According to its terms, the settlement became effective on June 1, 2006. The settlement’s approval, which was recognized in the first quarter of 2006, improved operating income by $6.9 million for the first quarter of 2006, including $5.4 million relating to years 2005 and prior.

On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources’ natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. The Company plans to finance the transaction through a combination of equity and debt issuances and possibly hybrid issuances and/or asset sales.

The transaction requires approvals from the Pennsylvania Public Utility Commission (PA PUC) and the Public Service Commission of West Virginia (WV PSC) and is also under review by the Pennsylvania Attorney General and under the Hart-Scott-Rodino Act by the Federal Trade Commission (FTC). The PA PUC has adopted a procedural schedule with a recommended decision to be issued in the first quarter of 2007. The WV PSC has not adopted a procedural schedule at this time, but indications are that it will be similar to the PA PUC schedule. The Company is engaged in settlement negotiations with interveners in the PA PUC and WV PSC cases which may result in a resolution by the end of 2006. Similarly, the Company is complying with the information requests of the Pennsylvania Attorney General and the FTC and is targeting a timeframe consistent with that of the PA PUC and WV PSC. No assurance is given that the targeted timeframe will be achieved.

In January 2005, the Company purchased the 99% limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million.

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for proceeds of approximately $142 million after purchase price adjustments.

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 and sales volumes, liquidity, capital expenditures and earnings and the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. and the financing of that acquisition. 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, those set forth under Item 1A, “Risk Factors” of the Company’s Form 10-K for the year ended December 31, 2005.

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, 2006

vs. Three Months Ended September 30, 2005

Equitable Resources’ consolidated income from continuing operations for the three months ended September 30, 2006 totaled $31.8 million, or $0.26 per diluted share, compared to $45.8 million, or $0.37 per diluted share, reported for the same period a year ago. This $14.0 million decrease in income from continuing operations from 2005 to 2006 was largely due to a decrease in the average well-head sales price, increased operating expenses at the Supply segment, transition costs at the Utility and a reduction in Energy Marketing revenues. These factors were partially offset by an increase in production sales volumes and an increase in revenues in the Pipeline business as a result of the Equitrans rate case settlement. In addition, 2005 consolidated income from continuing operations contained a number of unusual items, including a gain on the sale of Kerr-McGee shares, which was offset by a charge for increased long-term incentive expenses and a charge for the termination and settlement of a defined benefit pension plan.

Nine Months Ended September 30, 2006

vs. Nine Months Ended September 30, 2005

Equitable Resources’ consolidated income from continuing operations for the nine months ended September 30, 2006 totaled $148.1 million, or $1.21 per diluted share, compared to $178.6 million, or $1.44 per diluted share, reported for the same period a year ago. This $30.5 million decrease in income from continuing operations from 2005 to 2006 was largely due to the unusual factors in 2005. On a nine month basis, 2005 unusual items include the items explained above and an additional gain on the sale of Kerr-McGee shares partially offset by a negative tax impact related to a tax benefit disallowance under Section 162(m) of the Internal Revenue Code and office consolidation charges. Excluding the unusual items, income from continuing operations decreased from 2005 to 2006 due to an increase in operating costs at the Supply segment, a decrease in the average well-head sales price, decreased Distribution margins due to warmer weather and lower gas customer usage in the first quarter of 2006 and transition costs at the Utility. These factors were partially offset by revenues resulting from the Equitrans rate case, an increase in production sales volumes and a reduction in bad debt expense.

OUTLOOK

Due to the recent repeal of the Public Utility Holding Company Act of 1935 (“PUHCA”), the Company expects in the near future to file applications with the Pennsylvania Public Utility Commission and the Public Service Commission of West Virginia for approvals to reorganize as a holding company. The reorganization will reduce Equitable Gas Company’s risk profile through the segregation of the utility assets and should provide greater flexibility in the financing of the Company’s utility operations. In addition, the holding company structure should result in a more typical organizational structure for a company with both regulated and unregulated businesses.

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

Customer Payment Assistance Programs

The gas cost rates effective for Equitable Gas Company’s residential and commercial tariff customers beginning October 1, 2005, included then-current high natural gas commodity prices, resulting in residential rates in the first nine months of 2006 as much as 40% higher than those in place in 2005. These increases presented a significant challenge to the Company’s low-income customers, especially during the winter months. Under various government- and Company-managed programs, significant funds were provided to assist low-income customers in re-establishing and maintaining their service during the 2005-2006 winter heating season. These programs enabled Equitable Gas to improve its bad debt expense in the first nine months of 2006 as compared to the first nine months of 2005 despite the high natural gas commodity prices. In addition, due to continued improvements in collection data and analysis, the Company was able to reduce its overall reserve for uncollectible accounts during the third quarter of 2006. The Company will continue to closely monitor its collections rates and adjust its reserve for uncollectible accounts as necessary.

