Form 10-Q

10-Q 1 d10q.htm FORM 10-Q Form 10-Q

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

¨	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: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

Virginia

23-1184320

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

THREE RADNOR CORPORATE CENTER, SUITE 300

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

(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

Indicate by a 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. (Check one):


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

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

As of October 31, 2006, 18,693,706 shares of common stock of the registrant were issued and outstanding.

PENN VIRGINIA CORPORATION

INDEX


		Page
PART I Financial Information

Item 1	Financial Statements

	Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2006 and 2005	1

	Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005	2

	Consolidated Statements of Cash Flows for the Three Months and Nine Months Ended September 30, 2006 and 2005	3

	Notes to Consolidated Financial Statements	4

Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4	Controls and Procedures	49

PART II Other Information

Item 1A	Risk Factors	50

Item 6	Exhibits	50

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME – Unaudited

(in thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Revenues
Natural gas	$	50,540		$	54,071		$	160,384		$	137,011
Oil and condensate		5,964			3,369			16,378			10,128
Natural gas midstream		100,809			101,940			305,340			213,351
Coal royalties		26,612			22,739			73,288			60,921
Other		4,468			4,240			13,060			11,157

Total revenues		188,393			186,359			568,450			432,568

Expenses
Cost of midstream gas purchased		80,272			87,812			254,615			182,278
Operating		14,259			9,141			33,438			22,642
Exploration		12,660			5,960			26,061			31,550
Taxes other than income		2,322			4,080			11,217			11,481
General and administrative		10,900			8,369			33,289			23,876
Impairment of oil and gas properties		—			3,488			—			3,488
Depreciation, depletion and amortization		23,336			20,701			66,581			56,324

Total expenses		143,749			139,551			425,201			331,639

Operating income		44,644			46,808			143,249			100,929

Other income (expense)
Interest expense		(7,108	)		(4,195	)		(17,292	)		(11,070	)
Interest income and other		379			276			1,138			971
Derivatives		17,940			3,578			11,403			(11,186	)

Income before minority interest and income taxes		55,855			46,467			138,498			79,644
Minority interest		18,539			13,684			31,187			22,274
Income tax expense		14,435			12,793			42,105			22,693

Net income	$	22,881		$	19,990		$	65,206		$	34,677

Net income per share, basic	$	1.22		$	1.08		$	3.49		$	1.87

Net income per share, diluted	$	1.21		$	1.07		$	3.46		$	1.85

Weighted average shares outstanding, basic		18,679			18,560			18,658			18,524
Weighted average shares outstanding, diluted		18,895			18,760			18,872			18,707

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)


	September 30, 2006			December 31, 2005
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	12,386		$	25,913
Accounts receivable		129,395			133,086
Derivative assets		15,271			11,551
Other		7,125			7,635

Total current assets		164,177			178,185

Property and equipment
Oil and gas properties (successful efforts method)		970,062			717,423
Other property and equipment		648,578			538,035
Accumulated depreciation, depletion and amortization		(334,751	)		(272,239	)

Net property and equipment		1,283,889			983,219
Equity investments		25,069			26,672
Goodwill and intangibles, net		41,970			45,769
Derivative assets		5,880			8,917
Other assets		13,342			8,784

Total assets	$	1,534,327		$	1,251,546

Liabilities and Shareholders’ Equity
Current liabilities
Current maturities of long-term debt	$	10,826		$	8,108
Accounts payable and accrued liabilities		114,212			114,678
Derivative liabilities		10,876			29,387
Income taxes payable		—			2,355

Total current liabilities		135,914			154,528

Other liabilities		25,441			24,448
Derivative liabilities		8,605			11,706
Deferred income taxes		176,421			111,186
Long-term debt of the Company		180,000			79,000
Long-term debt of PVR		315,772			246,846
Minority interest in PVR		317,199			313,524
Shareholders’ equity Preferred stock of $100 par value – 100,000 shares authorized; none issued		—			—
Common stock of $0.01 par value – 32,000,000 shares authorized; 18,693,691 and 18,624,002 shares issued and outstanding at September 30, 2006, and December 31, 2005		187			186
Paid-in capital		100,880			98,541
Retained earnings		281,334			222,456
Deferred compensation obligation		1,129			580
Accumulated other comprehensive income		(7,063	)		(7,816	)
Treasury stock – 33,312 and 23,644 shares common stock, at cost, on September 30, 2006, and December 31, 2005		(1,492	)		(832	)
Unearned compensation		—			(2,807	)

Total shareholders’ equity		374,975			310,308

Total liabilities and shareholders’ equity	$	1,534,327		$	1,251,546

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

(in thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Cash flows from operating activities
Net income	$	22,881		$	19,990		$	65,206		$	34,677
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		23,336			20,701			66,581			56,324
Commodity derivative contracts:
Total derivative losses (gains)		(17,675	)		273			(10,042	)		15,422
Cash settlements of derivatives		(4,216	)		(4,886	)		(10,433	)		(7,112	)
Deferred income taxes		13,248			6,750			32,071			10,793
Minority interest		18,539			13,684			31,187			22,274
Impairment of oil and gas properties		—			3,488			—			3,488
Dry hole and unproved leasehold expense		9,566			2,733			17,925			21,649
Other		919			4,575			5,483			6,464
Changes in operating assets and liabilities		(19,437	)		(3,467	)		(917	)		(15,472	)

Net cash provided by operating activities		47,161			63,841			197,061			148,507

Cash flows from investing activities
Proceeds from the sale of property and equipment		30			6,624			2,505			17,375
Acquisitions, net of cash acquired		(6,816	)		(67,492	)		(171,479	)		(290,169	)
Additions to property and equipment		(76,700	)		(51,938	)		(182,239	)		(129,898	)

Net cash used in investing activities		(83,486	)		(112,806	)		(351,213	)		(402,692	)

Cash flows from financing activities
Dividends paid		(2,101	)		(2,087	)		(6,298	)		(6,250	)
Distributions paid to minority interest holders of PVR		(9,827	)		(8,491	)		(28,144	)		(22,247	)
Proceeds from issuance of PVR partners’ capital		—			39			—			126,475
Proceeds from borrowings of the Company		35,000			25,000			121,000			66,000
Repayments of borrowings of the Company		—			(25,000	)		(20,000	)		(53,000	)
Proceeds from borrowings of PVR		15,000			67,000			79,800			293,800
Repayments of borrowings of PVR		(5,000	)		(12,800	)		(8,300	)		(153,600	)
Payments for debt issuance costs		—			(346	)		—			(2,385	)
Other		1,833			1,370			2,567			1,927

Net cash provided by financing activities		34,905			44,685			140,625			250,720

Net increase (decrease) in cash and cash equivalents		(1,420	)		(4,280	)		(13,527	)		(3,465	)
Cash and cash equivalents – beginning of period		13,806			26,286			25,913			25,471

Cash and cash equivalents – end of period	$	12,386		$	22,006		$	12,386		$	22,006

Supplemental disclosures:
Cash paid during the periods for:
Interest (net of amounts capitalized)	$	6,842		$	4,649		$	17,592		$	10,220
Income taxes	$	8,475		$	2,726		$	16,640		$	10,386

Noncash investing activities:
Deferred tax liabilities related to acquisition, net	$	—		$	—		$	32,759		$	—
Issuance of PVR units for acquisition	$	—		$	10,415		$	—		$	10,415
Assumption of liabilities in acquisitions	$	—		$	3,981		$	—		$	3,981

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

PENN VIRGINIA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Unaudited

September 30, 2006

1. Nature of Operations

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent energy company that is engaged in three primary business segments. Our oil and gas segment explores for, develops, produces and sells crude oil, condensate and natural gas primarily in the eastern, Gulf Coast and mid-continent onshore areas of the United States. Our coal segment and natural gas midstream segment operate through our 39 percent ownership in Penn Virginia Resource Partners, L.P. (“PVR”). Due to our control of the general partner of PVR, the financial results of the Partnership are included in our consolidated financial statements. However, PVR functions with a capital structure that is independent of the Company, consisting of its own debt instruments and publicly traded common units.

In the coal segment, PVR does not operate any mines. Instead, PVR enters into leases with various third-party operators which give those operators the right to mine coal reserves on PVR’s land in exchange for royalty payments. PVR also provides fee-based infrastructure facilities to some of its lessees and third parties to generate coal services revenues. These facilities include coal loading facilities, preparation plants and coal handling facilities located at end-user industrial plants. PVR also sells timber growing on its land.

PVR purchased its natural gas midstream business on March 3, 2005 through the acquisition of Cantera Gas Resources, LLC (the “Cantera Acquisition”). As a result of the Cantera Acquisition, PVR owns and operates a significant set of midstream assets. PVR’s natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services.

The general partner of PVR is Penn Virginia Resource GP, LLC, a wholly owned subsidiary of Penn Virginia. Penn Virginia recently formed Penn Virginia GP Holdings, L.P. (“GP Holdings”), a Delaware limited partnership. GP Holdings filed a Registration Statement on Form S-1 in July 2006 with the intent of completing an initial public offering of common units. GP Holdings was formed to own the general partner interest, all of the incentive distribution rights, 7,475,414 common units and 7,649,880 subordinated units in PVR. If the offering is completed, GP Holdings will use the proceeds from the offering to purchase newly issued common and class B common units from PVR, and PVR expects to use substantially all of the proceeds from such purchase to repay debt outstanding under its revolving credit facility. The initial public offering of GP Holdings common units is not guaranteed to occur. Please refer to GP Holdings’ Registration Statement on Form S-1, as amended, for more information on the potential initial public offering of GP Holdings common units.

2. Summary of Significant Accounting Policies

Our accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2005, except as discussed below. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

Our unaudited consolidated financial statements include the accounts of Penn Virginia, all of its wholly-owned subsidiaries and PVR, of which we indirectly owned the sole two percent general partner interest and an approximately 37 percent limited partner interest as of September 30, 2006. Penn Virginia Resource GP, LLC, a wholly-owned subsidiary of Penn Virginia, serves as PVR’s general partner and controls PVR. We own and operate our undivided oil and gas reserves through our wholly-owned subsidiaries. We account for our undivided interest in oil and gas properties using the proportionate consolidation method, whereby our share of assets, liabilities, revenues and expenses is included in the appropriate classification in our consolidated financial statements. Intercompany balances and transactions have been eliminated in consolidation. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and Securities and Exchange Commission (“SEC”) regulations. These statements involve the use

of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our consolidated financial statements have been included. These financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2005. Operating results for the three months and nine months ended September 30, 2006 are not necessarily indicative of the results that may be expected for the year ending December 31, 2006. Certain reclassifications have been made to conform to the current period’s presentation.

Derivative Activities

Prior to January 1, 2006, all of our commodity derivative contracts were accounted for using hedge accounting in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities. Effective January 1, 2006, some of our derivative contracts no longer qualified for hedge accounting. Effective May 1, 2006, we elected to discontinue hedge accounting prospectively for all remaining and future commodity derivatives. See Note 5 for further discussion of derivative activities and the discontinuation of hedge accounting.

New Accounting Standards

In December 2004, the Financial Accounting Standards Board (the “FASB”) issued the final revised version of SFAS No. 123(R), Share-Based Payment, which requires companies to recognize in the income statement the grant-date fair value of stock options and other equity-based compensation issued to employees. In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107, Share-Based Payment, regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations. Effective January 1, 2006, we adopted SFAS No. 123(R). Beginning January 1, 2006, we recognize compensation expense related to share-based payments on a straight-line basis over the requisite service period for share-based payment awards granted after the effective date of SFAS No. 123(R). For unvested stock options granted prior to the effective date of SFAS No. 123(R), we recognize compensation expense in the same manner as was used for pro forma disclosures prior to the effective date of SFAS No. 123(R). See Note 8 for more information regarding the adoption of SFAS No. 123(R).

In June 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 creates a single model to address uncertainty in income tax positions. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. It also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition and clearly scopes income taxes out of SFAS No. 5, Accounting for Contingencies. FIN 48 is effective for fiscal years beginning after December 15, 2006. We have not yet determined the impact on our consolidated financial statements of adopting FIN 48 effective January 1, 2007.

In September 2006, the FASB issued FASB Staff Position (“FSP”) AUG AIR-1, Accounting for Planned Major Maintenance Activities. FSP AUG AIR-1 prohibits companies from accruing as a liability the future costs of periodic major overhauls and maintenance of plant and equipment. FSP AUG AIR-1 is effective for fiscal years beginning after December 15, 2006. We expect that the provisions of FSP AUG AIR-1 will not have a material impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, a standard that provides enhanced guidance for using fair value to measure assets and liabilities. SFAS No. 157 also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect of fair value measurements on earnings. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. SFAS No. 157 does not expand the use of fair value in any new circumstances. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop fair value assumptions. SFAS No. 157 is effective for fiscal years and interim periods beginning after November 15, 2007. We have not yet determined the impact on our financial statements of adopting SFAS No. 157 effective January 1, 2008.

In September 2006, the SEC published SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, to address quantifying the financial statement effects of misstatements. The SEC believes that registrants and auditors must quantify the effects on the current year financial statements of correcting all misstatements, including both the carryover and reversing effects of uncorrected prior year misstatements. After considering all relevant quantitative and qualitative factors, if a misstatement is material to either the income statement or the balance sheet, a registrant’s financial statements must be adjusted. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We expect that adoption of the provisions of SAB No. 108 will not have a material impact on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, which requires companies to recognize on their balance sheets the overfunded or underfunded status of pension and other postretirement benefit plans, to measure a plan’s assets and obligations as of the end of the employer’s fiscal year and to recognize in comprehensive income changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. The requirement to recognize the funded status of a benefit plan is effective for fiscal years 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. We have not yet determined the impact on our financial statements of adopting SFAS No. 158 for our fiscal year ending December 31, 2006.

3. Acquisitions

Huff Creek Acquisition—PVR Coal Segment

On May 25, 2006, PVR acquired from Huff Creek Energy Company and Appalachian Coal Holdings, Inc. the lease rights to approximately 69 million tons of coal reserves located on approximately 20,000 acres in Boone, Logan and Wyoming Counties, West Virginia. The purchase price was approximately $65 million and was funded with long-term debt under PVR’s revolving credit facility.

Crow Creek Acquisition—Oil and Gas Segment

On June 13, 2006, we acquired 100 percent of the capital stock of Crow Creek Holding Corporation (“Crow Creek”) in a cash transaction for approximately $71.5 million, subject to certain adjustments (the “Crow Creek Acquisition”). Crow Creek was a privately owned independent exploration and production company with operations primarily in the Oklahoma portions of the Arkoma and Anadarko Basins. The Crow Creek Acquisition was funded with long-term debt under our revolving credit facility.

Transwestern Acquisition—PVR Midstream Segment

On June 30, 2006, PVR completed the acquisition of approximately 115 miles of gathering pipelines and related compression facilities in Texas and Oklahoma to complement its existing midstream systems (the “Transwestern Acquisition”). PVR paid for the acquisition with approximately $15 million in cash. In July 2006, PVR borrowed $15 million under its revolving credit facility to replenish the cash used in the Transwestern Acquisition.

4. Equity Investments

In July 2004, PVR acquired from affiliates of Massey Energy Company (“Massey”) a 50 percent interest in Coal Handling Solutions, LLC, a joint venture formed to own and operate end-user coal handling facilities. PVR accounts for the investment under the equity method of accounting. In 2004, the original cash investment of $28.4 million was capitalized. At September 30, 2006, PVR’s equity investment totaled $25.0 million, which exceeded its portion of the underlying equity in net assets by $9.2 million. The difference is being amortized to equity earnings over the life of coal services contracts in place at the time of the acquisition. In accordance with the equity method, PVR recognized equity earnings of $1.0 million and $0.8 million during the nine months ended September 30, 2006 and 2005, with a corresponding increase in the investment. Cash distributions of approximately $2.7 million and $2.3 million received from the joint venture during the nine months ended September 30, 2006 and 2005 reduced the investment. Equity earnings are included in other revenues on our consolidated statements of income.

5. Derivative Instruments

Discontinuation of Hedge Accounting

As a result of price volatility resulting from the 2005 hurricane season, a large portion of our natural gas derivatives and natural gas liquid (“NGL”) derivatives no longer qualified for hedge accounting. Because of this non-qualification and to increase clarity in our consolidated financial statements (see below for further discussions), we elected to discontinue hedge accounting prospectively for our remaining commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in our future earnings through 2008 as the original hedged transactions occur. This change in reporting will have no impact on our reported cash flows, although our future results of operations will be affected by mark-to-market gains and losses which fluctuate with changes in oil and gas prices.

The following table summarizes the effects of commodity derivative activities on our consolidated statements of income (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Income statement caption:
Natural gas revenues	$	663		$	(2,551	)	$	247		$	(3,177	)
Oil and condensate revenues		(103	)		(283	)		(333	)		(631	)
Midstream revenues		(2,724	)		(1,991	)		(7,456	)		(1,208	)
Cost of gas purchased		1,899			974			6,181			780
Derivatives		17,940			3,578			11,403			(11,186	)

Decrease in income before minority interest and income taxes	$	17,675		$	(273	)	$	10,042		$	(15,422	)

Realized and unrealized derivative impact:
Cash paid for derivative settlements	$	(4,216	)	$	(4,886	)	$	(10,433	)	$	(7,112	)
Unrealized derivative gain (loss)		21,891			4,613			20,475			(8,310	)

Decrease in income before minority interest and income taxes	$	17,675		$	(273	)	$	10,042		$	(15,422	)

Oil and Gas Segment Commodity Derivatives

We utilize put options, costless collar and three-way collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements.

With respect to a put option contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are not required to make any payment in connection with the settlement of a put option contract. For a costless collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. A three-way collar contract consists of a collar contract as described above plus a put option contract sold by us with a price below the floor price of the collar. This additional put requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. Combining the collar contract with the additional put option results in our entitlement to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the

additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option.

The fair values of our oil and gas derivative agreements are determined based on third party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of September 30, 2006. The following table sets forth our positions as of September 30, 2006:


	Average Volume Per Day		Weighted Average Price							Estimated Fair Value (in thousands)
	Average Volume Per Day		Additional Put Option		Floor			Ceiling		Estimated Fair Value (in thousands)
Natural Gas Costless Collars	(in Mmbtus	)				(per Mmbtu	)
Fourth Quarter 2006	26,269				$	8.17		$	15.15	$	6,138
First Quarter 2007	20,000				$	9.00		$	19.03		3,463
Second Quarter 2007	15,000				$	7.33		$	12.93		1,345
Third Quarter 2007	15,000				$	7.33		$	12.93		1,314
Fourth Quarter 2007	11,667				$	8.28		$	15.78		1,342
First Quarter 2008	10,000				$	9.00		$	17.95		1,163

Natural Gas Three-way Collars	(in Mmbtus	)				(per Mmbtu	)
Fourth Quarter 2006 (October only)	25,000		$	4.50	$	6.00		$	9.40		1,163
First Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		219
Second Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		307
Third Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		258
Fourth Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		124
First Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		(54	)
Second Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		215
Third Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		188
Fourth Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		88

Natural Gas Put Options	(in Mmbtus	)				(per Mmbtu	)
Fourth Quarter 2006	1,333				$	9.00					393

Crude Oil Costless Collars	(in barrels	)				(per barrel	)
Fourth Quarter 2006	200				$	60.00		$	72.20		7
First Quarter 2007	200				$	60.00		$	72.20		(11	)
Second Quarter 2007	200				$	60.00		$	72.20		(29	)
Third Quarter 2007	200				$	60.00		$	72.20		(41	)
Fourth Quarter 2007	200				$	60.00		$	72.20		(47	)

										$	17,545

Based upon our assessment of derivative agreements at September 30, 2006, we reported (i) a net derivative asset of $17.5 million and (ii) a loss in accumulated other comprehensive income of $0.1 million, net of related income tax benefit.

At the time we entered into our natural gas derivatives, physical sales prices correlated well with NYMEX natural gas prices; however, beginning in the second half of 2005, basis differentials for certain derivative agreements widened as NYMEX natural gas prices reached historically high levels. In the first quarter of 2006, our correlation assessment indicated that certain NYMEX natural gas derivatives could no longer be considered “highly effective” hedges under the parameters of the accounting rules. Consequently, we discontinued hedge accounting effective January 1, 2006 for certain natural gas derivatives that were no longer considered highly effective. As discussed above, beginning May 1, 2006, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives.

PVR Midstream Segment Commodity Derivatives

In addition to costless collar derivative contracts, PVR also utilizes swap contracts in its natural gas midstream business. With respect to a swap contract, the counterparty is required to make a payment to PVR if the settlement price for any settlement period is less than the swap price for such contract, and PVR is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.

The fair values of PVR’s derivative agreements are determined based on forward price quotes and regression analysis for the respective commodities as of September 30, 2006. The following table sets forth PVR’s positions as of September 30, 2006 for commodities related to natural gas midstream revenues (ethane, propane and crude oil) and cost of midstream gas purchased (natural gas):


	Average Volume Per Day		Weighted Average Price			Estimated Fair Value (in thousands)
Ethane Swaps	(in gallons	)		(per gallon	)
Fourth Quarter 2006	73,126		$	0.4870		$	(1,251	)
First Quarter 2007 through Fourth Quarter 2007	34,440		$	0.5050			(916	)
First Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700			(1,026	)

Propane Swaps	(in gallons	)		(per gallon	)
Fourth Quarter 2006	52,080		$	0.7060			(1,679	)
First Quarter 2007 through Fourth Quarter 2007	26,040		$	0.7550			(1,709	)
First Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175			(1,798	)

Crude Oil Swaps	(in barrels	)		(per barrel	)
Fourth Quarter 2006	1,100		$	44.45			(2,638	)
First Quarter 2007 through Fourth Quarter 2007	560		$	50.80			(3,376	)
First Quarter 2008 through Fourth Quarter 2008	560		$	49.27			(3,653	)

Crude Oil Collars	(in barrels	)		(per barrel	)
Fourth Quarter 2006 (October only)	270		$	73.59			107

Natural Gas Swaps	(in MMbtu	)		(per MMbtu	)
Fourth Quarter 2006	8,005		$	6.98			(1,009	)
First Quarter 2007 through Fourth Quarter 2007	4,000		$	6.97			987
First Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97			1,377

						$	(16,584	)

Based upon our assessment of derivative agreements at September 30, 2006, PVR reported (i) a net derivative liability related to the PVR midstream segment of $16.6 million, (ii) a loss in accumulated other comprehensive income of $7.0 million, net of a related income tax benefit of $3.8 million, and (iii) a net loss on derivatives for hedge ineffectiveness of zero and $0.1 million for the three months and nine months ended September 30, 2006 related to derivatives in the PVR midstream segment.

At the time PVR entered into its natural gas derivatives and certain NGL derivatives, physical purchase prices of natural gas correlated well with NYMEX natural gas prices and physical sales prices of NGLs correlated well with NGL index prices. However, in the second half of 2005, basis differentials for certain derivative agreements widened as NYMEX natural gas prices and NGL index prices reached historically high levels. In the first quarter of 2006, PVR’s correlation assessment indicated that its NYMEX natural gas derivatives and certain NGL derivatives could no longer be considered “highly effective” hedges under the parameters of the accounting rules. Consequently, PVR discontinued hedge accounting effective January 1, 2006 for its natural gas derivatives and

certain NGL derivatives that were no longer considered highly effective. As discussed above, beginning May 1, 2006, PVR elected to discontinue hedge accounting prospectively for its remaining and future commodity derivatives.

In November 2005, PVR entered into a basis swap for the period January 2006 through July 2006. The basis swap relates to purchases of natural gas in the Texas/Oklahoma Basin region. During the three months and nine months ended September 30, 2006, PVR recognized mark-to-market gains of zero and $0.7 million related to the basis swap. In accordance with SFAS No. 133, changes in market value of the derivative instrument were charged to earnings. Mark-to-market gains are recorded in the derivatives line in the other income (expense) section of our consolidated statements of income.

Interest Rate Swaps—PVR

In September 2005, PVR entered into interest rate swap agreements (the “PVR Revolver Swaps”) to establish fixed rates on $60 million of the portion of the outstanding balance on PVR’s revolving credit facility that is based on the London Inter Bank Offering Rate (“LIBOR”) until March 2010. PVR pays a weighted average fixed rate of 4.22 percent on the notional amount plus the applicable margin, and the counterparties pay a variable rate equal to the three-month LIBOR. Settlements on the PVR Revolver Swaps are recorded as interest expense. The PVR Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest expense. PVR reported (i) a derivative asset of approximately $1.4 million at September 30, 2006 and (ii) a gain in accumulated other comprehensive income of $0.9 million, net of related income tax expense of $0.5 million, at September 30, 2006 related to the PVR Revolver Swaps. In connection with periodic settlements, PVR recognized $0.2 million and $0.3 million in net hedging gains in interest expense for the three months and nine months ended September 30, 2006.

Interest Rate Swaps—PVA

In August 2006, we entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on $50 million of the LIBOR-based portion of the outstanding balance on our revolving credit facility until December 2010. We pay a weighted average fixed rate of 5.34 percent on the notional amount plus the applicable margin, and the counterparties pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest expense. We reported (i) a derivative liability of approximately $0.7 million at September 30, 2006 and (ii) a loss in accumulated other comprehensive income of $0.5 million, net of related income tax benefit of $0.3 million, at September 30, 2006 related to the Revolver Swaps. In connection with periodic settlements, we recognized less than $0.1 million in net hedging gains in interest expense for the three months and nine months ended September 30, 2006.

6. Pension Plans and Other Postretirement Benefits

In accordance with SFAS No. 132, Employers’ Disclosures about Pensions and Other Postretirement Benefits, the following table provides the components of net periodic benefit costs for the respective plans shown for the three months and nine months ended September 30, 2006 and 2005 (in thousands):


	Pension								Post-retirement Healthcare
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005		2006		2005		2006		2005
Service cost	$	—	$	—	$	—	$	—	$	8	$	7	$	24	$	21
Interest cost		32		32		97		97		63		65		189		196
Amortization of prior service cost		1		1		4		4		22		22		66		66
Amortization of transitional obligation		1		1		3		3		—		—		—		—
Recognized actuarial loss		9		8		26		23		21		13		65		39

Net periodic benefit cost	$	43	$	42	$	130	$	127	$	114	$	107	$	344	$	322

7. Earnings per Share

The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share for the three months and nine months ended September 30, 2006 and 2005 (in thousands, except per share data):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Net income	$	22,881	$	19,990	$	65,206	$	34,677

Weighted average shares, basic Effective of dilutive securities:		18,679		18,560		18,658		18,524
Stock options		216		200		214		183

Weighted average shares, diluted		18,895		18,760		18,872		18,707

Net income per share, basic	$	1.22	$	1.08	$	3.49	$	1.87

Net income per share, diluted	$	1.21	$	1.07	$	3.46	$	1.85

8. Share-Based Payments

Adoption of New Accounting Standard

We have several stock compensation plans (collectively, the “Stock Compensation Plans”) that allow incentive and nonqualified stock options and restricted stock to be granted to key employees and officers and nonqualified stock options and deferred common stock units to be granted to directors. Prior to January 1, 2006, we accounted for those plans under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations, as permitted by SFAS No. 123, Accounting for Stock-Based Compensation. Stock-based compensation cost in our statements of income prior to 2006 included only costs related to restricted stock and deferred common stock units. Prior to 2006, we did not recognize expense for options as permitted by SFAS No. 123 because all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R) using the modified prospective transition method. Under that transition method, compensation cost recognized in the three months and nine months ended September 30, 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006 based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123 and (b) compensation cost for all share-based payments granted on or after January 1, 2006 based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Results for prior periods have not been restated. For the three months and nine months ended September 30, 2006, we recognized $0.7 million and $2.1 million of compensation expense related to the Stock Compensation Plans. The total income tax benefit recognized in our consolidated statements of income for the Stock Compensation Plans was $0.3 million and $0.8 million for the three months and nine months ended September 30, 2006.