Pipeline Rate Case Settlement

On April 5, 2006, the Federal Energy Regulatory Commission (FERC) approved a settlement to resolve all issues raised in Equitrans’ rate case filings. The settlement provides for the following:

• An overall cost of service underlying the settled rates of $62.8 million, which was derived on a global basis; an expected annual revenue increase of $6.0 million and an expected operating income increase of $3.2 million

• Replenishment of 7.1 Bcf of migrated base gas from prior periods

• Consolidation of transmission assets into a single transmission system with a system-wide rate

• Consolidation of gathering assets into a single gathering system with a system-wide rate

• Tracking and recovery of ongoing Pipeline Safety Act and Security related costs

• Redesigned contract storage services

• Five-year rate moratorium on gathering rates

• Three-year rate moratorium on transmission rates

According to its terms, the settlement became effective on June 1, 2006. The settlement’s approval, which was recognized in the first quarter of 2006, improved operating income by $6.9 million for the three months ended March 31, 2006, including $5.4 million relating to years 2005 and prior. On-going increases related to the new rates and related contract negotiations resulted in additional net increases of pipeline operating income of $1.8 million in the third quarter 2006 compared to the same quarter in the prior year.

RESULTS OF OPERATIONS

EQUITABLE UTILITIES

	Three Months Ended September 30,								Nine Months Ended September 30,
	2006			2005			%		2006			2005			%
OPERATIONAL DATA

Heating degree days (30 year normal average: Qtr – 124; YTD – 3,759)	123			34			261.8		3,226			3,465			(6.9	)

Residential sales and transportation volumes (MMcf)	1,307			1,292			1.2		14,168			16,838			(15.9	)
Commercial and industrial volumes (MMcf)	4,109			3,153			30.3		17,859			18,258			(2.2	)
Total throughput (MMcf) – Distribution Operations	5,416			4,445			21.8		32,027			35,096			(8.7	)

Net operating revenues (thousands):
Distribution Operations (regulated):
Residential	$	11,887		$	11,856		0.3		$	65,054		$	72,771		(10.6	)
Commercial & industrial	7,026			4,903			43.3		29,694			33,553			(11.5	)
Other	2,487			1,519			63.7		5,691			6,036			(5.7	)
Total Distribution Operations	21,400			18,278			17.1		100,439			112,360			(10.6	)
Pipeline Operations (regulated)	15,377			10,311			49.1		54,314			37,275			45.7
Energy Marketing	2,878			7,575			(62.0	)	29,522			27,867			5.9
Total net operating revenues	$	39,655		$	36,164		9.7		$	184,275		$	177,502		3.8

Total operating expenses as a % of net operating revenues	89.99		%	120.68		%			57.21		%	65.87		%

Operating income (thousands):
Distribution Operations (regulated)	$	(4,043	)	$	(16,362	)	75.3		$	25,528		$	22,898		11.5
Pipeline Operations (regulated)	5,595			1,811			208.9		24,943			11,065			125.4
Energy Marketing	2,417			7,074			(65.8	)	28,387			26,619			6.6
Total operating income	$	3,969		$	(7,477	)	153.1		$	78,858		$	60,582		30.2

Depreciation, depletion and amortization (DD&A):
Distribution Operations	$	4,987		$	4,830		3.3		$	14,874		$	14,058		5.8
Pipeline Operations	2,158			2,154			0.2		6,559			6,260			4.8
Energy Marketing	10			18			(44.4	)	47			56			(16.1	)
Total DD&A	$	7,155		$	7,002		2.2		$	21,480		$	20,374		5.4

Capital expenditures (thousands)	$	16,463		$	18,710		(12.0	)	$	45,543		$	40,283		13.1

	Three Months Ended September 30,								Nine Months Ended September 30,
	2006			2005			%		2006			2005			%
FINANCIAL DATA (Thousands)
Distribution revenues (regulated)	$	39,330		$	34,642		13.5		$	322,633		$	304,513		6.0
Pipeline revenues (regulated)	15,782			10,311			53.1		55,418			37,275			48.7
Marketing revenues	81,477			78,532			3.8		262,714			245,880			6.8
Less: intrasegment revenues	(10,986		)	(9,773		)	12.4		(41,437		)	(36,984		)	12.0
Total operating revenues	125,603			113,712			10.5		599,328			550,684			8.8

Purchased gas costs	85,948			77,548			10.8		415,053			373,182			11.2
Net operating revenues	39,655			36,164			9.7		184,275			177,502			3.8

Operating expenses:
Operating and maintenance (O & M)	14,037			14,465			(3.0	)	42,294			42,982			(1.6	)
Selling, general and administrative (SG&A)	14,494			22,174			(34.6	)	44,039			49,723			(11.4	)
Office consolidation impairment charges	—			—			—		(2,396		)	3,841			(162.4	)
DD&A	7,155			7,002			2.2		21,480			20,374			5.4
Total operating expenses	35,686			43,641			(18.2	)	105,417			116,920			(9.8	)

Operating income	$	3,969		$	(7,477	)	153.1		$	78,858		$	60,582		30.2

Three Months Ended September 30, 2006

vs. Three Months Ended September 30, 2005

Equitable Utilities’ operating income totaled $4.0 million for the three months ended September 30, 2006 compared to an operating loss of $7.5 million for the three months ended September 30, 2005. The $11.5 million increase in operating income is primarily due to a pension settlement charge in the third quarter of 2005 and increases in net operating margins in the distribution and pipeline divisions. These positive variances are partially offset by lower current quarter net operating marketing revenues and transition costs incurred in the third quarter of 2006 in planning for the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc.