As a result of adopting SFAS No. 123(R) on January 1, 2006, our income before minority interest and income taxes and our net income are $0.4 million and $0.2 million lower for the three months ended September 30, 2006 and $1.0 million and $0.6 million lower for the nine months ended September 30, 2006 than if we had continued to account for share-based compensation under Opinion No. 25. Basic and diluted earnings per share are each $0.01 lower for the three months ended September 30, 2006 and $0.03 lower for the nine months ended September 30, 2006 than if we had continued to account for share-based compensation under Opinion No. 25.

Prior to the adoption of SFAS No. 123(R), we presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in our consolidated statements of cash flows. SFAS No. 123(R) requires the cash flows resulting from the tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. The $0.8 million and $1.0 million excess tax benefit classified as a financing cash inflow for the three months and nine months ended September 30, 2006 would have been classified as an operating cash inflow if we had not adopted SFAS No. 123(R).

The following table illustrates the effect on net income and earnings per share as if we had applied the fair value recognition provision of SFAS No. 123 to options granted under our stock option plans for the three months and nine ended September 30, 2005. For purposes of this pro forma disclosure, the value of the options is estimated using a Black-Scholes-Merton option-pricing formula and amortized to expense over the options’ vesting periods (in thousands, except per share data).


	Three Months Ended September 30, 2005			Nine Months Ended September 30, 2005
Net income, as reported	$	19,990		$	34,677
Add: Stock-based employee compensation expense included in reported net income related to restricted units and director compensation, net of related tax effects		262			746
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(461	)		(1,288	)

Pro forma net income	$	19,791		$	34,135

Earnings per share
Basic—as reported	$	1.08		$	1.87
Basic—pro forma	$	1.07		$	1.84
Diluted—as reported	$	1.07		$	1.85
Diluted—pro forma	$	1.05		$	1.82

Stock Options

The exercise price of all options granted under the Stock Compensation Plans is at the fair market value of our common stock on the date of the grant. Options may be exercised at any time after vesting and prior to 10 years following the grant. Options vest upon terms established by the Compensation and Benefits Committee of our Board of Directors. In addition, all options will vest upon a change of control of the Company, as defined by the Stock Compensation Plans. In the case of employees, if a grantee’s employment terminates (i) for cause, all of the grantee’s options, whether vested or unvested, will be automatically forfeited, (ii) by reason of death, disability or retirement after reaching age 62 and providing ten consecutive years of service, the grantee’s options will automatically vest and (iii) for any other reason, the grantee’s unvested options will be automatically forfeited. In the case of directors, if a grantee’s membership on our Board of Directors terminates for any reason, the grantee’s unvested options will be automatically forfeited. We have a policy of issuing new shares to satisfy share option exercises.

Options granted on or before January 2, 2004 under the Stock Compensation Plans vested on the first anniversary of the date of grant. Options granted after January 2, 2004 vest ratably over a three-year period so that one-third is exercisable after one year, another third is exercisable after two years and the remaining third is exercisable after three years.

The fair value of each option award is estimated on the date of grant using the Black-Scholes-Merton option-pricing formula that uses the assumptions noted in the following table. Expected volatilities are based on historical changes in the market value of our stock. Separate groups of employees that have similar historical exercise behavior are considered separately to estimate expected lives. Options granted have a maximum term of ten years. We base the risk-free interest rate on the U.S. Treasury rate for the week of the grant having a term equal to the expected life of the option.


	Three Months and Nine Months Ended September 30, 2006
Expected volatility	20.6% to 26.0	%
Dividend yield	0.67% to 0.71	%
Expected life	3.5 to 4.6 years
Risk-free interest rate	4.68% to 5.01	%

The following table summarizes activity since our most recent fiscal year end with respect to the common stock options awarded under the Stock Compensation Plans described above.


Options	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at January 1, 2006	621,631		$	26.68
Granted	203,691			63.24
Exercised	(63,566	)		24.39
Forfeit	(17,299	)		52.38

Outstanding at September 30, 2006	744,457		$	36.28	7.3	$	23,537

Exercisable at September 30, 2006	410,666		$	22.44	6.2	$	18,667

The weighted-average grant-date fair value of options granted during the three months and nine months ended September 30, 2006 was $14.67 and $14.29 per option. The total intrinsic value of options exercised during the three months and nine months ended September 30, 2006 was $2.1 million and $2.8 million.

A summary of the status of our nonvested shares as of September 30, 2006 and changes during the nine months then ended, is presented below:


Nonvested Shares	Shares		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2006	232,937		$	9.19
Granted	203,691			14.29
Vested	(85,538	)		8.78
Forfeit	(17,299	)		11.61

Nonvested at September 30, 2006	333,791		$	12.28

As of September 30, 2006, we had $2.6 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Stock Compensation Plans. We expect that cost to be recognized over a weighted-average period of 1.1 years. The total fair value of shares vested during the three months and nine months ended September 30, 2006 was $0.8 million.

Cash received from the exercise of share options for the nine months ended September 30, 2006 was $2.5 million. The actual tax benefit realized for the tax deductions from option exercises was $1.0 million for the nine months ended September 30, 2006.

Other Stock Compensation Plans

Accounting for restricted common stock and deferred common stock units did not significantly change from the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2005.

9. Comprehensive Income

Comprehensive income represents certain changes in equity during the reporting period, including net income and charges directly to equity which are excluded from net income. Accumulated other comprehensive income was $7.1 million at September 30, 2006. For the three months and nine months ended September 30, 2006 and 2005, the components of comprehensive income were as follows (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006		2005
Net income	$	22,881		$	19,990		$	65,206	$	34,677
Unrealized holding gains (losses) on derivative activities, net of tax		(1,156	)		(28,366	)		399		(32,144	)
Reclassification adjustment for derivative activities, net of tax		54			1,421			354		1,671

Comprehensive income	$	21,779		$	(6,955	)	$	65,959	$	4,204

10. Suspended Well Costs

The following table describes the changes in capitalized exploratory drilling costs since December 31, 2005 that are pending the determination of proved reserves (in thousands, except wells):


	Nine Months Ended September 30, 2006
	# Wells		Cost
Balance at beginning of period	3		$	1,670
Charged to expense	(3	)		(1,670	)

Balance at end of period	—		$	—

We had no capitalized exploratory drilling costs that had been under evaluation for a period greater than one year as of September 30, 2006.

11. Commitments and Contingencies

Drilling Commitments

In January 2006, we entered into an agreement to purchase oil and gas drilling services from a third party for three years, beginning in the fourth quarter of 2006. The agreement includes early termination provisions that would require us to pay a penalty if we terminate the agreement prior to the end of the original three-year term. The amount of the penalty is based on the number of days remaining in the three-year term and declines as time passes. As of September 30, 2006, drilling services had not commenced, and the pre-commencement early termination penalty amount would have been $0.7 million if we had terminated the agreement on that date. Management intends to utilize drilling services under this agreement for the full three-year term and has no plans to terminate the agreement early.

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, management believes these claims will not have a material effect on our financial position, liquidity or operations.

Environmental Compliance

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

The operations of PVR’s coal lessees and PVR’s natural gas midstream segment are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified PVR against any and all future environmental liabilities. PVR regularly visits coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Management believes that the operations of PVR’s coal lessees and PVR’s natural gas midstream segment comply with existing regulations and does not expect any material impact on its financial condition or results of operations.

As of September 30, 2006, PVR’s environmental liabilities were $2.4 million, which represents PVR’s best estimate of its liabilities as of that date related to the coal and natural gas midstream businesses. PVR has reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

12. Segment Information

Segment information has been prepared in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an

enterprise about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our chief operating decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our oil and gas operations, PVR’s coal operations and PVR’s natural gas midstream operations. Accordingly, our reportable segments are as follows:

•

Oil and Gas – crude oil and natural gas exploration, development and production.

•

Coal (the “PVR coal” segment) – management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber and real estate rentals; leasing of fee-based infrastructure facilities to certain lessees for coal handling, transportation and processing; and investment in a joint venture which primarily provides coal handling facilities to end-user industrial plants.

•

Natural Gas Midstream (the “PVR midstream” segment) – natural gas processing, natural gas gathering and other related services.

The following table presents a summary of certain financial information relating to our segments (in thousands):


	Oil and Gas		PVR Coal		PVR Midstream		Corporate and Other			Consolidated
For the Three Months Ended September 30, 2006:
Revenues	$	56,896	$	29,890	$	101,544	$	63		$	188,393
Intersegment revenues (1)		—		—		60		(60	)		—
Operating costs and expenses		25,473		5,591		86,141		3,208			120,413
Depreciation, depletion and amortization		13,365		5,551		4,313		107			23,336

Operating income (loss)	$	18,058	$	18,748	$	11,150	$	(3,312	)		44,644

Interest expense											(7,108	)
Interest income and other											379
Derivatives											17,940

Income before minority interest and taxes										$	55,855

Total assets	$	806,982	$	418,201	$	287,041	$	22,103		$	1,534,327

Additions to property and equipment and acquisitions, net of cash acquired	$	70,558	$	5,735	$	6,036	$	1,187		$	83,516

For the Three Months Ended September 30, 2005:
Revenues	$	57,845	$	25,922	$	102,482	$	110		$	186,359
Operating costs and expenses		15,903		4,067		92,682		2,710			115,362
Impairment of oil and gas properties		3,488		—		—		—			3,488
Depreciation, depletion and amortization		11,433		5,257		3,902		109			20,701

Operating income (loss)	$	27,021	$	16,598	$	5,898	$	(2,709	)		46,808

Interest expense											(4,195	)
Interest income and other											276
Derivatives											3,578

Income before minority interest and taxes										$	46,467

Total assets	$	541,305	$	373,404	$	291,104	$	11,242		$	1,217,055

Additions to property and equipment and acquisitions, net of cash acquired (2)	$	34,808	$	66,943	$	4,344	$	85		$	106,180

(1)	Represents agent fees paid by the oil and gas segment to the PVR midstream segment for marketing certain natural gas production under an agreement effective September 1, 2006.

(2)	PVR coal segment excludes noncash expenditures of $14.4 million. Oil and gas segment excludes a third quarter 2005 cash disbursement of $13.2 million for a second quarter 2005 acquisition.


	Oil and Gas		PVR Coal		PVR Midstream (1)		Corporate and Other			Consolidated
For the Nine Months Ended September 30, 2006:
Revenues	$	178,283	$	83,115	$	306,946	$	106		$	568,450
Intersegment revenues (2)		—		—		60		(60	)		—
Operating costs and expenses		63,362		12,922		272,265		10,071			358,620
Depreciation, depletion and amortization		38,755		15,050		12,451		325			66,581

Operating income (loss)	$	76,166	$	55,143	$	22,290	$	(10,350	)		143,249

Interest expense											(17,292	)
Interest income and other											1,138
Derivatives											11,403

Income before minority interest and taxes										$	138,498

Total assets	$	806,982	$	418,201	$	287,041	$	22,103		$	1,534,327

Additions to property and equipment and acquisitions, net of cash acquired (3)	$	243,016	$	80,902	$	27,577	$	2,223		$	353,718

For the Nine Months Ended September 30, 2005:
Revenues	$	147,720	$	69,428	$	214,775	$	645		$	432,568
Operating costs and expenses		58,912		10,793		193,941		8,181			271,827
Impairment of oil and gas properties		3,488		—		—		—			3,488
Depreciation, depletion and amortization		33,777		13,440		8,797		310			56,324

Operating income (loss)	$	51,543	$	45,195	$	12,037	$	(7,846	)		100,929

Interest expense											(11,070	)
Interest income and other											971
Derivatives											(11,186	)

Income before minority interest and taxes										$	79,644

Total assets	$	541,305	$	373,404	$	291,104	$	11,242		$	1,217,055

Additions to property and equipment and acquisitions, net of cash acquired (4)	$	120,133	$	95,974	$	203,810	$	150		$	420,067

(1)	Represents the results of operations of the PVR midstream segment since March 3, 2005, the closing date of the Cantera Acquisition.

(2)	Represents agent fees paid by the oil and gas segment to the PVR midstream segment for marketing certain natural gas production.

(3)	Oil and gas segment excludes noncash expenditures of $32.8 million.

(4)	PVR coal segment excludes noncash expenditures of $14.4 million.

13. PVR Unit Split

On February 23, 2006, the board of directors of the general partner of PVR declared a two-for-one split of PVR’s common and subordinated units. To effect the split, PVR distributed one additional common unit and one additional subordinated unit (a total of 16,997,325 common units and 3,824,940 subordinated units) on April 4, 2006 for each common unit and subordinated unit held of record at the close of business on March 28, 2006.

14. Subsequent Events

On October 25, 2006, our Board of Directors declared a quarterly dividend of $0.1125 per share payable November 22, 2006 to shareholders of record at the close of business on November 6, 2006.

Effective November 1, 2006, we amended our revolving credit facility to increase the commitment from $200 million to $300 million and increase the borrowing base from $300 million to $400 million.

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

The following analysis of financial condition and results of operations of Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) and its subsidiaries should be read in conjunction with our consolidated financial statements and the accompanying notes in Item 1, “Financial Statements.” Our discussion and analysis include the following items:

•

Overview of Business

•

Acquisitions and Investments

•

Current Performance

•

Critical Accounting Policies and Estimates

•

Liquidity and Capital Resources

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Results of Operations

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Environmental

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Recent Accounting Pronouncements

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Forward-Looking Statements

Overview of Business

We are an independent energy company that is engaged in three primary business segments: oil and gas, coal and natural gas midstream. Our coal and natural gas midstream segments operate through our 39 percent ownership in Penn Virginia Resource Partners, L.P. (“PVR”). A description of each of our reportable segments follows:

Oil and Gas Segment

In our oil and gas segment, we explore for, develop, produce and sell crude oil, condensate and natural gas primarily in the Appalachian, Mississippi, east Texas, mid-continent and Gulf Coast onshore regions of the United States.

Our revenues, profitability and future rate of growth are highly dependent on the prevailing prices for oil and natural gas, which are affected by numerous factors that are generally beyond our control. Crude oil prices are generally determined by global supply and demand. Natural gas prices are influenced by national and regional supply and demand. A substantial or extended decline in the price of oil or natural gas could have a material adverse effect on our revenues, profitability and cash flow and could, under certain circumstances, result in an impairment of some of our oil and natural gas properties. Our future profitability and growth is also highly dependent on the results of our exploratory and development drilling programs.

In addition to our conventional development program, we have continued to expand our presence in unconventional plays by developing coal bed methane (“CBM”) gas reserves in Appalachia. By employing horizontal drilling techniques, we expect to continue to increase the value from the CBM-prospective properties we own. We are committed to expanding our oil and gas reserves and production primarily by using our ability to generate exploratory prospects and development drilling programs internally.

PVR Coal Segment

The PVR coal segment includes management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber and real estate rentals; leasing of fee-based infrastructure facilities to certain lessees for coal handling, transportation and processing; and investment in a joint venture which primarily provides coal handling facilities to end-user industrial plants.

PVR enters into leases with various third-party operators for the right to mine coal reserves on its properties in exchange for royalty payments. PVR does not operate any mines. In managing its properties, PVR actively works with its lessees to develop efficient methods to exploit reserves and to maximize production from its properties. In addition to coal royalty revenues, PVR generates coal services revenues from fees charged to lessees for the use of its coal preparation and loading facilities, which enhance their production levels and generate additional coal royalty revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through PVR’s joint venture with Massey Energy Company (“Massey”). PVR also earns revenues from oil and gas royalty interests, coal transportation (“wheelage”) rights and the sale of standing timber on its properties.

Coal royalties are impacted by several factors that PVR generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. The possibility exists that new legislation or regulations have or may be adopted which may have a significant impact on the mining operations of PVR’s lessees or their customers’ ability to use coal and which may require PVR, its lessees or its lessees’ customers to change operations significantly or incur substantial costs. See Item 1A, “Risk Factors.”

PVR Midstream Segment

PVR purchased its natural gas midstream business on March 3, 2005. The results of operations of the PVR midstream segment since that date are included in the operations and financial summary table below.

The PVR midstream segment derives revenues primarily from natural gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. PVR continually seeks new supplies of natural gas to both offset the natural declines in production from the wells currently connected to its systems and to increase throughput volume. New natural gas supplies are obtained for all of PVR’s systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and by contracting for natural gas that has been released from competitors’ systems.

Revenues, profitability and the future rate of growth of the PVR midstream segment are highly dependent on market demand and prevailing natural gas liquid (“NGL”) and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty.

Corporate and Other

Corporate and other primarily represents corporate functions.

Ownership of and Relationship with PVR

Penn Virginia and PVR are publicly traded on the New York Stock Exchange under the symbols “PVA” and “PVR.” Due to our control of the general partner of PVR, the financial results of PVR are included in our consolidated financial statements. However, PVR functions with a capital structure that is independent of ours, consisting of its own debt instruments and publicly traded common units. The following diagram depicts our ownership of PVR as of September 30, 2006 (after the effect of the two-for-one unit split described in Note 13 of the Notes to Consolidated Financial Statements):

LOGO

As a result of our ownership in PVR, we receive cash payments from PVR in the form of quarterly cash distributions. We received approximately $7.1 million and $19.8 million of cash distributions from PVR during the three months and nine months ended September 30, 2006. As part of our ownership of PVR’s general partner, we also own the rights, referred to as incentive distribution rights, to receive an increasing percentage of quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. The cash payments we received from PVR in the three months and nine months ended September 30, 2006 and 2005 were as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
Limited partner units	$	5,790	$	5,042	$	16,624	$	14,474
General partner interest (2%)		319		276		914		745
Incentive distribution rights		976		325		2,277		585

Total	$	7,085	$	5,643	$	19,815	$	15,804

In November 2004, 25 percent of PVR’s subordinated units converted to common units because PVR met certain requirements to qualify for early conversion. In November 2005, another 25 percent converted to common units. The remaining 50 percent of PVR’s subordinated units will convert to common units on November 14, 2006, when the quarterly distribution will be paid.

Acquisitions and Investments

Strategy

Our oil and gas investment strategy is to increase our inventory of predictable, low risk development prospects, with a focus on unconventional natural gas, and to selectively drill higher risk exploration opportunities which could make a meaningful difference to our production and reserve profile.

The strategy of our coal and natural gas midstream businesses conducted through PVR is to evaluate acquisition opportunities that are accretive to cash available for distribution to PVR’s unitholders, of which we are the largest single unitholder. These opportunities include, but are not limited to, acquiring additional coal properties and reserves and acquiring or constructing assets for coal services and natural gas midstream gathering and processing, all of which would provide a primarily fee-based revenue stream.

Huff Creek Acquisition—PVR Coal Segment

On May 25, 2006, PVR acquired from Huff Creek Energy Company and Appalachian Coal Holdings, Inc. the lease rights to approximately 69 million tons of coal reserves located on approximately 20,000 acres in Boone, Logan and Wyoming Counties, West Virginia (the “Huff Creek Acquisition”). The purchase price was $65 million and was funded with long-term debt under PVR’s revolving credit facility.

Crow Creek Acquisition—Oil and Gas Segment

On June 13, 2006, we acquired 100 percent of the capital stock of Crow Creek Holding Corporation (“Crow Creek”) in a cash transaction for approximately $71.5 million, subject to certain adjustments (the “Crow Creek Acquisition”). Crow Creek was a privately owned independent exploration and production company with operations primarily in the Oklahoma portions of the Arkoma and Anadarko Basins. The acquired assets of Crow Creek include approximately 42.7 billion cubic feet equivalent (“Bcfe”) of net proved reserves, about 85 percent of which is natural gas. The Crow Creek Acquisition was funded with long-term debt under our revolving credit facility.

Transwestern Acquisition—PVR Midstream Segment

Coal Infrastructure Construction—PVR Coal Segment

In September 2006, PVR completed construction of a new 600-ton per hour coal processing plant and rail loading facility one of its lessees located in Knott County in eastern Kentucky. The facility began operations in October 2006. Since acquiring fee ownership and lease rights to the property’s coal reserves in July 2005, PVR made cumulative capital expenditures of $15.4 million related to the construction of the facility.

Current Performance

Operating income for the nine months ended September 30, 2006 was $147.1 million. The oil and gas segment, combined with the operating results of corporate, contributed $69.6 million to operating income, and PVR’s coal and midstream segments, in which we have a 41 percent interest in net income, including incentive distribution rights, contributed $77.4 million, before the deduction of the 59 percent interest in net income to which we do not own rights. The following table presents a summary of certain financial information relating to our segments (in thousands):


	Oil and Gas		PVR Coal		PVR Midstream		Corporate and Other			Consolidated
For the Nine Months Ended September 30, 2006:
Revenues	$	178,283	$	83,115	$	307,006	$	46		$	568,450
Operating costs and expenses		63,362		12,922		272,265		10,071			358,620
Depreciation, depletion and amortization		38,755		15,050		12,451		325			66,581

Operating income (loss)	$	76,166	$	55,143	$	22,290	$	(10,350	)	$	143,249

For the Nine Months Ended September 30, 2005:
Revenues	$	147,720	$	69,428	$	214,775	$	645		$	432,568
Operating costs and expenses		58,912		10,793		193,941		8,181			271,827
Impairment of oil and gas properties		3,488		—		—		—			3,488
Depreciation, depletion and amortization		33,777		13,440		8,797		310			56,324

Operating income (loss)	$	51,543	$	45,195	$	12,037	$	(7,846	)	$	100,929

Oil and Gas Segment

During the nine months ended September 30, 2006, our oil and gas production increased by 12 percent to 22.7 Bcfe. High commodity prices also contributed significantly to our financial results. Natural gas prices have been volatile in the last few years, with the NYMEX futures market trading at record price levels for natural gas. Our realized natural gas price for the nine months ended September 30, 2006 was $7.63 per thousand cubic feet (“Mcf”), an increase of five percent from $7.28 per Mcf for the nine months ended September 30, 2005. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices. The use of this risk management strategy has resulted in lower price realizations compared to physical sale prices in the last several years.

The following table summarizes total natural gas, oil and condensate production and total natural gas, oil and condensate revenues by region:


	Natural Gas, Oil and Condensate Production				Natural Gas, Oil and Condensate Revenues
	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,				Nine Months Ended September 30,
Region	2006	2005	2006	2005	2006		2005		2006		2005
	(Mmcfe)				(in thousands)
Appalachia	3,241	3,549	9,718	10,407	$	22,711	$	29,221	$	75,947	$	75,309
Mississippi	1,557	1,407	4,644	3,573		10,598		12,426		35,787		26,918
Gulf Coast	1,388	1,297	4,609	4,316		10,961		10,340		37,275		30,489
East Texas	1,182	634	3,084	1,910		8,790		5,453		23,737		14,423
Mid-continent	546	—	652	—		3,444		—		4,016		—

Total	7,914	6,887	22,707	20,206	$	56,504	$	57,440	$	176,762	$	147,139

In east Texas, we entered into a joint venture with GMX Resources, Inc. (NASDAQ: GMXR) in 2004 to drill development wells in the North Carthage Field in east Texas. Through September 30, 2006, 68 gross (46.1 net) wells were drilled on this acreage, and we estimate that a total of 80 to 100 wells could ultimately be drilled.

In Mississippi, 62 (61.6 net) successful Selma Chalk development wells were drilled during the nine months ended September 30, 2006 in the Company’s Baxterville, Gwinville and Maxie fields. A total of 85 wells (gross) are expected to be drilled in 2006. We plan to drill two horizontal Selma Chalk wells during the fourth quarter. A program is also planned for the fourth quarter to test down-spacing the Selma Chalk from 20-acre to 10-acre spacing, which, if successful, would add a significant number of drilling opportunities in our three Selma Chalk fields.

In the gulf coast region, we participated in the drilling of nine gross (4.1 net) exploratory wells during the nine months ended September 30, 2006. Two (0.4 net) of the wells were successful, five (2.1 net) of the wells were unsuccessful, and the remaining two (1.6 net) wells are under evaluation.

In the mid-continent region, we acquired approximately 42.7 Bcfe of net proved reserves in Oklahoma with the Crow Creek Acquisition in June 2006. We began development of the acquired properties and drilled seven gross (4.3 net) successful horizontal CBM wells and one gross (0.5 net) conventional well during the third quarter of 2006. Another horizontal CBM well (0.4 net) was drilled but plugged and abandoned.

In Appalachia, we continue to expand our CBM production and reserve base in through leasehold acquisitions and the use of a proprietary horizontal drilling technology. We drilled 17 gross (8.3 net) horizontal CBM development wells in Appalachia in the nine months ended September 30, 2006, and all were successful. Production has been temporarily affected by water disposal issues, which has resulted in shutting in or temporarily delaying the first production from nine horizontal patterns.

We drilled a total of 139 gross (104.9 net) wells during the nine months ended September 30, 2006, including 129 gross (100.5 net) development wells and 10 gross (4.4 net) exploratory wells. All but three gross (2.4 net) development wells were successful. Three exploratory wells (0.8 net) were successful, five exploratory wells (2.0 net) were not successful and two gross (1.6 net) exploratory wells are currently being tested. We have completed testing on three other exploratory wells that were under evaluation as of December 31, 2005 and have determined in the third quarter of 2006 that all three wells were unsuccessful. We wrote off $3.7 million of drilling costs in the third quarter of 2006 related to these wells.

PVR Coal Segment

In the nine months ended September 30, 2006, coal royalty revenues increased 20 percent, or $12.4 million, over the same period last year due to acquisitions, more coal being mined by PVR’s lessees and increasing coal prices. Tons produced by PVR’s lessees increased from 22.5 million tons in the nine months ended September 30, 2005 to 24.5 million tons in the nine months ended September 30, 2006, and average gross royalties per ton increased from $2.71 in the nine months ended September 30, 2005 to $3.00 in the nine months ended September 30, 2006. The Illinois Basin coal reserves that PVR acquired in July 2005 resulted in $3.7 million of coal royalty revenues in the nine months ended September 30, 2006. The May 2006 Huff Creek Acquisition resulted in $3.4 million of coal royalty revenues in the nine months ended September 30, 2006. Generally, as coal prices increase, average royalties per ton also increase because the vast majority of PVR’s lessees pay royalties based on the gross sales prices of the coal mined.

Coal services revenues increased to $4.3 million in the nine months ended September 30, 2006 from $3.9 million in the nine months ended September 30, 2005. PVR believes that these types of fee-based infrastructure assets provide good investment and cash flow opportunities, and it continues to look for additional investments of this type, as well as other primarily fee-based assets.

As of September 30, 2006, PVR’s primary coal reserves and coal infrastructure assets were located on the following properties:

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in central Appalachia, at properties in Buchanan, Lee and Wise Counties, Virginia; Floyd, Harlan, Knott and Letcher Counties, Kentucky; and Boone, Fayette, Kanawha, Lincoln, Logan, Raleigh and Wyoming Counties, West Virginia;

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in northern Appalachia, at properties in Barbour, Harrison, Lewis, Monongalia and Upshur Counties, West Virginia;

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in the Illinois Basin, at properties in Henderson and Webster Counties, Kentucky; and

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in the San Juan Basin, at properties in McKinley County, New Mexico.