Net operating revenues for the three months ended September 30, 2006 were $39.7 million compared to $36.2 million for the same quarter in 2005. The $3.5 million increase was due to increased revenues in the Pipeline business as a result of the previously reported Equitrans rate case settlement and increases in commercial revenues and gathering revenues in the Distribution business. The commercial revenues included the settlement of a prior period measurement dispute with a commercial customer. Commercial and industrial volumes increased 30% compared to 2005 as the majority of the increase relates to a low margin, high volume customer. The increase in gathering revenues was due to increased gathering rates and volumes in the non-regulated gathering business. These positive variances were partially offset by decreases in marketing storage asset optimization opportunities realized in the lower natural gas commodity price environment and the recognition in the third quarter of 2005 of certain energy marketing revenues previously deferred.

Operating expenses totaled $35.7 million for the three months ended September 30, 2006 compared to $43.6 million for the three months ended September 30, 2005. Excluding a $12.7 million pension settlement charge recognized in 2005 and $3.7 million of transition expenses in 2006 in planning for the pending acquisition discussed above, operating expenses increased $1.1 million. The increase was primarily due to $1.2 million in the pipeline business as a result of the first quarter rate case settlement which was partially offset by a decrease in bad debt expense as the provision for uncollectible accounts was reduced. The Company’s improved collection data and analysis, coupled with the regulatory and other assistance provided to assist low income customers, has allowed the Company to realize this improvement despite increased rates and customer bills.

Capital expenditures totaled $16.5 million for the three months ended September 30, 2006 compared to $18.7 million for the three months ended September 30, 2005. The $2.2 million decrease was due to decreased expenditures for the automated meter reading program, which began in the second quarter of 2005 as installation of the devices was substantially completed at the end of the third quarter of 2006, partially offset by capital expenditures of $2.5 million in the third quarter of 2006 in planning relating to the pending acquisition.

Nine Months Ended September 30, 2006

vs. Nine Months Ended September 30, 2005

Equitable Utilities’ operating income totaled $78.9 million for the nine months ended September 30, 2006 compared to $60.6 million for the nine months ended September 30, 2005. The $18.3 million increase in operating income is primarily due to an increase in pipeline net operating revenues, a pension settlement charge in the third quarter of 2005, a positive operating impact from office consolidation impairment charges recorded in the second quarter of 2005 and a partial reversal of those charges in the second quarter of 2006 and a reduction in bad debt expense. These positive variances were partially offset by a reduction in distribution margins, transition costs incurred in 2006 in planning for the pending acquisition and postretirement benefit expenses recognized in 2006 as a result of the Equitrans rate case settlement.

Net operating revenues for the nine months ended September 30, 2006 were $184.3 million compared to $177.5 million for the same period in 2005. The $6.8 million increase was due to increased revenues in the Pipeline business as a result of the previously reported Equitrans rate case settlement partially offset by decreases in Distribution net operating revenues. Lower residential net operating revenues were primarily due to decreased throughput from warmer weather and lower customer usage in 2006 as a result of conservation due to customers’ sensitivity to high commodity prices. Lower net operating revenues from commercial and industrial customers resulted as warmer weather produced high levels of gas inventory and low commodity margins.

Operating expenses totaled $105.4 million for the nine months ended September 30, 2006 compared to $116.9 million for the nine months ended September 30, 2005. The $11.5 million decrease in operating expenses was primarily attributable to the $12.7 million pension settlement charge in the third quarter of 2005 as previously discussed, the $6.2 million positive impact from office consolidation impairment charges recorded in the second quarter of 2005 and a partial reversal of those charges in the second quarter of 2006 as previously discussed, and a $4.4 million decrease in bad debt expense as the provision for uncollectible accounts was reduced. These positive variances were partially offset by $6.4 million of transition costs incurred in 2006 in planning for the pending acquisition and $3.5 million of postretirement benefit expenses recognized in 2006 as a result of the Equitrans rate case settlement.

Capital expenditures totaled $45.5 million for the nine months ended September 30, 2006 compared to $40.3 million for the nine months ended September 30, 2005. The $5.2 million increase was primarily due to increased expenditures for the automated meter reading program, which began in the second quarter of 2005 as installation of the devices was substantially completed at the end of the third quarter of 2006 and $2.5 million of capital expenditures in planning relating to the pending acquisition.