The following table summarizes coal production and coal royalty revenues by property:


	Coal Production				Coal Royalty Revenues
	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,				Nine Months Ended September 30,
Property	2006	2005	2006	2005	2006		2005		2006		2005
	(tons in thousands)				(in thousands)
Central Appalachia	5,494	5,024	14,933	14,046	$	20,970	$	17,295	$	56,892	$	47,667
Northern Appalachia	1,306	1,501	3,929	4,158		1,894		2,062		5,746		5,890
Illinois Basin	550	731	1,891	731		1,055		1,164		3,666		1,164
San Juan Basin	1,432	1,275	3,714	3,561		2,693		2,218		6,984		6,200

Total	8,782	8,531	24,467	22,496	$	26,612	$	22,739	$	73,288	$	60,921

PVR Midstream Segment

The gross processing margin for PVR’s natural gas midstream operations increased from $31.1 million in the nine months ended September 30, 2005 to $50.2 million in the nine months ended September 30, 2006. This increase was due primarily to higher NGL prices and the contribution of the Transwestern Acquisition. Inlet volumes at PVR’s gas processing plants and gathering systems were 144 million cubic feet (“MMcf”) per day in the nine months ended September 30, 2006, an increase over 126 MMcf per day in the nine months ended September 30, 2005, primarily due to additional well connections in the area. As part of its risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See the tables in “—Results of Operations—PVR Midstream Segment—Expenses” for the effects of PVR’s derivative program on gross processing margin.

Our natural gas midstream assets are primarily located in the mid-continent area of Oklahoma and the panhandle of Texas. The following table sets forth information regarding our natural gas midstream assets as of September 30, 2006:


				Nine Months Ended September 30, 2006
		Approximate Length (Miles)	Current Processing Capacity (Mmcfd)	Average System Throughput (Mmcfd)		Utilization of Processing Capacity (%)
Beaver/Perryton System	Gathering pipelines and
	processing facility	1,188	100	97.4		97.4	%
Crescent System	Gathering pipelines and
	processing facility	1,675	28	18.5		66.1	%
Hamlin System	Gathering pipelines and
	processing facility	517	10	6.8		68.0	%
Arkoma System	Gathering pipelines	78	—	14.9	(1)
North Canadian System	Gathering pipelines	115	—	6.8	(1)

		3,573	138	144.4

(1)	Gathering only volumes.

Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management.

Reserves

The estimates of oil and gas reserves are the single most critical estimate included in our consolidated financial statements. Reserve estimates become the basis for determining depletive write-off rates, recoverability of historical cost investments and the fair value of properties subject to potential impairments. There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities, including projecting the total quantities in place, future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are less precise than those of producing properties due to the lack of a production history. Accordingly, these estimates are subject to change as additional information becomes available.

Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those quantities that require additional capital investment through drilling or well recompletion techniques.

There are several factors which could change our estimates of oil and gas reserves. Significant rises or declines in product prices could lead to changes in the amount of reserves as production activities become more or less economical. An additional factor that could result in a change of recorded reserves is the reservoir decline rates differing from those assumed when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates.

Depreciation and depletion of oil and gas producing properties is determined by the units-of-production method and could change with revisions to estimated proved recoverable reserves.

Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. PVR’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively.

Oil and Gas Revenues

Revenues associated with sales of natural gas, crude oil, condensate and NGLs are recorded when title passes to the customer. Natural gas sales revenues from properties in which we have an interest with other producers are recognized on the basis of our net working interest (“entitlement” method of accounting). Natural gas imbalances occur when we sell more or less than our entitled ownership percentage of total natural gas production. Any amount received in excess of our share is treated as deferred revenues. If we take less than we are entitled to take, the under-delivery is recorded as a receivable. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, accruals for revenues and accounts receivable are made based on estimates of our share of production, particularly from properties that are operated by our partners. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. Any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized. Approximately 54 percent of natural gas and oil and condensate revenues for the nine months ended September 30, 2006 related to three customers.

Natural Gas Midstream Revenues

Revenues from the sale of NGLs and residue gas are recognized when the NGLs and residue gas produced at PVR’s gas processing plants are sold. Gathering and transportation revenues are recognized based upon actual volumes delivered. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues may take up to 30 days following the month of production. Therefore, accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable are made based on estimates of natural gas purchased and NGLs and natural gas sold, and our financial results include estimates of production and revenues for the period of actual production. Any differences, which we do not expect to be significant, between the actual amounts ultimately received or paid and the original estimates are recorded in the period they become finalized. Approximately 40 percent of natural gas midstream revenues for the nine months ended September 30, 2006 related to two customers.

Coal Royalty Revenues

Coal royalty revenues are recognized on the basis of tons of coal sold by PVR’s lessees and the corresponding revenues from those sales. Since PVR does not operate any mines, it does not have access to actual production and revenue information until approximately 30 days following the month of production. Therefore, the financial results of PVR include estimated revenues and accounts receivable for the month of production. Any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

Derivative Activities

We and PVR have historically entered into derivative financial instruments that would qualify for hedge accounting under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Hedge accounting affects the timing of revenue recognition and cost of midstream gas purchased in our consolidated statements of income, as a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred until the related hedged transaction occurs. The results reflected in our consolidated statements of income are based on the actual settlements with the counterparty. We include this gain or loss in oil and gas revenues, natural gas midstream revenues or cost of midstream gas purchased, depending on the commodity. As a result of price volatility resulting from the 2005 hurricane season, a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting. Because of this non-qualification and to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). Because we no longer use hedge accounting for our commodity derivatives, we could experience significant changes in the estimate of derivative gain or loss recognized in revenues and cost of midstream gas purchased due to swings in the value of these contracts. These fluctuations could be significant in a volatile pricing environment.

The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in our future earnings through 2008 as the original hedged transactions occur. This change in reporting will have no impact on our reported cash flows, although our future results of operations will be affected by mark-to-market gains and losses which fluctuate with changes in oil and gas prices.

Oil and Gas Properties

We use the successful efforts method to account for our oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. Geological and geophysical costs, delay rentals and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We will carry the costs of an exploratory well as an asset if the well found a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its

economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis.

A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At September 30, 2006, the costs attributable to unproved properties were approximately $100.5 million. We regularly assess on a property-by-property basis the impairment of individual unproved properties whose acquisition costs are relatively significant. Unproved properties whose acquisition costs are not relatively significant are amortized in the aggregate over the lesser of five years or the average remaining lease term. As exploration work progresses and the reserves on relatively significant properties are proven, capitalized costs of these properties will be subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be expensed. The timing of any writedowns of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, the Company and PVR operate with independent capital structures. The Company and PVR have separate credit facilities, and neither entity guarantees the debt of the other. Since PVR’s inception in 2001, with the exception of cash distributions paid to us by PVR, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and issuance of new PVR units. We expect that our cash needs and the cash needs of PVR will continue to be met independently of each other with a combination of these funding sources.

Summarized cash flow statements for nine months ended September 30, 2006 and 2005, consolidating our combined segments, are set forth below (in thousands):


For the nine months ended September 30, 2006	Oil and Gas & Corporate			PVR Coal and PVR Midstream (1)			Consolidated
Cash flows from operating activities:
Net income contribution	$	52,012		$	13,194		$	65,206
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		74,362			58,410			132,772
Net change in operating assets and liabilities		(4,737	)		3,820			(917	)

Net cash provided by operating activities		121,637			75,424			197,061
Net cash used in investing activities		(242,767	)		(108,446	)		(351,213	)
Net cash provided by financing activities		117,085			23,540			140,625

Net increase (decrease) in cash and cash equivalents	$	(4,045	)	$	(9,482	)	$	(13,527	)


For the nine months ended September 30, 2005	Oil and Gas & Corporate			PVR Coal and PVR Midstream (1)			Consolidated
Cash flows from operating activities:
Net income contribution	$	25,919		$	8,758		$	34,677
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		72,566			55,887			128,453
Net change in operating assets and liabilities		(21,668	)		7,045			(14,623	)

Net cash provided by operating activities		76,816			71,691			148,507
Net cash used in investing activities		(102,960	)		(299,732	)		(402,692	)
Net cash provided by financing activities		21,459			229,261			250,720

Net increase in cash and cash equivalents	$	(4,685	)	$	1,220		$	(3,465	)

(1)	Net income, adjustments to reconcile net income to net cash provided by operating activities and net change in operating assets and liabilities for PVR segments have been adjusted for minority interest and income taxes.

Cash Flows

Except where noted, the following discussion of cash flows relates to our consolidated results.

From the nine months ended September 30, 2005 to the nine months ended September 30, 2006, the oil and gas segment’s and corporate’s net cash provided by operating activities increased primarily due to increased natural gas production and increased prices received for natural gas and crude oil. Cash provided by operating activities of the PVR coal and PVR midstream segments increased primarily due to an increase in average royalties per ton resulting from higher coal sales prices and accretive cash flows from the natural gas midstream business, which PVR acquired in March 2005.

Capital expenditures totaled $388.7 million for the nine months ended September 30, 2006 compared with $435.8 million for the nine months ended September 30, 2005. The following table sets forth capital expenditures by segment made during the periods indicated:


	Nine Months Ended September 30,
	2006		2005
	(in thousands)
Oil and gas
Proved property acquisitions	$	72,531	$	—
Development drilling		116,046		76,797
Exploration drilling		23,710		13,681
Seismic		4,945		6,876
Lease acquisition and other (1)		16,998		20,303
Pipeline, gathering, facilities		11,929		3,858

Total		246,159		121,515

Coal
Acquisitions (2)		66,580		91,078
Expansion capital expenditures		13,833		—
Other property and equipment expenditures		69		4,896

Total		80,482		95,974

Natural gas midstream
Acquisitions, net of cash acquired		14,626		199,091
Expansion capital expenditures		5,926		—
Other property and equipment expenditures		7,317		4,719

Total		27,869		203,810

Other		2,223		150

Total capital expenditures	$	356,733	$	421,449

(1)	Lease acquisition excludes total non-cash expenditures of $32.8 million in the nine months ended September 30, 2006 related to deferred taxes in the Crow Creek Acquisition.

(2)

Amount in 2005 excludes noncash expenditure of $11.1 million to acquire coal reserves in Kentucky in exchange for $10.4 million of equity issued in the form of PVR common units and $0.7 million of liabilities assumed. Amount in 2005 also includes noncash portion of another coal reserve acquisition in which PVR assumed $3.3 million of deferred income.

We are committed to expanding our oil and gas operations over the next several years through a combination of development, exploration and acquisition of new properties. We have a portfolio of assets which balances relatively low risk, moderate return development projects in Appalachia, Mississippi, east Texas and the mid-continent with relatively moderate risk, potentially higher return development projects and exploration prospects in south Texas and south Louisiana.

We expect oil and gas segment capital expenditures, including previously completed proved property acquisitions, to be between $320 million and $335 million in 2006. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on industry conditions and the availability of capital. We believe our cash flow from operations and sources of debt financing are sufficient to fund our 2006 planned oil and gas capital expenditures program.

During the nine months ended September 30, 2006, PVR made aggregate capital expenditures of $108.4 million for coal reserve acquisitions, coal loadout facility construction and natural gas midstream gathering systems. PVR’s cash flows from operations and its revolving credit facility were used to fund coal and natural gas midstream capital expenditures, including two acquisitions, for the nine months ended September 30, 2006. To finance its acquisitions in the nine months ended September 30, 2005, PVR borrowed $140.2 million, net of repayments, received proceeds of $126.5 million from the sale of its common units in a public offering and received a $2.8 million contribution from its general partner, which is a wholly owned subsidiary of the Company.

We borrowed $101.0 million under our revolving credit facility, net of repayments, in the nine months ended September 30, 2006 compared to borrowings, net of repayments, of $13.0 million for the nine months ended September 30, 2005. We also received cash distributions from PVR of $19.8 million in the nine months ended September 30, 2006 compared to $15.6 million in the same period last year. Funds from both of these sources were primarily used for capital expenditures.

In October 2006, PVR announced a $0.40 per unit quarterly distribution for the three months ended September 30, 2006, or $1.60 per unit on an annualized basis. The distribution will be paid on November 14, 2006 to unitholders of record at the close of business on November 3, 2006. As a result of the 15.6 million limited partner units and the incentive distribution rights we own as PVR’s general partner, cash distributions we receive from PVR are expected to be approximately $27 million in 2006 compared to $21 million in 2005.

Long-Term Debt

Revolving Credit Facility. We have a revolving credit facility (the “Revolver”) that is secured by a portion of our proved oil and gas reserves and matures in December 2010. Effective November 1, 2006, we amended our credity facility to increase the commitment from $200 million to $300 million and the borrowing base from $300 million to $400 million. We had $180 million outstanding under the Revolver as of September 30, 2006. The Revolver is governed by a borrowing base calculation and is redetermined semi-annually. We have the option to elect interest at (i) the London Inter Bank Offering Rate (“LIBOR”) plus a Eurodollar margin ranging from 1.00 to 1.75 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus a margin up to 0.50 percent. The Revolver allows for the issuance of up to $20 million of letters of credit.

Effective August 2, 2006, we entered into interest rate swap agreements to swap $50 million of outstanding borrowings under our Revolver from a variable rate to a weighted average fixed rate of 5.34 percent plus the applicable margin. The interest rate swap agreement is accounted for as a cash flow hedge in accordance with SFAS No. 133.

The financial covenants under the Revolver require us to maintain levels of debt-to-earnings and impose dividend limitation restrictions. The Revolver contains various other covenants that limit, among other things, our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. As of September 30, 2006, we were in compliance with all of our covenants under the Revolver.

Line of Credit. We have a $10.0 million line of credit with a financial institution, which had no borrowings against it as of September 30, 2006. The line of credit is effective through June 2007 and is renewable annually. We increased the line of credit from $5.0 million to $10.0 million in June 2006. We have an option to elect either a fixed rate LIBOR loan, a floating rate LIBOR loan or a base rate (as determined by the financial institution) loan.

PVR Revolving Credit Facility. As of September 30, 2006, PVR had $251.8 million outstanding under its $300 million revolving credit facility (the “PVR Revolver”) that matures in March 2010. The PVR Revolver is available for general PVR purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. PVR has a one-time option to expand the PVR Revolver by $150 million upon receipt by the credit facility’s administrative agent of commitments from one or more lenders. The PVR Revolver’s interest rate fluctuates based on PVR’s ratio of total indebtedness to EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.00 percent if PVR selects the base rate borrowing option under the credit agreement or at a rate derived from LIBOR, plus an applicable margin ranging from 1.00 percent to 2.00 percent if PVR selects the LIBOR-based borrowing option.

The financial covenants under the PVR Revolver require PVR to maintain specified levels of debt to consolidated EBITDA and consolidated EBITDA to interest. The financial covenants restricted PVR’s additional borrowing capacity under the PVR Revolver to approximately $126.2 million as of September 30, 2006. At the current $300 million limit on the PVR Revolver, and given the outstanding balance of $250.2 million, net of $1.6 million of letters of credit, PVR could borrow up to $46.6 million without exercising its one-time option to expand the PVR Revolver. In order to utilize the full extent of the $126.2 million borrowing capacity, PVR would need to exercise its one-time option to expand the PVR Revolver by $150 million. The PVR Revolver prohibits PVR from making certain distributions, including distributions to unitholders if any default or event of default occurs or would result from such unitholder distributions. In addition, the PVR Revolver contains various covenants that limit, among other things, PVR’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of PVR’s business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in PVR’s subsidiaries. As of September 30, 2006, PVR was in compliance with all of its covenants under the PVR Revolver.

PVR Senior Unsecured Notes. As of September 30, 2006, PVR owed $74.8 million under its senior unsecured notes (the “PVR Notes”). The PVR Notes bear interest at a fixed rate of 6.02 percent and mature over a ten-year period ending in March 2013, with semi-annual principal and interest payments. The PVR Notes are equal in right of payment with all of PVR’s other unsecured indebtedness, including the PVR Revolver. The PVR Notes require PVR to obtain an annual confirmation of its credit rating, with a 1.00 percent increase in the interest rate payable on the PVR Notes in the event its credit rating falls below investment grade. In March 2006, PVR’s investment grade credit rating was confirmed by Dominion Bond Rating Services. The PVR Notes contain various covenants similar to those contained in the PVR Revolver. As of September 30, 2006, PVR was in compliance with all of its covenants under the PVR Notes.

Interest Rate Swaps. In September 2005, PVR entered into interest rate swap agreements (the “PVR Revolver Swaps”) with notional amounts totaling $60 million to establish fixed rates on the LIBOR-based portion of the outstanding balance of the PVR Revolver until March 2010. PVR pays a weighted average fixed rate of 4.22 percent on the notional amount plus the applicable margin, and the counterparties pay a variable rate equal to the three-month LIBOR. Settlements on the PVR Revolver Swaps are recorded as interest expense. The PVR Revolver Swaps were designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings in interest expense. After considering the applicable margin of 1.25 percent in effect as of September 30, 2006, the total interest rate on the $60 million portion of PVR Revolver borrowings covered by the PVR Revolver Swaps was 5.47 percent at September 30, 2006.

Future Capital Needs and Commitments

In the oil and gas segment, we expect to continue to execute a program dominated by relatively low risk, moderate return development drilling and, to a lesser extent, higher risk, higher return exploration drilling, supplemented periodically with acquisitions.

In 2006, we anticipate making oil and gas segment capital expenditures, including previously completed proved property acquisitions, of between $320 and $335 million. These expenditures are expected to be funded primarily by operating cash flow and from the Revolver as needed.

Part of PVR’s strategy is to make acquisitions which increase cash available for distribution to its unitholders. Long-term cash requirements for asset acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities. PVR’s ability to make these acquisitions in the future will depend in part on the availability of debt financing and on its ability to periodically use equity financing through the issuance of new common units, which will depend on various factors, including prevailing market conditions, interest rates and its financial condition and credit rating at the time.

In 2006, PVR anticipates making capital expenditures, excluding acquisitions, of $16 to $18 million for coal services projects and other property and equipment and $19 to $21 million for natural gas midstream system expansion projects. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities, borrowings under the PVR Revolver under which it had $126.2 million of borrowing capacity as of September 30, 2006 and potentially with proceeds from the issuance of additional equity. PVR believes that it

will continue to have adequate liquidity to fund future recurring operating and investing activities. Short-term cash requirements, such as operating expenses and quarterly distributions to its general partner and unitholders, are expected to be funded through PVR’s operating cash flows.

Results of Operations

Selected Financial Data—Consolidated


	Three Months Ended September 30,				Nine Months Ended September 30,
	2006		2005		2006		2005
	(in thousands, except per share data)
Revenues	$	188,393	$	186,359	$	568,450	$	432,568
Expenses		143,749		139,551		425,201		331,639

Operating income	$	44,644	$	46,808	$	143,249	$	100,929

Net income	$	22,881	$	19,990	$	65,206	$	34,677
Earnings per share, basic	$	1.22	$	1.08	$	3.49	$	1.87
Earnings per share, diluted	$	1.21	$	1.07	$	3.46	$	1.85
Cash flows provided by operating activities	$	47,161	$	63,841	$	197,061	$	148,507

The increase in net income for the nine months ended September 30, 2006 compared to the same period in 2005 was primarily attributable to a $46.1 million increase in operating income, and a $22.6 million increase in derivative gains, partially offset by increased interest expense and the related net increase in income tax expense. The increase in net income for the three months ended September 30, 2006 compared to the same period in 2005 was primarily attributable to a $1.6 million increase in operating income and a $14.4 million increase in derivative gains, partially offset by increases in interest expense and income tax expense. Operating income increased in the three months and nine months ended September 30, 2006 primarily due to increased natural gas revenues as a result of record oil and gas production volumes, along with increased operating income contributions from our ownership interest in PVR, which is reported under the PVR coal and PVR midstream segments.

The assets, liabilities and earnings of PVR are fully consolidated in our financial statements, with the public unitholders’ interest (59 percent, after effect of incentive distribution rights, as of September 30, 2006) reflected as a minority interest.

Oil and Gas Segment

Operations and Financial Summary – Oil and Gas Segment

Three Months Ended September 30, 2006 Compared with Three Months Ended September 30, 2005


	Three Months Ended September 30,				% Change		Three Months Ended September 30,
	2006		2005		% Change		2006		2005
	(in thousands, except as noted)						(per Mcfe) (1)
Production
Natural gas (million cubic feet (“Mmcf”))		7,332		6,473	13	%
Oil and condensate (thousand barrels)		97		69	41	%
Total production (Mmcfe)		7,914		6,887	15	%
Revenues
Natural gas	$	50,540	$	54,071	-7	%	$	6.89	$	8.35
Oil and condensate		5,954		3,369	77	%		61.38		48.83
Other income		402		405	-1	%

Total revenues		56,896		57,845	-2	%		7.19		8.40

Expenses
Operating		7,882		4,553	73	%		1.00		0.66
Taxes other than income		1,750		3,424	-49	%		0.22		0.50
General and administrative		3,181		1,966	62	%		0.40		0.29

Production costs		12,813		9,943	29	%		1.62		1.44
Exploration		12,660		5,960	112	%		1.60		0.87
Impairment of oil and gas properties		—		3,488	-100	%		—		0.51
Depreciation, depletion and amortization		13,365		11,433	17	%		1.69		1.66

Total expenses		38,838		30,824	26	%		4.91		4.48

Operating income	$	18,058	$	27,021	-33	%	$	2.28	$	3.92

(1)	Natural gas revenues are shown per Mcf, oil and condensate revenues are shown per barrel (“Bbl”), and all other amounts are shown per thousand cubic feet equivalent (“Mcfe”).

Production. The increase in production was primarily due to new production from increased drilling, including the horizontal CBM play in Appalachia, the Cotton Valley play in east Texas, the Selma Chalk development play in Mississippi and the success of our Fannett exploration prospect in south Texas drilled in the second quarter of 2005. Production increases were partially offset by normal field declines.

Revenues. Approximately 93 percent and 94 percent of production in the three months ended September 30, 2006 and 2005 was natural gas. Increased natural gas production resulted in an increase of approximately $7.2 million in natural gas revenues. Decreased realized prices for natural gas resulted in a decrease of approximately $10.7 million in natural gas revenues. Increased oil and condensate production accounted for approximately $1.4 million, or 53 percent, of the increase in oil and condensate revenues. Increased realized prices for oil and condensate accounted for approximately $1.2 million, or 47 percent, of the increase in oil and condensate revenues.

Natural gas, oil and condensate revenues are derived from the sale of our oil and gas production, which is net of the effects of the settlement of derivative contracts that follow hedge accounting. Settlement of our derivative contracts that do not follow hedge accounting has no effect on our reported revenues. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes.

recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions occur. This change in reporting will have no impact on our reported cash flows, although future results of operations will be affected by mark-to-market gains and losses which fluctuate with changes in oil and gas prices.

The following table shows a summary of the effects of derivative activities on revenues and realized prices for the three months ended September 30, 2006 and 2005:


	Three Months Ended September 30,
	2006			2005			2006			2005
	(in thousands)						(per Mcf)
Natural gas revenue, as reported	$	50,540		$	54,071		$	6.89		$	8.35
Derivatives (gains) losses included in natural gas revenues		(663	)		2,551			(0.09	)		0.39

Natural gas revenue before impact of derivatives		49,877			56,622			6.80			8.75
Cash settlements on natural gas derivatives		3,148			(2,551	)		0.43			(0.39	)

Natural gas revenues, adjusted for derivatives	$	53,025		$	54,071		$	7.23		$	8.35


								(per Bbl)
Crude oil revenue, as reported	$	5,954		$	3,369		$	61.38		$	48.83
Derivatives (gains) losses included in oil and condensate revenues		103			283			1.06			4.10

Oil and condensate revenue before impact of derivatives		6,057			3,652			62.44			52.93
Cash settlements on crude oil derivatives		(19	)		(283	)		(0.20	)		(4.10	)

Oil and condensate revenues, adjusted for derivatives	$	6,038		$	3,369		$	62.25		$	48.83

Expenses. The oil and gas segment’s aggregate operating costs and expenses in the three months ended September 30, 2006 increased due to increases in operating expenses, general and administrative expenses, exploration expense and depreciation, depletion and amortization (“DD&A”) expense. This increase was partially offset by decreases in taxes other than income and impairment of oil and gas properties.

Operating expenses increased primarily due to additional compressor rentals at fields with increased production, downhole maintenance charges associated with horizontal CBM wells in Appalachia and Selma Chalk wells in Mississippi, increased surface repair costs and increased gathering fees related to horizontal CBM and Cotton Valley wells.

Taxes other than income decreased due to lower natural gas prices and a severance tax refund related to production in the Cotton Valley play and property tax adjustments in West Virginia.

General and administrative expenses increased primarily due to increased payroll costs as a result of wage increases and new personnel and consulting fees related to the Crow Creek Acquisition.

Exploration expenses for the three months ended September 30, 2006 and 2005 consisted of the following:


	Three Months Ended September 30,
	2006		2005
	(in thousands)
Dry hole costs	$	6,697	$	2,010
Seismic		1,425		755
Unproved leasehold		2,898		925
Other		1,640		2,270

Total	$	12,660	$	5,960

Exploration expenses for the three months ended September 30, 2006 increased primarily due to an increase in dry hole costs related to the write off of six exploratory wells in the third quarter of 2006, an increase in unproved leasehold due to the amortization of unproved property pools in 2006 and an increase in seismic costs due to the timing of seismic data purchases. These increases were partially offset by a decrease in delay rentals.

We recorded an impairment charge in the third quarter of 2005 related to a change in estimate of the reserve base of a field in southeast Texas.

Oil and gas DD&A expenses increased due to the 15 percent increase in equivalent production and as a result of higher average depletion rates. The average depletion rate increased from $1.66 per Mcfe for the third quarter of 2005 to $1.69 per Mcfe for the third quarter of 2006 as a result of a greater percentage of production coming from relatively higher cost horizontal CBM and Cotton Valley wells and general price inflation for equipment, services and tubulars used for drilling and development.

Nine Months Ended September 30, 2006 Compared with Nine Months Ended September 30, 2005


	Nine Months Ended September 30,				% Change		Nine Months Ended September 30,
	2006		2005		% Change		2006		2005
		(in thousands, except as noted)						(per Mcfe) (1)
Production
Natural gas (Mmcf)		21,009		18,826	12	%
Oil and condensate (thousand barrels)		283		230	23	%
Total production (Mmcfe)		22,707		20,206	12	%

Revenues
Natural gas	$	160,384	$	137,011	17	%	$	7.63	$	7.28
Oil and condensate		16,378		10,128	62	%		57.87		44.03
Other income		1,521		581	162	%

Total revenues		178,283		147,720	21	%		7.85		7.31

Expenses
Operating		19,490		11,629	68	%		0.86		0.58
Taxes other than income		9,162		9,484	-3	%		0.40		0.47
General and administrative		8,649		6,249	38	%		0.38		0.31

Production costs		37,301		27,362	36	%		1.64		1.35
Exploration		26,061		31,550	-17	%		1.15		1.56
Impairment of oil and gas properties		—		3,488	-100	%		—		0.17
Depreciation, depletion and amortization		38,755		33,777	15	%		1.71		1.67

Total expenses		102,117		96,177	6	%		4.50		4.76

Operating income	$	76,166	$	51,543	48	%	$	3.35	$	2.55

(1)	Natural gas revenues are shown per Mcf, oil and condensate revenues are shown per Bbl, and all other amounts are shown per Mcfe.

Revenues. Approximately 93 percent and 93 percent of production in the nine months ended September 30, 2006 and 2005 was natural gas. Increased natural gas production accounted for approximately $15.9 million, or 68 percent, of the increase in natural gas revenues. Increased realized prices for natural gas accounted for approximately $7.5 million, or 32 percent, of the increase in natural gas revenues. Increased oil and condensate production accounted for approximately $2.3 million, or 37 percent, of the increase in oil and condensate revenues. Increased realized prices for oil and condensate accounted for approximately $3.9 million, or 63 percent, of the increase in oil and condensate revenues.