OUTLOOK

Equitable Utilities’ business strategy is focused on effectively managing its gas distribution assets, optimizing its return on assets, selectively growing its gas distribution business through acquisition and developing a portfolio of closely related, unregulated businesses with an emphasis on risk management and earnings contribution. On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources’ natural gas distribution assets in Pennsylvania and in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. The transaction requires approvals from the Pennsylvania Public Utility Commission (PA PUC) and the Public Service Commission of West Virginia (WV PSC) and is also under review by the Pennsylvania Attorney General and under the Hart-Scott-Rodino Act by the Federal Trade Commission (FTC). The PA PUC has adopted a procedural schedule with a recommended decision to be issued in the first quarter of 2007. The WV PSC has not adopted a procedural schedule at this time, but indications are that it will be similar to the PA PUC schedule. Several parties have intervened in the state regulatory cases, including governmental representatives, consumer advocates and commercial interests. The Company is engaged in settlement negotiations with the interveners in the PA PUC and WV PSC cases which may result in a resolution by the end of 2006. Similarly, the Company is complying with the information requests of the Pennsylvania Attorney General and the FTC and is targeting a timeframe consistent with that of the PA PUC and WV PSC. No assurance is given that the targeted timeframe will be achieved. The assets to be acquired will increase the number of customers by 475,000 or 173%, total storage capacity by 33 Bcf or 60%, miles of gathering pipelines by 936 miles, gathered volumes by 40%, and miles of high pressure transmission by 466 or 42%. Transition activities have commenced at Equitable Utilities to plan for the integration of The Peoples Natural Gas Company and Hope Gas, Inc.’s assets, resources and business processes into Equitable Resources. The Company incurred $6.4 million of transition planning costs through September 30, 2006. Based on the work completed to date, the Company expects that the conversion activities will continue at a slightly increased monthly rate and increase Equitable Utilities’ operating expenses in the fourth quarter of 2006 in anticipation of closing the transaction.

The gas cost rates effective for Equitable Gas residential and commercial tariff customers beginning October 1, 2006 include lower natural gas commodity prices in comparison with the prior year resulting in expected average residential bills being 20% lower than those in 2005.

EQUITABLE SUPPLY

OVERVIEW

In May 2005, the Company sold certain non-core gas properties and associated gathering assets for proceeds of approximately $142 million after purchase price adjustments. The unit of production depletion rate (or DD&A rate) decreased by $0.04 per Mcfe prospectively as a result of this transaction.

RESULTS OF OPERATIONS

EQUITABLE SUPPLY

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006		2005		%		2006		2005			%
OPERATIONAL DATA

Capital expenditures (thousands) (a)	$	82,871	$	53,535	54.8		$	205,398	$	201,348		2.0

Production:
Total sales volumes (MMcfe)	19,442		18,670		4.1		56,886		55,492			2.5
Average (well-head) sales price ($/Mcfe)	$	4.66	$	5.43	(14.2	)	$	4.82	$	4.98		(3.2	)

Company usage, line loss (MMcfe)	1,410		1,334		5.7		3,929		3,681			6.7

Natural gas inventory usage, net (MMcfe)	—		—		—		—		(51		)	100.0

Natural gas and oil production (MMcfe)	20,852		20,004		4.2		60,815		59,122			2.9

Lease operating expenses (LOE), excluding production taxes ($/Mcfe)	$	0.32	$	0.29	10.3		$	0.30	$	0.31		(3.2	)
Production taxes ($/Mcfe)	$	0.45	$	0.48	(6.3	)	$	0.48	$	0.44		9.1
Production depletion ($/Mcfe)	$	0.62	$	0.58	6.9		$	0.62	$	0.60		3.3

Gathering:
Gathered volumes (MMcfe)	26,723		29,227		(8.6	)	80,273		91,339			(12.1	)
Average gathering fee ($/Mcfe)	$	1.05	$	0.81	29.6		$	1.02	$	0.77		32.5
Gathering and compression expense ($/Mcfe)	$	0.42	$	0.29	44.8		$	0.39	$	0.31		25.8
Gathering and compression depreciation ($/Mcfe)	$	0.14	$	0.13	7.7		$	0.14	$	0.11		27.3

(in thousands)
Production operating income	$	53,690	$	71,642	(25.1	)	$	172,357	$	187,079		(7.9	)
Gathering operating income	9,540		8,259		15.5		28,299		21,345			32.6
Total operating income	$	63,230	$	79,901	(20.9	)	$	200,656	$	208,424		(3.7	)

Production depletion	$	12,888	$	11,526	11.8		$	37,619	$	35,425		6.2
Gathering and compression depreciation	3,811		3,760		1.4		11,399		10,485			8.7
Other DD&A	1,083		779		39.0		3,059		2,731			12.0
Total DD&A	$	17,782	$	16,065	10.7		$	52,077	$	48,641		7.1

(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.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006		2005		%		2006		2005		%

FINANCIAL DATA (Thousands)
Production revenues	$	92,949	$	103,450	(10.2	)	$	281,141	$	282,266	(0.4	)
Gathering revenues	28,042		23,802		17.8		81,626		70,470		15.8
Total operating revenues	120,991		127,252		(4.9	)	362,767		352,736		2.8

Operating expenses:
LOE, excluding production taxes	6,753		5,784		16.8		18,543		18,500		0.2
Production taxes	9,423		9,543		(1.3	)	29,422		26,023		13.1
Gathering and compression (O&M)	11,123		8,425		32.0		31,547		28,622		10.2
SG&A	12,680		7,534		68.3		30,522		22,007		38.7
Office consolidation impairment charges	—		—		—		—		519		(100.0	)
DD&A	17,782		16,065		10.7		52,077		48,641		7.1
Total operating expenses	57,761		47,351		22.0		162,111		144,312		12.3
Operating income	$	63,230	$	79,901	(20.9	)	$	200,656	$	208,424	(3.7	)

Equity in earnings of nonconsolidated investments	$	71	$	131	(45.8	)	$	53	$	261	(79.7	)

Three Months Ended September 30, 2006

vs. Three Months Ended September 30, 2005

Equitable Supply’s operating income totaled $63.2 million for the three months ended September 30, 2006 compared to $79.9 million for the three months ended September 30, 2005. The $16.7 million decrease in operating income was primarily due to a decrease in the average well-head sales price and increased operating expenses, partially offset by an increase in production sales volumes.

Total operating revenues were $121.0 million for the three months ended September 30, 2006 compared to $127.3 million for the three months ended September 30, 2005. The $6.3 million decrease in total operating revenues was primarily due to a 14% decrease in the average well-head sales price, partially offset by a 4% increase in production sales volumes and an 18% increase in gathering revenues. The $0.77 per Mcfe decrease in the average well-head sales price was primarily the result of unfavorable market prices, increased gathering rates, and discounted sales to obtain capacity. The increase in production sales volumes was primarily due to new wells drilled in 2005 and 2006, partially offset by the natural decline from the remaining wells. The increase in gathering revenues was due to a 30% increase in the average gathering fee, partially offset by a 9% decline in gathered volumes. The increase in the average gathering fee is reflective of the Company’s commitment to an increased infrastructure program, along with higher gas prices and related operating cost increases. The average gathering fee was also positively impacted by the transfer of certain regulated gathering facilities to Equitable Utilities. The decrease in gathered volumes is primarily due to the aforementioned transfer of certain regulated gathering facilities, partially offset by increased gathered volumes for Equitable Supply production in 2006.

Operating expenses totaled $57.8 million for the three months ended September 30, 2006 compared to $47.4 million for the three months ended September 30, 2005. The $10.4 million increase in operating expenses was primarily attributable to increases of $5.1 million in SG&A, $2.7 million in gathering and compression, $1.7 million in DD&A and $1.0 million in LOE, excluding production taxes. The increase in SG&A was primarily related to a total of $7.3 million for a reserve established in connection with West Virginia royalty disputes, increased legal expenses and reserves established for uncollectible accounts. These increases were partially offset by the reduction of a reserve which was established as part of the previous sale of certain non-core gas properties and adjustments to reserves for certain employment-related costs. The increase in gathering and compression was due primarily to increased compressor station operation and repair costs, increased field labor and related employment costs, increased property taxes and increased gathering line operation and repair costs. The increase in gathering and compression expense was also attributable to the timing of repair and maintenance activities performed in 2005. The increase in DD&A was primarily related to the increase in produced volumes and the Company’s increased investment in infrastructure. The increase in LOE was primarily due to increased direct well

expenses, increased location maintenance and increased insurance costs. Additionally, production taxes decreased slightly, $0.1 million, despite the increase in production sales volumes. The decrease in production taxes was due to decreased severance taxes resulting from lower current gas commodity prices, partially offset by increased property taxes resulting from increased prices and sales in prior years.

Capital expenditures totaled $82.9 million for the three months ended September 30, 2006 compared to $53.5 million for the three months ended September 30, 2005. The $29.4 million increase was mainly due to increased spending on drilling and development and the Big Sandy Pipeline project. The Company drilled 174 and 137 wells for the three months ended September 30, 2006 and 2005, respectively.

Nine Months Ended September 30, 2006

vs. Nine Months Ended September 30, 2005

Equitable Supply’s operating income totaled $200.7 million for the nine months ended September 30, 2006 compared to $208.4 million for the nine months ended September 30, 2005. The $7.7 million decrease in operating income was primarily due to higher operating expenses and a decrease in the average well-head sales price, partially offset by an increase in production sales volumes.

Total operating revenues were $362.8 million for the nine months ended September 30, 2006 compared to $352.7 million for the nine months ended September 30, 2005. The $10.1 million increase in total operating revenues was primarily attributable to a 16% increase in gathering revenues and a 3% increase in production sales volumes, partially offset by a 3% decrease in the average well head sales price. The increase in gathering revenues was due to a 33% increase in the average gathering fee, partially offset by a 12% decrease in gathered volumes. The increase in the average gathering fee is reflective of the Company’s commitment to an increased infrastructure program, along with higher gas prices and rising operating cost. The average gathering fee was also positively impacted by the transfer of certain regulated gathering facilities to Equitable Utilities. The decrease in gathered volumes is primarily attributable to the aforementioned transfer of certain regulated gathering facilities, the sale of certain non-core gathering assets in May 2005 and third-party volume shut-ins caused by extended maintenance projects on interstate pipelines. These decreases were partially offset by increased gathered volumes for Equitable Supply production in 2006. The increase in production sales volumes was primarily due to new wells drilled in 2005 and 2006, partially offset by the natural decline from the remaining wells. The $0.16 per Mcfe decrease in the average sales price was primarily the result of increased gathering rates partially offset by favorable market prices.

Operating expenses were $162.1 million for the nine months ended September 30, 2006, compared to $144.3 million for the nine months ended September 30, 2005. The $17.8 million increase in operating expenses was primarily due to increases of $8.5 million in SG&A, $3.5 million in DD&A, $3.4 million in production taxes and $2.9 million in gathering and compression, partially offset by a 2005 impairment charge of $0.5 million related to the office consolidation. The increase in SG&A was primarily related to increased legal expenses and a reserve established for West Virginia royalty disputes. The increase in DD&A was primarily related to the increase in produced volumes and the Company’s increased investment in infrastructure. The increase in production taxes was due to increased property taxes and severance taxes. The increase in property taxes was the result of increased prices and sales in prior years. The increase in severance taxes was due to increased sales and higher current gas commodity prices. The increase in gathering and compression was due to increased electricity from newly installed electric compressors, increased property taxes and increased compressor operation and repair costs.

Capital expenditures totaled $205.4 million for the nine months ended September 30, 2006 compared to $201.3 million for the nine months ended September 30, 2005. The $4.1 million increase was due to increased spending on drilling and development and the Big Sandy Pipeline project, partially offset by the $57.5 million acquisition in January 2005 of the limited partnership interest in ESP. The Company drilled 449 and 310 wells for the nine months ended September 30, 2006 and 2005, respectively.

OUTLOOK

Equitable Supply’s business strategy is focused on achieving profit maximization by primarily focusing on developing new opportunities, through increased drilling and other development in the Appalachian Basin, as well as improvements to and expansion of its gathering systems, 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. The Company expects to exceed its previous drilling target of 550 wells and sell between 76 Bcfe and 77 Bcfe of natural gas in 2006. The drilling program includes drilling

horizontal wells, with five test wells expected to be drilled by the end of 2006, to determine reservoir response that will enable the Company to begin testing the economic viability of using horizontal techniques in future reserve development. The Company plans to drill 17 wells as a part of a coalbed methane infill pilot to evaluate the economic viability of accelerating production by down spacing coal bed wells. Equitable Supply plans to continue to expand its pipeline and compression infrastructure in order to manage increased gathered volumes from both Company drilling programs and third party shippers. The Company also plans to expand its gathering systems by approximately 190 miles of pipeline and approximately 20,000 horsepower of compression in 2006.

In the second quarter of 2006, the Company filed its certificate application with the FERC for approval to build a 70-mile, 20-inch diameter pipeline which will connect the Company’s Kentucky Hydrocarbon processing plant in Langley, Kentucky, with the Tennessee Gas Pipeline interconnect in Carter County, Kentucky, and will provide up to 130,000 Dekatherms per day of firm transportation service. The pipeline, known as The Big Sandy Pipeline, is owned and operated by Equitrans and is targeted for completion in 2007. Equitrans has secured most of the materials, labor and right-of-way necessary to complete the project and the FERC has completed its environmental assessment for the pipeline, which is subject to public comment through the end of October 2006. The Company is also planning an upgrade to the Langley plant for completion in early 2008.

Both projects are projected to cost a total of $191 million and should enable the Company to further support its drilling growth, mitigate pipeline curtailments, increase flexibility and reliability of its midstream gathering systems and satisfy third party producer demand in the Appalachian Basin. Natural gas processing expansion will continue to be required in order to meet the interstate pipeline gas quality standards and will represent an opportunity for the Company. The Company is evaluating several processing, pipeline and compression expansion opportunities in Appalachia and expects to invest in additional projects in the future.

CAPITAL RESOURCES AND LIQUIDITY

Operating Activities

Cash flows provided by operating activities totaled $550.5 million for the first nine months of 2006 as compared to $451.1 million of cash flows used in operating activities for the first nine months of 2005, a net increase of $1.0 billion in cash flows provided by operating activities between years. The increase in cash flows provided by operating activities was attributable primarily to the following:

• a $830.6 million net increase in cash inflows for margin deposit requirements on the Company’s natural gas hedge agreements, primarily resulting from decreased natural gas prices and increased margin deposit thresholds with financial institutions during the first nine months of 2006;

• a greater decrease in accounts receivable primarily due to a decrease in natural gas prices during the first nine months of 2006;

partially offset by:

• a greater decrease in accounts payable primarily due to a decrease in natural gas prices during the first nine months of 2006.

Investing Activities

Cash flows used in investing activities totaled $256.5 million for the first nine months of 2006 as compared to $284.5 million of cash flows provided by investing activities for the first nine months of 2005, a net increase of $541.0 million in cash flows used in investing activities between years. The increase in cash flows used in investing activities was primarily due to the following:

• net proceeds of $394.9 million received from the sale of approximately 6.3 million shares of Kerr-McGee Corporation common stock in the first nine months of 2005;

• cash proceeds of $142.0 million from the sale of non-core properties in the first nine months of 2005;

• an increase in capital expenditures to $253.5 million in the first nine months of 2006 from $193.7 million in the first nine months of 2005;

partially offset by:

• the Company’s acquisition of the 99% limited partnership interest in ESP for $57.5 million in the first nine months of 2005.

During the third quarter of 2006, the Company’s Board of Directors approved an additional $83 million of capital commitments under the Company’s 2006 Capital Program for future expenditures related to the Big Sandy Pipeline and Langley plant expansion projects previously discussed. In October 2006, the Company’s Board of Directors approved an additional $61 million of capital commitments under the Company’s 2006 Capital Program for future expenditures related to the Company’s well development and gathering system improvements and extensions projects.

The Company is forecasting total capital expenditures for the year ended December 31, 2006, of approximately $375 million. Amounts committed under the 2006 Capital Program that are not spent by the end of 2006 are expected to be spent on approved capital projects in subsequent years.

Financing Activities

Cash flows used in financing activities totaled $368.9 million for the first nine months of 2006 as compared to $166.6 million of cash flows provided by financing activities for the first nine months of 2005, a net increase of $535.5 million in cash flows used in financing activities between years. The increase in cash flows used in financing activities was attributable to the following:

• a $310.7 million decrease in amounts borrowed under short-term loans in the first nine months of 2006 compared to a $142.0 million increase in short-term borrowings in the first nine months of 2005. The decrease in short-term borrowings in the first nine months of 2006 was primarily the result of decreased requirements for funding margin deposits as previously discussed;

• proceeds in the first nine months of 2005 from the September 2005 issuance of $150.0 million of notes with a stated interest rate of 5% and a maturity date of October 1, 2015;

partially offset by:

• no repurchases of shares of the Company’s common stock under the Company’s share repurchase program during the first nine months of 2006 in anticipation of the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. compared to repurchases of $84.5 million of common stock in the first nine months of 2005.

The Company believes that cash generated from operations, amounts available under its credit facilities and amounts which the Company could obtain in the debt and equity markets given its financial position, are adequate to meet the Company’s reasonably foreseeable operating liquidity requirements. The Company intends to finance the $970 million purchase price for the previously discussed acquisition through a combination of equity and debt issuances and possible hybrid issuances and/or asset sales.

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.

	Senior
	Unsecured	Commercial
Rating Service	Debt	Paper
Moody’s Investors Service	A-2	P-1
Standard & Poor’s Ratings Services	A -	A-2

On March 2, 2006, Standard & Poor’s Ratings Services placed the Company’s short and long-term credit ratings on CreditWatch with negative implications and Moody’s Investors Service placed the ratings under review for possible downgrade. These actions resulted from the Company’s announcement that it had entered into a definitive agreement to acquire Dominion Resources’ natural gas distribution and midstream assets in Pennsylvania and its natural gas distribution assets in West Virginia, subject to anti-trust and regulatory approvals. The final ratings outcomes are expected to be determined after the acquisition financing plan has been reviewed by the ratings agencies and the regulatory approval process is near completion.

The Company’s credit ratings are 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 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 with respect to its hedging instruments 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%. This calculation excludes unrealized gains or losses from hedging transactions recorded in accumulated other comprehensive income (loss). As of September 30, 2006, 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 first nine months of 2006, the Company increased its hedge position for 2007 through 2013. The approximate volumes and prices of the Company’s production hedges for 2007 through 2009 are:

Swaps	2007		2008		2009
Total Volume (Bcf)	56		54		38
Average Price per Mcf (NYMEX)*	$	4.74	$	4.64	$	5.90

Collars	2007		2008		2009
Total Volume (Bcf)	10		10		10
Average Floor Price per Mcf (NYMEX)*	$	7.61	$	7.61	$	7.61
Average Cap Price per Mcf (NYMEX)*	$	11.27	$	11.27	$	11.27

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

The Company’s current hedged position provides price protection for a substantial portion of expected equity production for the years 2006 through 2008 and a smaller but significant portion of expected equity production for the years 2009 through 2013. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is less than $0.01 per diluted share for 2006 and ranges from $0.01 to $0.02 per diluted share per year for 2007 and 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.

West Virginia Royalty Litigation

In June 2006, the West Virginia Supreme Court of Appeals issued a decision involving interpretation of certain types of oil and gas leases of an unrelated party, in which a class of royalty owners in the state of West Virginia filed a lawsuit claiming that the Defendant in the case underpaid royalties by deducting certain post-production costs not permitted by such types of leases and not paying a fair value for the gas produced from the royalty owners’ leases. Similar claims have been brought against others in the oil and gas industry, including the Company, since that judgment. The Company believes that any adverse impact of that decision has been reflected in its financial statements.

Incentive Compensation

The Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R) on January 1, 2006, which results in the Company recognizing compensation cost for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The Company previously applied Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25) in accounting for its share-based compensation and consequently did not recognize any compensation cost for its stock option awards. The Company’s estimate of compensation cost for stock options is based on the use of the Black-Scholes option-pricing model. The Black-Scholes model is considered a “theoretical” or probability model used to estimate the price an option would sell for in the market today. The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.

The Company adopted SFAS No. 123R using the modified prospective method, under which the Company is recording compensation expense for its unvested stock options beginning January 1, 2006. As such, the Company did not restate any prior period income statement amounts. In addition, the adoption of SFAS No. 123R did not result in any significant changes to the Company’s method for valuing its stock options from that previously used for pro forma disclosures under SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123).

The adoption of SFAS No. 123R did not have a significant impact on the Company’s operating results for the first nine months of 2006, as the Company has shifted its compensation focus to the issuance of time-restricted stock awards and performance-based units for which it already recognized compensation expense under generally accepted accounting principles. 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. No new stock options have been awarded since 2003; all stock options granted subsequent to 2003 have comprised options granted for reload rights associated with previously-awarded options.

The Company recorded approximately $0.7 million of compensation expense related to stock options in the first nine months of 2006, the majority of which related to stock option reloads which immediately vested under the terms of the related stock option award agreements. The majority of the Company’s previously issued stock options were already vested at the time of adoption of SFAS No. 123R, and associated compensation expense yet to be recognized was insignificant. All stock options outstanding as of September 30, 2006 are fully vested, and as such, the Company does not anticipate incurring any additional compensation expense related to currently outstanding stock options.

Had compensation cost been determined based on the fair value at the grant date for prior periods’ stock option grants consistent with the methodology prescribed in SFAS No. 123R, net income for the first nine months of 2005 would have been reduced by an estimated $1.4 million, or approximately $0.01 per diluted share.

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

	Nine Months Ended September 30,
	2006		2005
	(Millions)
Short-term incentive compensation expense	$	9.1	$	7.6
Long-term incentive compensation expense	19.4		31.8
Total incentive compensation expense	$	28.5	$	39.4

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 compensation expenses during the first nine months of 2005 were higher than during the same period in 2006 due to a greater number of unvested units outstanding during 2005 than during the current year.

Dividend

On October 18, 2006, the Board of Directors declared a regular quarterly cash dividend of 22 cents per share payable December 1, 2006, to shareholders of record on November 10, 2006.

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, 2005 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, 2006. 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.

Equitable Resources, Inc. and Subsidiaries

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company’s primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of the Company 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. 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, 2006, the Company continued to execute its hedging strategy by utilizing forward contracts, swap agreements and collar agreements covering approximately 329.0 Bcf of natural gas. These derivatives have hedged a portion of expected equity production through 2013. See 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 discussion. A decrease of 10% in the market price of natural gas from the September 30, 2006 levels would increase the fair value of natural gas instruments by approximately $239.7 million. An increase of 10% in the market price of natural gas would decrease the fair value by approximately $239.5 million.

With respect to the derivative commodity instruments held by the Company for trading purposes as of September 30, 2006, an increase or decrease of 10% in the market price of natural gas from the September 30, 2006 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, 2005. The Company assumed a 10% change in the price of natural gas from its levels at September 30, 2006. 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.

Equitable Resources, Inc. and Subsidiaries

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of management, including the Company’s Principal Executive Officer and Principal Financial Officers, an evaluation of the Company’s disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officers 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 (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) that occurred during the third quarter of 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1A. Risk Factors

Information regarding risk factors is discussed in Item 1A, “Risk Factors” of the Company’s Form 10-K for the year ended December 31, 2005. There have been no material changes from the risk factors previously disclosed in the Company’s Form 10-K.

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, 2006.

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 2006 (July 1 – July 31)	4,224	$	34.71	—	8,385,400

August 2006 (August 1 – August 31)	4,234	$	35.66	—	8,385,400

September 2006 (September 1 – September 30)	4,337	$	36.04	—	8,385,400

Total	12,795			—

(a) Represents Company-directed purchases made by the Company’s 401(k) plans.

(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, April 15, 2004 and July 13, 2005.

Item 6. Exhibits

31.1	Rule 13(a)-14(a) Certification of Principal Executive Officer

31.2	Rule 13(a)-14(a) Certification of Co-Principal Financial Officer

31.3	Rule 13(a)-14(a) Certification of Co-Principal Financial Officer

32	Section 1350 Certification of Principal Executive Officer and Co-Principal Financial Officers

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/ Philip P. Conti
		Philip P. Conti
		Vice President and Chief Financial Officer


Date: October 26, 2006

INDEX TO EXHIBITS

Exhibit No.	Document Description	Incorporated by Reference

31.1	Rule 13(a)-14(a) Certification of Principal Executive Officer	Filed Herewith

31.2	Rule 13(a)-14(a) Certification of Co-Principal Financial Officer	Filed Herewith

31.3	Rule 13(a)-14(a) Certification of Co-Principal Financial Officer	Filed Herewith

32	Section 1350 Certification of Principal Executive Officer and Co-Principal Financial Officers	Filed Herewith