As a result of price volatility resulting from the 2005 hurricane season, a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting. Because of this non-qualification and to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions occur. This change in reporting will have no impact on our reported cash flows, although future results of operations will be affected by mark-to-market gains and losses which fluctuate with changes in oil and gas prices.

The following table shows a summary of the effects of derivative activities on revenues and realized prices for the nine months ended September 30, 2006 and 2005:


	Nine Months Ended September 30,
	2006			2005			2006			2005
	(in thousands)						(per Mcf)
Natural gas revenue, as reported	$	160,384		$	137,011		$	7.63		$	7.28
Derivatives (gains) losses included in natural gas revenues		(247	)		3,177			(0.01	)		0.17

Natural gas revenue before impact of derivatives		160,137			140,188			7.62			7.45
Cash settlements on natural gas derivatives		5,181			(3,177	)		0.25			(0.17	)

Natural gas revenues, adjusted for derivatives	$	165,318		$	137,011		$	7.87		$	7.28


								(per Bbl)
Crude oil revenue, as reported	$	16,378		$	10,128		$	57.87		$	44.03
Derivatives (gains) losses included in oil and condensate revenues		333			631			1.18			2.74

Oil and condensate revenue before impact of derivatives		16,711			10,759			59.05			46.78
Cash settlements on crude oil derivatives		(209	)		(631	)		(0.74	)		(2.74	)

Oil and condensate revenues, adjusted for derivatives	$	16,502		$	10,128		$	58.31		$	44.03

Expenses. The oil and gas segment’s aggregate operating costs and expenses in the nine months ended September 30, 2006 increased due to increases in operating expenses, general and administrative expenses and DD&A. These increases were offset by decreases in exploration expense and impairment of oil and gas properties.

Taxes other than income decreased due to a severance tax refund related to production in the Cotton Valley play and property tax adjustments in West Virginia. This decrease was offset by higher severance taxes as a result of increased production and higher oil and gas prices.

General and administrative expenses increased primarily due to increased payroll costs as a result of wage increases and new personnel and consulting fees related to the Crow Creek Acquisition.

Exploration expenses for the nine months ended September 30, 2006 and 2005 consisted of the following:


	Nine Months Ended September 30,
	2006		2005
	(in thousands)
Dry hole costs	$	12,533	$	7,874
Seismic		5,064		6,752
Unproved leasehold		5,406		13,977
Other		3,058		2,947

Total	$	26,061	$	31,550

Exploration expenses for the nine months ended September 30, 2006 decreased primarily due to unproved leasehold and dry hole costs related to an exploratory well in south Texas that was determined to be unsuccessful in the second quarter of 2005. There were offsetting increases in dry hole costs due to the write-off of exploratory wells and in unproved leasehold due to the amortization of unproved property pools in 2006. The timing of seismic data purchases in the nine months ended September 30, 2006 caused seismic expenses to decrease compared to the nine months ended September 30, 2005.

We recorded an impairment charge in the third quarter of 2005 related to a change in estimate of the reserve base of a field in southeast Texas.

Oil and gas DD&A expenses increased due to the 12 percent increase in equivalent production and as a result of higher average depletion rates. The average depletion rate increased from $1.67 per Mcfe for the nine months ended September 30, 2005 to $1.71 per Mcfe for the nine months ended September 30, 2006 as a result of a greater percentage of production coming from relatively higher cost horizontal CBM and Cotton Valley wells and general price inflation for equipment, services and tubulars used for drilling and development.

PVR Coal Segment

Operations and Financial Summary – PVR Coal Segment

Three Months Ended September 30, 2006 Compared with Three Months Ended September 30, 2005


	Three Months Ended September 30,				% Change
	2006		2005		% Change
Financial Highlights		(in thousands, except as noted)

Revenues
Coal royalties	$	26,612	$	22,739	17	%
Coal services		1,515		1,261	20	%
Other		1,763		1,923	(8	%)

Total revenues		29,890		25,923	15	%

Expenses
Operating		3,340		1,931	73	%
Taxes other than income		154		219	(30	%)
General and administrative		2,097		1,917	9	%
Depreciation, depletion and amortization		5,551		5,257	6	%

Total expenses		11,142		9,324	19	%

Operating income	$	18,748	$	16,599	13	%

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,782		8,531	3	%
Average royalty per ton ($/ton)	$	3.03	$	2.67	14	%

Revenues. Coal royalty revenues increased due to a higher average royalty per ton and increased production. The average royalty per ton increased to $3.03 in the third quarter of 2006 from $2.67 in the third quarter of 2005. The increase in the average royalty per ton was primarily due to a greater percentage of coal being produced from certain price-sensitive leases and stronger market conditions for coal resulting in higher prices. Coal production by PVR’s lessees increased primarily due to production on the central Appalachian property due to the Huff Creek Acquisition in May 2006.

Expenses. Operating expenses increased due to an increase in production by lessees on PVR’s subleased properties, including a subleased central Appalachian property acquired in the Huff Creek Acquisition in May 2006. Fluctuations in production on subleased properties have a direct impact on royalty expense. The increase in DD&A expense was due to an increase in production and a higher depletion rate on recently acquired reserves.

Nine Months Ended September 30, 2006 Compared with Nine Months Ended September 30, 2005


	Nine Months Ended September 30,				% Change
	2006		2005		% Change
Financial Highlights		(in thousands, except as noted)

Revenues
Coal royalties	$	73,288	$	60,921	20	%
Coal services		4,345		3,869	12	%
Other		5,482		4,638	18	%

Total revenues		83,115		69,428	20	%

Expenses
Operating		5,561		4,104	36	%
Taxes other than income		565		727	(22	%)
General and administrative		6,796		5,962	14	%
Depreciation, depletion and amortization		15,050		13,440	12	%

Total expenses		27,972		24,233	15	%

Operating income	$	55,143	$	45,195	22	%

Operating Statistics
Royalty coal tons produced by lessees (tons in millions)		24,467		22,496	9	%
Average royalty per ton ($/ton)	$	3.00	$	2.71	11	%

Revenues. Coal royalty revenues increased due to a higher average royalty per ton and increased production. The average royalty per ton increased to $3.00 in the nine months ended September 30, 2006 from $2.71 in the nine months ended September 30, 2005. The increase in the average royalty per ton was primarily due to a greater percentage of coal being produced from certain price-sensitive leases and stronger market conditions for coal resulting in higher prices. Coal production by PVR’s lessees increased primarily due to production on PVR’s Illinois Basin property, which PVR acquired in the third quarter of 2005, and production on PVR’s central Appalachian property due to the Huff Creek Acquisition in May 2006.

Coal services revenues increased primarily due to increased equity earnings from PVR’s coal handling joint venture and increased revenues from coal handling facilities that processed higher volumes. Coal services revenues are included in other revenues on the consolidated statements of income.

Other revenues increased primarily due to the following factors. In the nine months ended September 30, 2006 and 2005, PVR received approximately $1.3 million and $0.3 million in revenues for the management of certain coal properties. In the nine months ended September 30, 2006, PVR recognized approximately $0.7 million of forfeiture income from lessees with rolling recoupment periods. There was virtually no forfeiture income in the same period of 2005. In the nine months ended September 30, 2006 and 2005, PVR recognized approximately $0.6 million and $0.2 million in railcar rental income related to railcars purchased in June 2005. In the nine months ended September 30, 2006 and 2005, PVR recognized approximately $1.3 million and $1.0 million of wheelage fees, primarily as a result of an April 2005 acquisition. In the nine months ended September 30, 2005, PVR received $1.5 million from the sale of a bankruptcy claim filed against a former lessee in 2004 for lost future rents.

Expenses. Operating expenses increased due to production on PVR’s subleased central Appalachian property acquired in the Huff Creek Acquisition in May 2006. This increase was partially offset by a decrease in production from other subleased properties primarily resulting from the movement of longwall mining operations at one of these properties. Fluctuations in production on subleased properties have a direct impact on royalty expense. General and administrative expenses increased due to absorbing operations related to 2005 and 2006 acquisitions,

increased professional fees and payroll costs relating to evaluating acquisition opportunities and increased reimbursement to the general partner for shared corporate overhead costs. DD&A expense increased due to the increase in production and a higher depletion rate on recently acquired reserves.

PVR Midstream Segment

Operations and Financial Summary – PVR Midstream Segment

Three Months Ended September 30, 2006 Compared with Three Months Ended September 30, 2005


	Three Months Ended September 30,				% Change
	2006		2005		% Change
Financial Highlights		(in thousands, except as noted)

Revenues
Residue gas	$	62,408	$	70,399	(11	%)
Natural gas liquids		35,363		29,240	21	%
Condensate		2,323		2,022	15	%
Gathering and transportation fees		715		279	156	%

Total natural gas midstream revenues		100,809		101,940	(1	%)
Marketing revenue, net		795		543	46	%

Total revenues		101,604		102,483	(1	%)

Operating costs and expenses
Cost of gas purchased		80,272		87,812	(9	%)
Operating		3,038		2,657	14	%
Taxes other than income		329		340	(3	%)
General and administrative		2,504		1,873	34	%
Depreciation and amortization		4,313		3,902	11	%

Total operating expenses		90,456		96,584	(6	%)

Operating income	$	11,148	$	5,899	89	%

Operating Statistics
Inlet volumes (Bcf)		14,643		11,567	27	%
Midstream processing margin (1)	$	20,537	$	14,128	45	%

(1)	Midstream processing margin consists of total natural gas midstream revenues minus the cost of gas purchased.

Revenues. Revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from inlet volumes received, condensate collected and sold, gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants and the purchase and resale of natural gas not connected to PVR’s gathering systems and processing plants. The decrease in residue gas revenues was primarily a result of overall market decreases in natural gas prices. The increase in natural gas liquids revenues was primarily a result of an increase in average NGL prices from the third quarter of 2005 to the third quarter of 2006. Gathering and transportation fees increased due to the addition of pipeline by the June 2006 Transwestern Acquisition.

Expenses. Cost of gas purchased consisted of amounts payable to third-party producers for gas purchased under percentage of proceeds and keep-whole contracts. The decrease in the average purchase price for natural gas was a direct result of overall market decreases in natural gas prices. The following table shows a summary of the effects of derivative activities on midstream processing margin:


	Three Months Ended September 30,
	2006			2005
	(in thousands)
Midstream processing margin, as reported	$	20,537		$	14,128
Derivatives losses included in midstream processing margin		825			1,017

Midstream processing margin before impact of derivatives		21,362			15,145
Cash settlements on derivatives		(7,344	)		(2,052	)

Midstream processing margin, adjusted for derivatives	$	14,018		$	13,093

Operating expenses increased primarily due to rent and maintenance costs associated with additional compressors. General and administrative expenses increased primarily due to additional personnel added to support the business and recent acquisitions and increased reimbursement to PVR’s general partner for shared corporate overhead costs. DD&A expense increased due to depreciation on the pipeline acquired in the June 2006 Transwestern Acquisition and recent gathering system expansions.

Nine Months Ended September 30, 2006 Compared with Nine Months Ended September 30, 2005


	Nine Months Ended September 30,				% Change
	2006		2005 (1)		% Change
	(in thousands, except as noted)
Financial Highlights

Revenues
Residue gas	$	199,096	$	132,245	51	%
Natural gas liquids		97,591		74,235	31	%
Condensate		7,165		5,386	33	%
Gathering and transportation fees		1,488		1,485	0	%

Total natural gas midstream revenues		305,340		213,351	43	%
Marketing revenue, net		1,666		1,424	17	%

Total revenues		307,006		214,775	43	%

Operating costs and expenses
Cost of gas purchased		254,615		182,278	40	%
Operating		8,387		6,626	27	%
Taxes other than income		1,054		930	13	%
General and administrative		8,209		4,107	100	%
Depreciation and amortization		12,451		8,797	42	%

Total operating expenses		284,716		202,738	40	%

Operating income	$	22,290	$	12,037	85	%

Operating Statistics
Inlet volumes (Bcf)		39,431		26,963	46	%
Midstream processing margin (2)	$	50,725	$	31,073	63	%

(1)	Represents the results of operations of the PVR midstream segment since March 3, 2005, the closing date of the acquisition of Cantera Gas Resources, LLC (the “Cantera Acquisition”).

(2)	Midstream processing margin consists of total natural gas midstream revenues minus the cost of gas purchased.

Revenues. Revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from inlet volumes received, condensate collected and sold, gathering and other fees primarily from natural gas volumes connected to PVR’s gas processing plants and the purchase and resale of natural gas not connected to our gathering systems and processing plants. In addition to reporting nine months for 2006 versus seven months for 2005, the increase in residue gas, NGLs and condensate revenues was due to higher average prices for both natural gas and NGLs in the nine months ended September 30, 2006.

Expenses. Expenses generally increased due to nine months of activity in 2006 compared to seven months of activity in 2005. The following paragraphs describe other factors contributing to the change in expenses.

Cost of gas purchased consisted of amounts payable to third-party producers for gas purchased under percentage of proceeds and keep-whole contracts. The increase in the cost of gas purchased was primarily due to overall market increases in natural gas prices in the nine months ended September 30, 2006. Included in cost of gas purchased for the nine months ended September 30, 2006 was a $4.6 million non-cash charge to reserve for amounts related to balances assumed as part of the Cantera Acquisition. The following table shows a summary of the effects of derivative activities on midstream processing margin:


	Nine Months Ended September 30,
	2006			2005
	(in thousands)
Midstream processing margin, as reported	$	50,725		$	31,073
Derivatives losses included in midstream processing margin		1,275			428

Midstream processing margin before impact of derivatives		52,000			31,501
Cash settlements on derivatives		(15,405	)		(3,303	)

Midstream processing margin, adjusted for derivatives	$	36,595		$	28,198

Operating expenses increased due to rent and maintenance costs associated with additional compressors. General and administrative expenses increased primarily due to additional personnel added to support the business and recent acquisitions and increased reimbursement to the general partner for shared corporate overhead costs from $0.3 million in the nine months ended September 30, 2005 to $1.6 million in the nine months ended September 30, 2006. DD&A expense increased due to depreciation on the pipeline acquired in the June 2006 Transwestern Acquisition and recent gathering system expansions.

Corporate and Other

Corporate and other results primarily consist of oversight and administrative functions.

Expenses. Corporate operating expenses increased by $0.5 million from $2.8 million in the third quarter of 2005 to $3.3 million in the third quarter of 2006. Corporate operating expenses increased by $1.9 million from $8.5 million for the nine months ended September 30, 2006 to $10.4 million for the nine months ended September 30, 2005. The increase was primarily related to increased general and administrative expenses which included higher payroll costs as a result of wage increases, new personnel and the recognition of stock option expense upon adoption of SFAS No. 123(R), Share-Based Payment.

Interest Expense. Interest expense increased by $2.9 million from $4.2 million in the third quarter of 2005 to $7.1 million in the third quarter of 2006. Interest expense increased by $6.2 million from $11.1 million in the nine months ended September 30, 2005 to $17.3 million in the nine months ended September 30, 2006. The increase in both periods was primarily due to interest incurred on additional borrowings under the Revolver and the PVR Revolver to finance 2005 and 2006 acquisitions and a general increase in interest rates. We capitalized interest costs amounting to $0.9 million and $1.1 million for the three months ended September 30, 2006 and 2005 and $1.8 million and $2.4 million for the nine months ended September 30, 2006 and 2005 because the borrowings funded the preparation of unproved properties for their intended use.

Derivatives. As a result of price volatility resulting from the 2005 hurricane season, a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting. Because of this non-qualification to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in our future earnings through 2008 as the original hedged transactions occur. This change in reporting will have no impact on our reported cash flows, although our future results of operations will be affected by mark-to-market gains and losses which fluctuate with changes in oil and gas prices.

Derivative gains were $11.4 million for the nine months ended September 30, 2006 and included a $10.9 million unrealized gain for mark-to-market adjustments and a $0.5 million unrealized gain for changes in hedge effectiveness. The unrealized loss due to changes in fair market value was associated with derivative contracts that we no longer accounted for using hedge accounting and represented changes in the fair value of our open contracts during the period. The unrealized loss for changes in hedge effectiveness was associated with hedging contracts that we accounted for using hedge accounting under SFAS No. 133. Derivative losses for the nine months ended

September 30, 2005 included a $13.9 million unrealized loss representing the change in market value of derivative agreements between the time PVR entered into the agreements in January 2005 and the time the derivative agreements qualified for hedge accounting after closing the acquisition of the natural gas midstream business in March 2005.

Environmental

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment and otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

The operations of PVR’s coal lessees and natural gas midstream segment are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of PVR’s coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified PVR against any and all future environmental liabilities. PVR regularly visits coal properties under lease to monitor lessee compliance with environmental laws and regulations and to review mining activities. Management believes that the operations of PVR’s coal lessees and natural gas midstream segment will comply with existing regulations and does not expect any material impact on its financial condition or results of operations.

As of September 30, 2006, PVR’s environmental liabilities were $2.4 million, which represents PVR’s best estimate of the liabilities as of that date related to the coal and natural gas midstream businesses. PVR has reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Recent Accounting Pronouncements

See Note 2 in the Notes to Consolidated Financial Statements for a description of recent accounting pronouncements.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

•

the cost of finding and successfully developing oil and gas reserves;

•

our ability to acquire new oil and gas reserves and the price for which such reserves can be acquired;

•

energy prices generally and specifically, the price of crude oil, natural gas, NGLs and coal;

•

the relationship between natural gas and NGL prices;

•

the price of coal and its comparison to the price of natural gas and oil;

•

the volatility of commodity prices for crude oil, natural gas, NGLs and coal;

•

the projected demand for crude oil, natural gas, NGLs and coal;

•

the projected supply of crude oil, natural gas, NGLs and coal;

•

our ability to obtain adequate pipeline transportation capacity for our oil and gas production;

•

non-performance by third party operators in wells in which we own an interest;

•

competition among producers in the oil and natural gas and coal industries generally and among natural gas midstream companies;

•

the extent to which the amount and quality of actual production of our oil and natural gas or PVR’s coal differs from estimated recoverable proved oil and gas reserves and coal reserves;

•

PVR’s ability to generate sufficient cash from its midstream and coal businesses to pay the minimum quarterly distribution to its general partner and its unitholders;

•

hazards or operating risks incidental to our business and to PVR’s coal or midstream business;

•

PVR’s ability to successfully manage its relatively new natural gas midstream business;

•

PVR’s ability to acquire new coal reserves or midstream assets on satisfactory terms;

•

the price for which coal reserves can be acquired;

•

PVR’s ability to continually find and contract for new sources of natural gas supply for its midstream business;

•

PVR’s ability to retain existing or acquire new midstream customers;

•

PVR’s ability to lease new and existing coal reserves;

•

the ability of PVR’s lessees to produce sufficient quantities of coal on an economic basis from PVR’s reserves;

•

the ability of PVR’s lessees to obtain favorable contracts for coal produced from its reserves;

•

PVR’s exposure to the credit risk of its coal lessees and midstream customers;

•

hazards or operating risks incidental to midstream operations;

•

unanticipated geological problems;

•

the dependence of PVR’s midstream business on having connections to third party pipelines;

•

the availability of required drilling rigs, materials and equipment;

•

the occurrence of unusual weather or operating conditions including force majeure events;

•

the failure of equipment or processes to operate in accordance with specifications or expectations;

•

the failure of PVR’s infrastructure and its lessees’ mining equipment or processes to operate in accordance with specifications or expectations;

•

delays in anticipated start-up dates of our oil and natural gas production and PVR’s lessees’ mining operations and related coal infrastructure projects;

•

environmental risks affecting the drilling and producing of oil and gas wells, the mining of coal reserves or the production, gathering and processing of natural gas;

•

the timing of receipt of necessary governmental permits by us and by PVR or PVR’s lessees;

•

the risks associated with having or not having price risk management programs;

•

labor relations and costs;

•

accidents;

•

changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators;

•

uncertainties relating to the outcome of current and future litigation regarding mine permitting;

•

risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions (including the impact of potential terrorist attacks);

•

the experience and financial condition of PVR’s coal lessees and midstream customers, including the lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others;

•

PVR’s ability to expand its midstream business by constructing new gathering systems, pipelines and processing facilities on an economic basis and in a timely manner;

•

coal handling joint venture operations;

•

changes in financial market conditions;

•

the completion of GP Holdings’ initial public offering; and

•

other risks set forth in Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2005.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2005. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

Item 3 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are NGL, crude oil, natural gas and coal price risks and interest rate risk.

We are also indirectly exposed to the credit risk of our and PVR’s customers and PVR’s lessees. If our customers or PVR’s lessees become financially insolvent, they may not be able to continue operating or meet their payment obligations.

Price Risk Management

Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our anticipated production and PVR’s natural gas midstream business. Prior to May 1, 2006, these financial instruments were historically designated as cash flow hedges and accounted for in accordance with SFAS No. 133. The derivative financial instruments are placed with major financial institutions that we believe are of minimum credit risk. The fair value of our price risk management assets is significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

During the nine months ended September 30, 2006, we reported a $10.9 million derivative gain for mark-to-market adjustments on certain derivatives that no longer qualified for hedge accounting effective January 1, 2006. As a result of price volatility resulting from the 2005 hurricane season, a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting. Because of this non-qualification and to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in our future earnings through 2008 as the original hedged transactions occur. This change in reporting will have no impact on our reported cash flows, although our future results of operations will be affected by mark-to-market gains and losses which fluctuate with changes in oil and gas prices. See the discussion and tables in Note 5 in the Notes to Consolidated Financial Statements for a description of our derivative program. The following table lists our open mark-to-market derivative agreements and their fair value as of September 30, 2006:

Oil and Gas Segment Derivatives


	Average Volume Per Day		Weighted Average Price							Estimated Fair Value (in thousands)
			Additional Put Option		Floor			Ceiling
			Additional Put Option		Floor			Ceiling
Natural Gas Costless Collars	(in Mmbtus	)				(per Mmbtu	)
Fourth Quarter 2006	26,269				$	8.17		$	15.15	$	6,138
First Quarter 2007	20,000				$	9.00		$	19.03		3,463
Second Quarter 2007	15,000				$	7.33		$	12.93		1,345
Third Quarter 2007	15,000				$	7.33		$	12.93		1,314
Fourth Quarter 2007	11,667				$	8.28		$	15.78		1,342
First Quarter 2008	10,000				$	9.00		$	17.95		1,163

Natural Gas Three-way Collars	(in Mmbtus	)				(per Mmbtu	)
Fourth Quarter 2006 (October only)	25,000		$	4.50	$	6.00		$	9.40		1,163
First Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		219
Second Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		307
Third Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		258
Fourth Quarter 2007	3,000		$	5.00	$	8.00		$	11.25		124
First Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		(54	)
Second Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		215
Third Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		188
Fourth Quarter 2008	2,500		$	5.00	$	8.00		$	10.75		88

Natural Gas Put Options	(in Mmbtus	)				(per Mmbtu	)
Fourth Quarter 2006	1,333				$	9.00					393

Crude Oil Costless Collars	(in barrels	)				(per barrel	)
Fourth Quarter 2006	200				$	60.00		$	72.20		7
First Quarter 2007	200				$	60.00		$	72.20		(11	)
Second Quarter 2007	200				$	60.00		$	72.20		(29	)
Third Quarter 2007	200				$	60.00		$	72.20		(41	)
Fourth Quarter 2007	200				$	60.00		$	72.20		(47	)

										$	17,545

PVR Midstream Segment Derivatives


	Average Volume Per Day		Weighted Average Price			Estimated Fair Value (in thousands)
Ethane Swaps	(in gallons	)		(per gallon	)
Fourth Quarter 2006	73,126		$	0.4870		$	(1,251	)
First Quarter 2007 through Fourth Quarter 2007	34,440		$	0.5050			(916	)
First Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700			(1,026	)

Propane Swaps	(in gallons	)		(per gallon	)
Fourth Quarter 2006	52,080		$	0.7060			(1,679	)
First Quarter 2007 through Fourth Quarter 2007	26,040		$	0.7550			(1,709	)
First Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175			(1,798	)

Crude Oil Swaps	(in barrels	)		(per barrel	)
Fourth Quarter 2006	1,100		$	44.45			(2,638	)
First Quarter 2007 through Fourth Quarter 2007	560		$	50.80			(3,376	)
First Quarter 2008 through Fourth Quarter 2008	560		$	49.27			(3,653	)

Crude Oil Collars	(in barrels	)		(per barrel	)
Fourth Quarter 2006 (October only)	270		$	73.59			107

Natural Gas Swaps	(in MMbtu	)		(per MMbtu	)
Fourth Quarter 2006	8,005		$	6.98			(1,009	)
First Quarter 2007 through Fourth Quarter 2007	4,000		$	6.97			987
First Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97			1,377

						$	(16,584	)

Interest Rate Risk

As of September 30, 2006, we had $153.0 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We executed interest rate derivative transactions in August 2006 to effectively convert the interest rate on $50 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 5.34 percent plus the applicable margin. The interest rate swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A one percent increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) at September 30, 2006 would cost approximately $1.0 million in additional interest expense.

As of September 30, 2006, PVR had $251.8 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR executed interest rate derivative transactions in September 2005 to effectively convert the interest rate on $60 million of the amount outstanding under the PVR Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.22 percent plus the applicable margin. The interest rate swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A one percent increase in short-term interest rates on the floating rate debt outstanding under the PVR Revolver (net of amounts fixed through hedging transactions) at September 30, 2006 would cost approximately $1.9 million in additional interest expense.

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2006. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2006, such disclosure controls and procedures were effective.

(b) Changes in Internal Control over Financial Reporting

No changes were made in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except that daily operational accounting for our mid-continent oil and gas division, which was acquired in June 2006, is being outsourced to a third party.

PART II. OTHER INFORMATION

Items 1, 2, 3, 4 and 5 of Part II are not applicable and have been omitted.

Item 1A Risk Factors

Recent new mining laws and regulations could increase operating costs and limit PVR’s lessees’ ability to produce coal, which could have an adverse effect on PVR’s coal royalty revenues.

Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that have resulted in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. In January 2006, West Virginia passed a law imposing stringent new mine safety and accident reporting requirements and increased civil and criminal penalties for violations of mine safety laws. On March 7, 2006, New Mexico Governor Bill Richardson signed into law an expanded miner safety program including more stringent requirements for accident reporting and the installation of additional mine safety equipment at underground mines. Similarly, on April 27, 2006, Kentucky Governor Ernie Fletcher signed mine safety legislation that includes requirements for increased inspections of underground mines and additional mine safety equipment and authorizes the assessment of penalties of up to $5,000 per incident for violations of mine ventilation or roof control requirements.

On June 15, 2006, the President signed new mining safety legislation that mandates similar improvements in mine safety practices, increases civil and criminal penalties for non-compliance, requires the creation of additional mine rescue teams, and expands the scope of federal oversight, inspection and enforcement activities. Earlier, the federal Mine Safety Health Administration announced the promulgation of new emergency rules on mine safety that took effect immediately upon their publication in the Federal Register on March 9, 2006. These rules address mine safety equipment, training, and emergency reporting requirements. Implementing and complying with these new laws and regulations could adversely affect PVR’s lessees’ coal production and could therefore have an adverse affect on PVR’s coal royalty revenues and PVR’s ability to make distributions.

Item 6 Exhibits


10.1		Fourth Amendment to Amended and Restated Credit Agreement dated as of August 25, 2006 among Penn Virginia Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A.

10.2		Fifth Amendment to Amended and Restated Credit Agreement dated as of November 1, 2006 among Penn Virginia Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A.

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.

31.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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


	PENN VIRGINIA CORPORATION

Date: November 2, 2006	By:	/s/ Frank A. Pici
		Frank A. Pici
		Executive Vice President and Chief Financial Officer

Date: November 2, 2006	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller