Ranger Oil 10Q 2007 Q3 Quarterly report

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, 2007

¨	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.

x Yes ¨ 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, 2007, 37,877,430 shares of common stock of the registrant were issued and outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX


		Page
PART I.	Financial Information

Item 1.	Financial Statements

	Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2007 and 2006	1

	Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006	2

	Consolidated Statements of Cash Flows for the Three Months and Nine Months Ended September 30, 2007 and 2006	3

	Notes to Consolidated Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47

Item 4.	Controls and Procedures	50

PART II.	Other Information

Item 6.	Exhibits	51

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,
	2007			2006			2007			2006
Revenues
Natural gas	$	65,310		$	50,540		$	193,961		$	160,384
Oil and condensate		7,589			5,964			18,443			16,378
Natural gas midstream		100,370			100,809			310,095			305,340
Coal royalties		24,426			26,612			73,455			73,288
Gain on the sale of properties		12,312			—			12,436			—
Other		5,751			4,468			16,036			13,060

Total revenues		215,758			188,393			624,426			568,450

Expenses
Cost of midstream gas purchased		76,192			80,272			251,000			254,615
Operating		17,602			14,259			47,557			33,438
Exploration		12,873			12,660			23,610			26,061
Taxes other than income		5,156			2,322			15,995			11,217
General and administrative		16,439			10,900			46,539			33,289
Impairment of oil and gas properties		2,405			—			2,405			—
Depreciation, depletion and amortization		33,207			23,336			89,823			66,581

Total expenses		163,874			143,749			476,929			425,201

Operating income		51,884			44,644			147,497			143,249
Other income (expense)
Interest expense		(10,843	)		(7,108	)		(25,878	)		(17,292	)
Other		576			379			2,536			1,138
Derivatives		(4,455	)		17,940			(22,068	)		11,403

Income before minority interest and income taxes		37,162			55,855			102,087			138,498
Minority interest		9,135			18,539			27,659			31,187
Income tax expense		10,913			14,435			29,033			42,105

Net income	$	17,114		$	22,881		$	45,395		$	65,206

Net income per share, basic (see Note 9)	$	0.45		$	0.61		$	1.20		$	1.75
Net income per share, diluted (see Note 9)	$	0.45		$	0.61		$	1.19		$	1.73
Weighted average shares outstanding, basic		37,898			37,358			37,748			37,316
Weighted average shares outstanding, diluted		38,213			37,790			38,045			37,744

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, 2007			December 31, 2006
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	14,803		$	20,338
Accounts receivable		147,361			138,880
Derivative assets		7,738			18,244
Other		11,449			14,921

Total current assets		181,351			192,383

Property and equipment
Oil and gas properties (successful efforts method)		1,384,740			1,045,182
Other property and equipment		837,754			671,169

		2,222,494			1,716,351
Accumulated depreciation, depletion and amortization		(447,411	)		(357,968	)

Net property and equipment		1,775,083			1,358,383
Derivative assets		1,732			4,344
Other assets		88,390			78,039

Total assets	$	2,046,556		$	1,633,149

Liabilities and Shareholders’ Equity
Current liabilities
Current maturities of long-term debt	$	12,554		$	10,832
Accounts payable and accrued liabilities		151,083			154,709
Derivative liabilities		22,579			7,149

Total current liabilities		186,216			172,690

Other liabilities		35,646			26,003
Derivative liabilities		4,162			7,065
Deferred income taxes		191,524			178,380
Long-term debt of the Company		414,500			221,000
Long-term debt of PVR		351,618			207,214
Minority interests of subsidiaries		189,820			438,372
Shareholders’ equity
Preferred stock of $100 par value – 100,000 shares authorized; none issued		—			—
Common stock of $0.01 par value – 62,000,000 shares authorized; 37,877,320 and 37,561,264 shares issued and outstanding at September 30, 2007, and December 31, 2006		190			188
Paid-in capital		350,917			100,559
Retained earnings		328,992			289,967
Deferred compensation obligation		1,451			1,314
Accumulated other comprehensive income		(6,626	)		(7,954	)
Treasury stock – 74,330 and 70,898 shares common stock, at cost, on September 30, 2007 and December 31, 2006, respectively		(1,854	)		(1,649	)

Total shareholders’ equity		673,070			382,425

Total liabilities and shareholders’ equity	$	2,046,556		$	1,633,149

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,
	2007			2006			2007			2006
Cash flows from operating activities
Net income	$	17,114		$	22,881		$	45,395		$	65,206
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		33,207			23,336			89,823			66,581
Commodity derivative contracts:
Total derivative losses		6,053			(17,675	)		25,569			(10,042	)
Cash received (paid) in derivative settlements		586			(4,216	)		2,281			(10,433	)
Deferred income taxes		9,218			13,248			21,902			32,071
Minority interest		9,135			18,539			27,659			31,187
Loss (gain) on the sale of property and equipment		(12,312	)		—			(12,436	)		—
Impairment of oil and gas properties		2,405			—			2,405			—
Dry hole and unproved leasehold expense		11,991			9,566			20,707			17,925
Other		1,523			919			2,918			5,483
Changes in operating assets and liabilities		(2,736	)		(19,437	)		(17,242	)		(917	)

Net cash provided by operating activities		76,184			47,161			208,981			197,061

Cash flows from investing activities
Proceeds from the sale of property and equipment		29,142			30			29,385			2,505
Acquisitions		(162,794	)		(6,816	)		(239,018	)		(171,479	)
Additions to property and equipment		(109,685	)		(76,700	)		(308,987	)		(182,239	)

Net cash used in investing activities		(243,337	)		(83,486	)		(518,620	)		(351,213	)

Cash flows from financing activities
Dividends paid		(2,130	)		(2,101	)		(6,370	)		(6,298	)
Proceeds from borrowings of the Company		113,000			35,000			220,500			121,000
Repayments of borrowings of the Company		(27,000	)		—			(27,000	)		(20,000	)
Distributions paid to minority interest holders		(12,937	)		(9,827	)		(36,402	)		(28,144	)
Proceeds from issuance of partners’ capital by PVG		—			—			860			—
Proceeds from borrowings of PVR, net		89,000			10,000			146,000			71,500
Other		(188	)		1,833			6,516			2,567

Net cash provided by financing activities		159,745			34,905			304,104			140,625

Net decrease in cash and cash equivalents		(7,408	)		(1,420	)		(5,535	)		(13,527	)
Cash and cash equivalents – beginning of period		22,211			13,806			20,338			25,913

Cash and cash equivalents – end of period	$	14,803		$	12,386		$	14,803		$	12,386

Supplemental disclosures:
Cash paid during the periods for:
Interest, net of amounts capitalized	$	13,630		$	6,842		$	28,397		$	17,592
Income taxes	$	162		$	8,475		$	464		$	16,640
Noncash investing activities:
Deferred tax liabilities related to acquisition, net	$	—		$	—		$	—		$	32,759

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

September 30, 2007

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 Appalachian, Mississippi, Mid-Continent, east Texas and Gulf Coast regions of the United States. Our coal and natural resource management segment and natural gas midstream segment operate through Penn Virginia Resource Partners, L.P. (“PVR”). We own 100% of the general partner of Penn Virginia GP Holdings, L.P. (“PVG”) and an approximately 82% limited partner interest in PVG. PVG owns 100% of the general partner of PVR, which holds a 2% general partner interest in PVR, and an approximately 42% limited partner interest in PVR. Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s condensed consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments.

PVR is a Delaware limited partnership formed by us in July 2001 primarily to engage in the business of managing coal properties in the United States. PVR completed its initial public offering (the “PVR IPO”) in October 2001. PVG completed its initial public offering (the “PVG IPO”) in December 2006, selling approximately 18% of its outstanding units to the public and using the proceeds from the offering to purchase newly issued common and Class B units from PVR.

The PVR coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. PVR also earns revenues from providing fee-based coal preparation and transportation services to its lessees, 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. In addition, PVR earns revenues from oil and gas royalty interests it owns, from coal transportation, or wheelage, rights and from the sale of standing timber on its properties.

The PVR natural gas midstream segment is engaged in providing gas processing, gathering and other related natural gas services. PVR owns and operates natural gas midstream assets located in Oklahoma and the panhandle of Texas. 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. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

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, 2006. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

Our consolidated financial statements include the accounts of Penn Virginia, all of its wholly-owned subsidiaries and PVG, of which we indirectly owned the sole general partner and an approximately 82% limited partner interest as of September 30, 2007. PVG GP, LLC, our wholly-owned subsidiary, serves as PVG’s general partner and controls PVG. Intercompany balances and transactions have been eliminated in consolidation. Our consolidated 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 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. Our consolidated 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, 2006. Operating results for the three months and nine months ended September 30, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007. Certain reclassifications have been made to conform to the current period’s presentation.

New Accounting Standards

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation 48,Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109(“FIN 48”), which became effective for us on January 1, 2007. FIN 48 creates a single model to address uncertainty in income tax positions. It 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. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition and clearly scopes income taxes out of Statement of Financial Accounting Standard (“SFAS”) No. 5,Accounting for Contingencies. See Note 8 for more information regarding the adoption of FIN 48.

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 are currently assessing the impact on our consolidated financial statements of adopting SFAS No. 157 effective January 1, 2008.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115,which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS No. 159 is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We are currently assessing the impact on our consolidated financial statements of adopting SFAS No. 159 effective January 1, 2008.

In July 2007, the Emerging Issues Task Force (the “EITF”) approved and the FASB ratified Issue 06-11,Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. Issue 06-11 addresses how a company should recognize the income tax benefit received on dividends that are (a) paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and (b) charged to retained earnings under SFAS No. 123(R),Share-based Payment. The EITF reached a conclusion that a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for any of the above-mentioned three types of equity-classified awards should be recognized as an increase to additional paid-in capital as part of the pool of excess tax benefits available to absorb tax deficiencies on share-based payment awards. Issue 06-11 is effective for the tax benefits of dividends declared in fiscal years beginning after December 15, 2007. We are currently assessing the impact on our consolidated financial statements of adopting Issue 06-11 effective January 1, 2008.

3.	Acquisitions

Oil and Gas Segment

In May 2007, we acquired lease rights to property covering approximately 640 acres located in Jefferson Davis County, Mississippi, with estimated proved reserves of 11.2 billion cubic feet of natural gas equivalent (“Bcfe”). The purchase price was $10.5 million in cash and was funded with long-term debt under our revolving credit facility. The acquisition has been recorded as a component of oil and gas properties.

In July 2007, we acquired lease rights to property covering approximately 4,000 acres located in Harrison County, Texas, with estimated proved reserves of 19.5 Bcfe. The purchase price was $22.0 million in cash and was funded with long-term debt under our revolving credit facility. The acquisition has been recorded as a component of oil and gas properties.

In August 2007, we acquired lease rights to property covering approximately 22,700 acres located in eastern Oklahoma, with estimated proved reserves of 18.8 Bcfe. The purchase price was $47.9 million in cash and was funded with long-term debt under our revolving credit facility. We acquired these assets in order to expand our oil and gas segment business. The acquisition has been recorded as a component of oil and gas properties. These assets include, $19.2 million of unproved property and $28.7 million of proved oil and gas properties. The purchase price allocation for the acquisition has not been finalized because we are still in the process of settling various post-closing adjustments with the seller and obtaining final appraisals of assets acquired and liabilities assumed.

The pro forma results for the year ended December 31, 2006 and the nine months ended September 30, 2007 would not materially change historical results.

PVR Coal and Natural Resource Management Segment

In June 2007, PVR acquired fee ownership of approximately nine million tons of coal reserves. The reserves are located on approximately 1,700 acres in Jackson County, Illinois. The purchase price was $9.9 million in cash and was funded with long-term debt under PVR’s revolving credit facility. The acquisition has been recorded as a component of other property and equipment.

In June 2007, PVR acquired a combination of fee ownership and lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. This property is located on approximately 17,000 acres in Webster and Hopkins Counties, Kentucky. The purchase price was $42.0 million in cash and was funded with long-term debt under PVR’s revolving credit facility. The acquisition has been recorded as a component of other property and equipment and other assets. Approximately $30.0 million of the purchase price was allocated to the coal reserves, approximately $11.5 million was allocated to other long-term assets and approximately $0.5 million was allocated to plant property.

In September 2007, PVR acquired fee ownership of approximately 62,000 acres of forestland in Barbour, Randolph, Tucker and Upshur Counties, West Virginia. The purchase price was $93.1 million in cash and was funded with long-term debt under PVR’s revolving credit facility. The acquisition has been recorded as a component of other property and equipment.

4.	Sale of Oil and Gas Properties

In September 2007, we sold non-operated working interests in oil and gas properties located in Harlan and Letcher Counties, Kentucky and Lee, Scott and Wise Counties, Virginia, with estimated proved reserves of 13.3 Bcfe. The sale price was $29.1 million in cash, and the proceeds of the sale were used to repay borrowings under our revolving credit facility. We recognized a gain of $12.4 million on the sale, which gain is reported in the revenues section of our consolidated statements of income.

5.	Stock Split

On May 8, 2007, the Board of Directors approved a two-for-one-split of the Company’s common stock in the form of a 100% stock dividend payable on June 19, 2007 to shareholders of record on June 12, 2007. Shareholders received one additional share of common stock for each share held on the record date. All common shares and per share data have been retroactively adjusted to reflect the stock split.

6.	Gain on Sale of Subsidiary Units

We accounted for the PVR IPO and each subsequent PVR equity issuance as a sale of a minority interest. For each PVR equity issuance, we calculated a gain under SEC Staff Accounting Bulletin No. 51 (or Topic 5-H),Accounting for Sales of Stock by a Subsidiary(“SAB 51”). Because the PVR common units had preference over the PVR subordinated units with respect to distributions, the gain was not recognized at the time of each PVR equity issuance. This gain was to be recognized in shareholders’

equity when all of the subordinated units converted to common units. By November 2006, all of the subordinated units had converted to common units. However, because the issuance of the PVR Class B units, which were subordinate to the PVR common units with respect to distributions, was contemplated at the time the final PVR subordinated units converted to PVR common units in November 2006, we did not recognize the SAB 51 gain at the time. After the conversion of the Class B units to common units on a one-for-one basis in May 2007, PVR no longer had any form of junior securities outstanding. Accordingly, we recognized a $150.5 million gain in shareholders’ equity related to PVR equity issuances from the time of the PVR IPO in October 2001 to May 2007. SAB 51 gains will be recognized with respect to future PVR equity issuances at the time of the equity issuances as long PVR does not have any junior securities outstanding and is not contemplating the issuance of junior securities.

Similarly, we accounted for the PVG IPO as a sale of a minority interest in December 2006. Because the PVR common units had preference over the PVR Class B units with respect to distributions, the gain was not recognized at the time of each PVR equity issuance. When the PVR Class B units converted to common units in May 2007, we recognized a $104.1 million gain to shareholders’ equity in accordance with SAB 51.

7.	Derivative Instruments

For commodity derivative instruments, we recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (shareholders’ equity). The following table summarizes the effects of commodity derivative activities on our consolidated statements of income:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Income statement caption:
Natural gas revenues	$	(166	)	$	663		$	316		$	247
Oil and condensate revenues		(126	)		(103	)		(383	)		(333	)
Natural gas midstream revenues		(2,077	)		(2,724	)		(6,413	)		(7,456	)
Cost of midstream gas purchased		773			1,899			2,981			6,181
Derivatives		(4,455	)		17,940			(22,068	)		11,403

Increase (decrease) in income before minority interest and income taxes	$	(6,051	)	$	17,675		$	(25,567	)	$	10,042

Realized and unrealized derivative impact:
Cash received (paid) for derivative settlements	$	586		$	(4,216	)	$	2,281		$	(10,433	)
Unrealized derivative gain (loss)		(6,637	)		21,891			(27,848	)		20,475

Increase (decrease) in income before minority interest and income taxes	$	(6,051	)	$	17,675		$	(25,567	)	$	10,042

Oil and Gas Segment Commodity Derivatives

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

With respect to 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. By combining the collar contract with the additional put option, we are entitled 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. With respect to a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are 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 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, 2007. The following table sets forth our positions as of September 30, 2007:


	Average Volume Per Day	Weighted Average Price						Estimated Fair Value
	Average Volume Per Day	Additional Put Option		Floor		Ceiling		Estimated Fair Value
								(in thousands)
	(in MMbtus)			(per MMbtu)
Natural Gas Costless Collars
Fourth quarter 2007	11,685			$	8.28	$	15.78	$	1,544
First quarter 2008	10,000			$	9.00	$	17.95		1,322
Second quarter 2008	10,000			$	7.50	$	9.10		243
Third quarter 2008	10,000			$	7.50	$	9.10		243
Fourth quarter 2008 (October only)	10,000			$	7.50	$	9.10		81

	(in MMbtus)			(per MMbtu)
Natural Gas Three-Way Collars
Fourth quarter 2007	26,370	$	5.25	$	7.74	$	11.14		2,372
First quarter 2008	22,500	$	5.44	$	8.00	$	12.64		1,313
Second quarter 2008	22,500	$	5.00	$	7.11	$	9.09		(140	)
Third quarter 2008	22,500	$	5.00	$	7.11	$	9.09		74
Fourth quarter 2008	22,500	$	5.44	$	7.70	$	11.40		558
First quarter 2009	20,000	$	5.75	$	8.00	$	12.80		291

	(in barrels)			(per barrel)
Crude Oil Costless Collars
Fourth quarter 2007	200			$	60.00	$	72.20		(157	)

	(in barrels)			(per barrel)
Crude Oil Swaps
Fourth quarter 2007	300			$	69.00				(307	)
Settlements to be paid in subsequent period									(141	)

Oil and gas segment commodity derivatives - net asset								$	7,296

We have reported (i) a net derivative asset of $7.3 million and (ii) a loss in accumulated other comprehensive income of $0.1 million, net of a related income taxes, related to derivatives in the oil and gas segment for which hedge accounting was discontinued during 2006.

PVR Natural Gas Midstream Segment Commodity Derivatives

PVR utilizes swap derivative contracts and costless collars to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of midstream gas purchased. While the use of derivative instruments limits the risk of adverse price movements, their use also may limit future revenues or cost savings from favorable price movements. The fair values of PVR’s derivative agreements are determined based on forward price quotes for the respective commodities as of September 30, 2007. The following table sets forth PVR’s positions as of September 30, 2007 for commodities related to natural gas midstream revenues (ethane, propane, natural gasoline and crude oil) and cost of midstream gas purchased (natural gas and crude oil):


	Average Volume Per Day	Weighted Average Price		Weighted Average Price Collars				Estimated Fair Value
	Average Volume Per Day	Weighted Average Price		Put		Call		Estimated Fair Value
								(in thousands)
	(in gallons)	(per gallon)
Ethane Swaps
Fourth quarter 2007	34,440	$	0.5050					$	(1,240	)
First quarter 2008 through fourth quarter 2008	34,440	$	0.4700						(3,299	)

	(in gallons)	(per gallon)
Propane Swaps
Fourth quarter 2007	26,040	$	0.7550						(1,384	)
First quarter 2008 through fourth quarter 2008	26,040	$	0.7175						(4,592	)

	(in barrels)	(per barrel)
Crude Oil Swaps
Fourth quarter 2007	560	$	50.80						(1,502	)
First quarter 2008 through fourth quarter 2008	560	$	49.27						(5,355	)

	(in MMbtu)	(per MMbtu)
Natural Gas Swaps (Purchase)
Fourth quarter 2007 through fourth quarter 2008	4,000	$	6.97						1,405

	(in gallons / in barrels)	(per gallon / per barrel)
Natural Gasoline Swap/Crude Oil Swap (purchase)
Fourth quarter 2007	23,520 / 560		1.265 / 57.12						33

	(in gallons)			(per gallon)
Ethane Collar
Fourth quarter 2007	5,000			$	0.6100	$	0.7125		(88	)

	(in gallons)			(per gallon)
Propane Collar
Fourth quarter 2007	9,000			$	1.0300	$	1.1640		(148	)

	(in gallons)			(per gallon)
Natural Gasoline Collar
Fourth quarter 2007 through fourth quarter 2008	6,300			$	1.4800	$	1.6465		(366	)

	(in barrels)			(per barrel)
Crude Oil Collar
First quarter 2008 through fourth quarter 2008	400			$	65.00	$	75.25		(600	)

	(in MMbtu)	(per MMbtu)
Frac Spread
Fourth quarter 2007	7,128	$	4.55						(2,601	)
First quarter 2008 through fourth quarter 2008	4,193	$	4.30						(1,933	)
Settlements to be paid in subsequent period									(2,428	)

Natural gas midstream segment commodity derivatives - net liability								$	(24,098	)

At September 30, 2007, PVR reported (i) a net derivative liability related to the natural gas midstream segment of $24.1 million and (ii) a loss in accumulated other comprehensive income of $4.3 million, net of the related income tax effect of $2.3 million, related to derivatives in the natural gas midstream segment for which PVR discontinued hedge accounting in 2006. The $4.3 million loss, net of the related income tax effect of $2.3 million, will be recorded in earnings through the end of 2008 as the hedged transactions settle.

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 portion of the outstanding balance on our revolving credit facility that is based on the London Inter Bank Offering Rate (“LIBOR”) until December 2010. We pay a weighted average fixed rate of 5.34% 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 $1.0 million at September 30, 2007 and (ii) a loss in accumulated other comprehensive income of less than $0.7 million, net of the related income tax effect of $0.3 million, at September 30, 2007 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 nine months ended September 30, 2007.

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 its revolving credit facility that is based on the LIBOR until March 2010. PVR pays a weighted average fixed rate of 4.22% 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 $0.6 million at September 30, 2007 and (ii) a gain in accumulated other comprehensive income of $0.4 million, net of the related income tax effect of $0.2 million, at September 30, 2007 related to the PVR Revolver Swaps. In connection with periodic settlements, PVR recognized $0.5 million in net hedging gains in interest expense for the nine months ended September 30, 2007.

8.	Income Taxes

Effective January 1, 2007, we adopted FIN 48. The evaluation of whether a tax position is in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon settlement.

The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of FIN 48. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings for that fiscal year. The adoption of FIN 48 did not result in a transition adjustment to retained earnings; instead, $8.7 million was reclassified from deferred income taxes to a long-term liability. In the three months and nine months ended September 30, 2007, we recognized a decrease of $0.5 million in the long-term liability related to tax settlements.

The long-term liability balance at September 30, 2007 was $9.5 million, including $6.4 million of tax positions which would change the effective tax rate, if recognized. We recognize interest related to unrecognized tax benefits in interest expense, and penalties are included in income tax accrued. For the three months and nine months ended September 30, 2007, we recognized $0.2 million and $0.5 million in interest and penalties. Prior to adoption of FIN 48, we classified interest on taxes as a component of income tax expense, and penalties were included in income tax expense. We had accrued interest and penalties of $3.2 million as of September 30, 2007 and $2.7 million as of January 1, 2007. We do not expect a significant change in unrecognized tax benefits within the next 12 months. Tax years from 2003 forward remain open for examination by the Internal Revenue Service.

9.	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, 2007 and 2006:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands except per share data)
Net income	$	17,114		$	22,881		$	45,395		$	65,206
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards		(60	)		(15	)		(170	)		(85	)

	$	17,054		$	22,866		$	45,225		$	65,121
Weighted average shares, basic		37,898			37,358			37,748			37,316
Effect of dilutive stock options		315			432			297			428

Weighted average shares, diluted		38,213			37,790			38,045			37,744

Net income per share, basic	$	0.45		$	0.61		$	1.20		$	1.75

Net income per share, diluted	$	0.45		$	0.61		$	1.19		$	1.73

10.

Share-Based Payments

Stock Compensation Plans

We recognized compensation expense related to the granting of common stock and deferred common stock units and the vesting of stock options and restricted stock granted under our stock compensations plans. For the three months ended September 30, 2007 and 2006, we recognized a total of $1.0 million and $0.7 million of compensation expense related to our stock compensation plans. The total income tax benefit recognized in our consolidated statements of income for our stock compensation plans was $0.4 million and $0.3 million for the three months ended September 30, 2007 and 2006. For the nine months ended September 30, 2007 and 2006, we recognized a total of $3.0 million and $2.1 million of compensation expense related to our stock compensation plans. The total income tax benefit recognized in our consolidated statements of income for our stock compensation plans was $1.2 million and $0.8 million for the nine months ended September 30, 2007 and 2006.

Stock Options. In February 2007, we granted 414,030 stock options with a weighted average exercise price of $35.21 and a weighted average grant date fair value of $9.79 per option. The options vest ratably over a three-year period. The number of options and the prices have been adjusted for the two-for-one stock split in June 2007.

Restricted Stock. In February 2007, we also granted 17,056 shares of restricted stock with a weighted average grant date fair value of $35.21 per share. Restricted stock granted in 2007 vests over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period. The number of shares and the prices have been adjusted for the two-for-one stock split in June 2007.

PVR Long-Term Incentive Plan

We also recognized compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under the long-term incentive plan of PVR’s general partner to our employees who perform services for PVR. For the three months ended September 30, 2007 and 2006, we recognized a total of $0.7 million and $0.6 million of compensation expense related to the PVR long-term incentive plan. For the nine months ended September 30, 2007 and 2006, we recognized a total of $1.8 million and $1.6 million of compensation expense related to the PVR long-term incentive plan.

During the nine months ended September 30, 2007, 85,233 PVR restricted units with a weighted average grant date fair value of $26.85 per unit were granted to our employees who perform services for PVR. During the same period, 42,582 PVR restricted units with a weighted average grant date fair value of $27.56 per unit vested. PVR restricted units granted in 2007 vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

11.

Impairment of Oil and Gas Properties

In accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets,we review oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. When we find that the carrying amounts of the properties exceed their estimated undiscounted future cash flows, we adjust the carrying amounts of the properties to their fair value as determined by discounting their estimated future cash flows. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

For the nine months ended September 30, 2007, we recognized an impairment charge of $2.4 million related to changes in estimates of the reserve bases of fields in the Gulf Coast and Mid-Continent regions.

12.

Comprehensive Income

Comprehensive income represents certain changes in shareholders’ equity during the reporting period, including net income and charges directly to shareholders’ equity which are excluded from net income. For the three months and nine months ended September 30, 2007 and 2006, the components of comprehensive income were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Net income	$	17,114		$	22,881		$	45,395		$	65,206
Unrealized holding gains (losses) on derivative activities, net of tax		(1,215	)		(1,156	)		(505	)		399
Reclassification adjustment for derivative activities, net of tax		925			54			1,938			354
Pension plan adjustment		(35	)		—			(106	)		—

Comprehensive income	$	16,789		$	21,779		$	46,722		$	65,959

13.

Suspended Well Costs

The exploratory well that was pending determination of proved reserves as of December 31, 2006 was subsequently determined to be successful. Accordingly, we reclassified $1.1 million of capitalized exploratory drilling costs related to this well to wells, equipment and facilities during the nine months ended September 30, 2007.

14.

Commitments and Contingencies

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, our management believes that these claims will not have a material effect on our financial position, liquidity or operations.

Environmental Compliance

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.

PVR’s operations and those of its lessees 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 its coal properties under lease to monitor lessee compliance with environmental laws and regulations and to review mining activities. PVR’s management believes that its operations and those of its lessees comply with existing laws and regulations and does not expect any material impact on its financial condition or results of operations.

As of September 30, 2007, PVR’s environmental liabilities included $1.5 million, which represents PVR’s best estimate of its liabilities as of that date related to its coal and natural resource management 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.

Mine Health and Safety Laws

There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since PVR does not operate any coal mines and does not employ any coal miners, PVR is not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.

15.

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 and natural resource management 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.

•

PVR Coal and Natural Resource Management—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 coal-related infrastructure facilities to certain lessees and end-user industrial plants; and collection of oil and gas royalties.

•

PVR Natural Gas Midstream—natural gas processing, natural gas gathering and other related services.

The following table presents a summary of certain financial information relating to our segments:


	Oil and Gas			PVR Coal and Natural Resource Management			PVR Natural Gas Midstream		Corporate and Other			Consolidated
	(in thousands)
For the Three Months Ended September 30, 2007:
Revenues	$	85,745		$	28,218		$	101,374	$	421		$	215,758
Intersegment revenues (1)		(414	)		198			414		(198	)		—
Operating costs and expenses		36,029			4,871			82,917		6,850			130,667
Depreciation, depletion and amortization		22,152			5,833			4,812		410			33,207

Operating income (loss)	$	27,150		$	17,712		$	14,059	$	(7,037	)		51,884

Interest expense													(10,843	)
Interest income and other													576
Derivatives													(4,455	)

Income before minority interest and taxes												$	37,162

Total Assets	$	1,151,331		$	561,169		$	287,769	$	46,287		$	2,046,556

Additions to property and equipment and acquisitions	$	166,500		$	93,449		$	10,755	$	1,775		$	272,479

For the Three Months Ended September 30, 2006:
Revenues	$	56,966		$	30,087		$	101,547	$	(207	)	$	188,393
Intersegment revenues (1)		(60	)		(198	)		60		198			—
Operating costs and expenses		25,473			5,591			86,144		3,205			120,413
Depreciation, depletion and amortization		13,365			5,551			4,313		107			23,336

Operating income (loss)	$	18,068		$	18,747		$	11,150	$	(3,321	)		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	$	70,558		$	5,735		$	6,036	$	1,187		$	83,516

(1)	Represents agent fees paid by the oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.


	Oil and Gas			PVR Coal and Natural Resource Management			PVR Natural Gas Midstream		Corporate and Other			Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2007:
Revenues	$	226,665		$	84,716		$	312,084	$	961		$	624,426
Intersegment revenues (1)		(1,154	)		594			1,154		(594	)		—
Operating costs and expenses		81,480			15,489			270,966		19,171			387,106
Depreciation, depletion and amortization		58,628			16,643			13,957		595			89,823

Operating income (loss)	$	85,403		$	53,178		$	28,315	$	(19,399	)		147,497

Interest expense													(25,878	)
Interest income and other													2,536
Derivatives													(22,068	)

Income before minority interest and taxes												$	102,087

Total Assets	$	1,151,331		$	561,169		$	287,769	$	46,287		$	2,046,556

Additions to property and equipment and acquisitions	$	367,558		$	146,915		$	28,619	$	4,913		$	548,005

For the Nine Months Ended September 30, 2006:
Revenues	$	178,343		$	83,709		$	306,946	$	(548	)	$	568,450
Intersegment revenues (1)		(60	)		(594	)		60		594			—
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	$	243,016		$	80,902		$	27,577	$	2,223		$	353,718

(1)	Represents agent fees paid by the oil and gas segment to the PVR natural gas midstream segment for marketing certain natural gas production and rail car rental fees paid by a corporate affiliate to the PVR coal and natural resource management segment.

16.

Subsequent Events

On October 12, 2007, PVR purchased oil and gas royalty interests from us for $31.0 million. The royalty interests are associated with leases of property in Harlan and Letcher Counties, Kentucky and Lee, Scott and Wise Counties, Virginia, with estimated proved reserves of approximately 8.7 Bcfe at January 1, 2007. PVR funded the acquisition using its revolving credit facility, and we used the net proceeds from the sale to repay borrowings under our revolving credit facility.

On October 24, 2007, our Board of Directors declared a $0.05625 per share quarterly dividend for the three months ended September 30, 2007, or $0.225 per share on an annualized basis. The dividend will be paid on November 20, 2007 to shareholders of record at the close of business on November 6, 2007.

On October 25, 2007, we acquired lease rights to property covering 4,800 gross acres in east Texas, with estimated proved reserves of 21.9 Bcfe. The purchase price was $44.9 million and was funded with borrowings under our revolving credit facility.

Item 2

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

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) 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 Dispositions

•

Liquidity and Capital Resources

•

Results of Operations

•

Summary of Critical Accounting Policies and Estimates

•

Environmental Matters

•

Recent Accounting Pronouncements

•

Forward-Looking Statements

Overview of Business

We are an independent energy company that is engaged in three primary business segments: 1) oil and gas, 2) coal and natural resource management and 3) natural gas midstream. We directly operate our oil and gas segment. Penn Virginia Resource Partners, L.P. (“PVR”) operates our coal and natural resource management and natural gas midstream segments. We own the general partner of Penn Virginia GP Holdings, L.P. (“PVG”) and an approximately 82% limited partner interest in PVG. PVG owns 100% of the general partner of PVR, which holds a 2% general partner interest in PVR, and an approximately 42% limited partner interest in PVR. We consolidate PVG’s results into our financial statements. For the nine months ended September 30, 2007, we had an approximately 82% interest in PVG’s net income. Operating income was $147.5 million in the nine months ended September 30, 2007, compared to $143.2 million in the nine months ended September 30, 2006. In the nine months ended September 30, 2007, the oil and gas segment contributed $85.4 million, or 58%, to operating income, the PVR coal and natural resource management segment contributed $53.2 million, or 36%, and the PVR natural gas midstream segment contributed $28.3 million, or 19%. Corporate and other functions resulted in $19.4 million of operating expenses. The following table presents a summary of certain financial information relating to our segments:


	Oil and Gas		PVR Coal and Natural Resource Management		PVR Natural Gas Midstream		Corporate and Other			Consolidated
For the Nine Months Ended September 30, 2007:
Revenues	$	225,511	$	85,310	$	313,238	$	367		$	624,426
Operating costs and expenses		81,480		15,489		270,966		19,171			387,106
Depreciation, depletion and amortization		58,628		16,643		13,957		595			89,823

Operating income (loss)	$	85,403	$	53,178	$	28,315	$	(19,399	)	$	147,497

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

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 regions of the United States. At December 31, 2006, we had proved oil and natural gas reserves of approximately 5 million barrels of oil and condensate and 457 billion cubic feet (“Bcf”) of natural gas, or 487 billion cubic feet equivalent (“Bcfe”). Oil and natural gas production from our properties increased by 7.2 Bcfe, or 32%, from 22.7 Bcfe produced in the nine months ended September 30, 2006 to 29.9 Bcfe produced in the nine months ended September 30, 2007. Three of our oil and gas customers accounted for 53% of our natural gas and oil and condensate revenues.

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, such as the Cotton Valley play in east Texas, the Selma Chalk play in Mississippi and coal bed methane (“CBM”) gas in Appalachia and the Mid-Continent. We expect to continue to increase our proved reserves and production through our active development drilling programs in each of these areas. We are also committed to expanding our oil and gas reserves and production by using our ability to generate exploratory prospects and development drilling programs internally, primarily along the Gulf Coast of Louisiana and Texas, and by acquiring proved reserves, production and leasehold acreage. For a more detailed discussion of our acquisitions, see “—Acquisitions and Dispositions.”

PVR Coal and Natural Resource Management Segment

As of December 31, 2006, PVR owned or controlled approximately 765 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. PVR enters into long-term leases with experienced, third-party mine operators providing them the right to mine its coal reserves in exchange for royalty payments. PVR actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. PVR does not operate any coal mines. In the nine months ended September 30, 2007, PVR’s lessees produced 25.2 million tons of coal from its properties and paid PVR coal royalties revenues of $73.5 million, for an average gross coal royalty per ton of $2.92. Approximately 80% and 83% of PVR’s coal royalties revenues in the nine months ended September 30, 2007 and 2006 were derived from coal mined on PVR properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of its coal royalties revenues for the respective periods was derived from coal mined on PVR properties under leases containing fixed royalty rates that escalate annually.

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. 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’s lessees or its lessee’s customers to change operations significantly or incur substantial costs. Fluctuations in production on subleased properties have a direct impact on coal royalties expense. To a lesser extent, Coal prices also impact coal royalties revenues. Generally, as coal prices change, PVR’s average royalty per ton also changes because the majority of its lessees pay royalties based on the gross sales prices of the coal mined. Most of PVR’s coal is sold by its lessees under contracts with a duration of one year or more; therefore, changes to the average royalty occurs as PVR’s lessees’ contracts are renegotiated.

PVR also earns revenues from providing fee-based coal preparation and transportation services to its lessees, which enhance their production levels and generate additional coal royalties revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through its joint venture with Massey Energy Company. In addition, PVR earns revenues from oil and gas royalty interests it owns, from coal transportation, or wheelage, rights and from the sale of standing timber on its properties.

PVR’s management continues to focus on acquisitions that increase and diversify its sources of cash flow. During the nine months ended September 30, 2007, PVR acquired 60 million tons of coal reserves.

in two coal reserve acquisitions with an aggregate purchase price of approximately $52 million. In addition, in September 2007, PVR acquired approximately 62,000 acres of forestland in West Virginia for a purchase price of approximately $93 million to expand its existing timber business. For a more detailed discussion of PVR’s acquisitions, see “—Acquisitions and Dispositions.”

PVR Natural Gas Midstream Segment

PVR owns and operates natural gas midstream assets located in Oklahoma and the panhandle of Texas. These assets include approximately 3,655 miles of natural gas gathering pipelines and three natural gas processing facilities having 160 million cubic feet per day (“MMcfd”) of total capacity. 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. PVR also owns a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

In the nine months ended September 30, 2007, system throughput volumes at PVR’s gas processing plants and gathering systems, including gathering-only volumes, were 50.8 billion cubic feet, or 186 MMcfd, and three of PVR’s natural gas midstream customers accounted for 53% of PVR’s natural gas midstream revenues.

Revenues, profitability and the future rate of growth of the PVR natural gas 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.

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 system throughput volumes. New natural gas supplies are obtained for all of its 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. During 2007, PVR has expended $21.7 million on expansion projects to allow it to capitalize on such opportunities. The expansion projects include two natural gas processing facilities with a combined 140 MMcfd of inlet gas capacity.

Corporate and Other

Corporate and other primarily represents corporate functions.

Ownership of and Relationship with PVG and PVR

Penn Virginia, PVG and PVR are publicly traded on the New York Stock Exchange under the symbols “PVA,” “PVG” and “PVR.” Because we control the general partner of PVG, the financial results of PVG are included in our consolidated financial statements. Because PVG controls the general partner of PVR, the financial results of PVR are included in PVG’s condensed consolidated financial statements. However, PVG and PVR function with capital structures that are independent of each other and us, with each having publicly traded common units and PVR having its own debt instruments. PVG does not currently have any debt instruments. While we report consolidated financial results of PVR’s coal and natural resources management and natural gas midstream businesses, the only cash we received from those businesses is in the form of cash distributions from PVG.

As of September 30, 2007, we owned the general partner of PVG and an approximately 82% limited partner interest in PVG. PVG owns the general partner of PVR, which holds a 2% general partner interest in PVR and all the incentive distribution rights, and an approximately 42% limited interest in PVR. We directly owned an additional 0.5% limited partner interest in PVR as of September 30, 2007. The following diagram depicts our ownership of PVG and PVR as of September 30, 2007:

LOGO

Acquisitions and Dispositions

Oil and Gas Segment

In May 2007, we acquired lease rights to property covering approximately 640 acres located in Jefferson Davis County, Mississippi, with estimated proved reserves of 11.2 Bcfe. The purchase price was $10.5 million in cash and was funded with long-term debt under our revolving credit facility. The acquisition has been recorded as a component of oil and gas properties.

In August 2007, we acquired lease rights to property covering approximately 22,700 acres located in eastern Oklahoma with estimated proved reserves of 18.8 Bcfe. The purchase price was $47.9 million in cash and was funded with long-term debt under our revolving credit facility. The acquisition has been recorded as a component of oil and gas properties. These assets include $19.2 million of unproved property and $28.7 million of proved oil and gas properties. The purchase price allocation for the acquisition has not been finalized because we are still in the process of settling various post-closing adjustments with the seller and obtaining final appraisals of assets acquired and liabilities assumed.

PVR Coal and Natural Resource Management Segment

Liquidity and Capital Resources

Although results are consolidated for financial reporting, Penn Virginia, PVG and PVR operate with independent capital structures. Since PVR’s inception in 2001 and PVG’s inception in 2006, with the exception of cash distributions paid to us by PVG and 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 PVG and PVR units. We expect that our cash needs and the cash needs of PVG and PVR will continue to be met independently of each other with a combination of these funding sources.

Cash Flows

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

The following table summarizes our cash flow statements for the nine months ended September 30, 2007 and 2006, consolidating our segments:


	Oil and Gas & Corporate			PVR			Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2007:
Net cash provided by operating activities	$	122,645		$	86,336		$	208,981

Cash flows from financing activities:
Dividends paid		(6,370	)		—			(6,370	)
PVR distributions received (paid)		29,451			(65,853	)		(36,402	)
Debt borrowings, net		193,500			146,000			339,500
Proceeds from equity issuance		—			860			860
Other		6,516			—			6,516

Net cash provided by financing activities		223,097			81,007			304,104

Net cash provided by operating and financing activities		345,742			167,343			513,085
Net cash used in investing activities		(343,283	)		(175,337	)		(518,620	)

Net increase (decrease) in cash and cash equivalents	$	2,459		$	(7,994	)	$	(5,535	)


	Oil and Gas & Corporate			PVR			Consolidated
				(in thousands)
For the Nine Months Ended September 30, 2006:
Net cash provided by operating activities	$	121,637		$	75,424		$	197,061

Cash flows from financing activities:
Dividends paid		(6,298	)		—			(6,298	)
PVR distributions received (paid)		19,816			(47,960	)		(28,144	)
Debt borrowings, net		101,000			71,500			172,500
Other		2,567			—			2,567

Net cash provided by financing activities		117,085			23,540			140,625

Net cash provided by operating and financing activities		238,722			98,964			337,686
Net cash used in investing activities		(242,767	)		(108,446	)		(351,213	)

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

Cash provided by operating activities in the oil and gas and corporate segments increased by $1.0 million, or 1%, from $121.6 million in the nine months ended September 30, 2006 to $122.6 million in the same period in 2007. The overall increase in cash provided by operating activities was primarily attributable to increased natural gas and crude oil production, partially offset by increased general and administrative expenses in the corporate segment.

Cash provided by operating activities in the PVR coal and natural resource management and PVR natural gas midstream segments increased by $10.9 million, or 15%, from $75.4 million in the nine months ended September 30, 2006 to $86.3 million in the same period in 2007. The overall increase in cash provided by operating activities was primarily attributable to an increase in PVR’s coal and natural resource management cash flows and, to a lesser extent, an increase in natural gas midstream processing cash flows.

Capital expenditures, which comprises the primary portion of cash used in investing activities, totaled $555.4 million for the nine months ended September 30, 2007, compared to $356.7 million for the nine months ended September 30, 2006. The following table sets forth capital expenditures by segment made during the periods indicated:


	Nine Months Ended September 30,
	2007		2006
	(in thousands)
Oil and gas
Proved property acquisitions	$	62,803	$	72,531
Development drilling		230,396		116,046
Exploration drilling		34,733		23,710
Seismic		2,213		4,945
Lease acquisition and other		30,653		16,998
Pipeline, gathering, facilities		14,593		11,929

Total		375,391		246,159

Coal and natural resource management
Acquisitions		145,878		66,580
Expansion capital expenditures		85		13,833
Other property and equipment expenditures		79		69

Total		146,042		80,482

Natural gas midstream
Acquisitions		—		14,626
Expansion capital expenditures		21,738		5,926
Other property and equipment expenditures		7,370		7,317

Total		29,108		27,869

Other		4,913		2,223

Total capital expenditures	$	555,454	$	356,733

During the nine months ended September 30, 2007, the oil and gas segment made aggregate capital expenditures of $375.4 million primarily for development drilling, proved property acquisitions and lease acquisitions. In September 2007, we sold non-operated working interests in oil and gas properties located in Harlan and Letcher Counties, Kentucky and Lee, Scott and Wise Counties, Virginia for $30.0 million in cash. During the nine months ended September 30, 2006, the oil and gas segment made aggregate capital expenditures of $246.2 million primarily for development drilling and proved property acquisitions. Our capital expenditures were funded with cash provided by operating activities, the sale of oil and gas working interests described above and borrowings under our revolving credit facility.

During the nine months ended September 30, 2007, PVR made aggregate capital expenditures of $175.2 million primarily for coal reserve acquisitions, a forestland acquisition and natural gas midstream gathering system expansion projects. During the nine months ended September 30, 2006, PVR made aggregate capital expenditures of $108.4 million primarily for coal reserve acquisitions and the acquisition of pipeline and compression facilities.

We funded oil and gas and other capital expenditures with cash provided by operating activities, the sale of oil and gas working interests and borrowings under our revolving credit facility. Borrowings under our revolving credit facility funded $220.5 million and $121.0 million of the oil and gas and other capital expenditures in the nine months ended September 30, 2007 and 2006, while cash provided by operating activities funded $159.8 million and $127.4 million of the capital expenditures in the nine months ended September 30, 2007 and 2006.

PVR funded capital expenditures in the nine months ended September 30, 2007 and 2006 with cash provided by operating activities and borrowings under PVR’s revolving credit facility. Borrowings, net of repayments, under PVR’s revolving credit facility funded $146.0 million and $71.5 million of the capital expenditures in the nine months ended September 30, 2007

and 2006, while cash provided by operating activities funded $29.2 million and $36.9 million of the capital expenditures in the nine months ended September 30, 2007 and 2006.

We borrowed $193.5 million, net of repayments, under our revolving credit facility in the nine months ended September 30, 2007, compared to borrowings, net of repayments, of $101.0 million for the nine months ended September 30, 2006. As a result of our partner interests in PVG and PVR, we received cash distributions of $53.1 million in the nine months ended September 30, 2007, compared to $19.8 million of cash distributions in the same period in 2006. Distributions increased by $33.3 million, or 168%, primarily due to PVR increasing its distribution per unit from $0.35 to $0.42 and the $19.6 million in distributions from PVG beginning in 2007. Funds from both of these sources were primarily used for capital expenditures. In addition, proceeds from the sale of our working interests were used to repay borrowings under our revolving credit facility.

PVR borrowed $146.0 million, net of repayments, under its revolving credit facility in the nine months ended September 30, 2007, compared to borrowings, net of repayments, of $71.5 million in the nine months ended September 30, 2006. Funds from the borrowings were primarily used for capital expenditures.

In October 2007, PVR declared a $0.43 per unit quarterly distribution for the three months ended September 30, 2007, or $1.72 per unit on an annualized basis. The distribution will be paid on November 19, 2007 to unitholders of record at the close of business on November 5, 2007. The portion of PVR’s distribution paid to PVG serves as the basis for PVG’s distribution to its unitholders, including us. In October 2007, PVG declared a $0.30 per unit quarterly distribution for the three months ended September 30, 2007, or $1.20 per unit on an annualized basis, of which we will receive $9.6 million as a result of our partner interests in PVG. This distribution will be paid on November 14, 2007 to unitholders of record at the close of business on November 5, 2007.

Long-Term Debt

Revolving Credit Facility. As of September 30, 2007, we had $414.5 million outstanding under our $450 million revolving credit facility (the “Revolver”) that matures in December 2010. The Revolver is secured by a portion of our proved oil and gas reserves. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $20 million sublimit for the issuance of letters of credit. We had outstanding letters of credit of $0.4 million as of September 30, 2007. Effective October 5, 2007, we amended the Revolver to increase the commitments from $450 million to $525 million. At the current $525 million limit on the Revolver, and given our outstanding balance of $414.5 million, net of $0.4 million of letters of credit, we could borrow up to $110.1 million. In the nine months ended September 30, 2007, we incurred commitment fees of $0.4 million on the unused portion of the Revolver. We capitalized $3.0 million of interest cost incurred in the nine months ended September 30, 2007. The Revolver is governed by a borrowing base calculation. Our borrowing base is currently $525 million 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%, based on the ratio of our outstanding borrowings to the borrowing base or (ii) the greater of the prime rate or federal funds rate plus a margin of up to 0.50%. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2007 was 6.4%.

The financial covenants under the Revolver require us to not exceed specified debt-to-EBITDAX and EBITDAX-to-interest expense ratios 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, 2007, we were in compliance with all of our covenants under the Revolver.

Credit Facility. We have a credit facility with a financial institution, which had no borrowings against it as of September 30, 2007. The facility is effective through August 31, 2008 and is renewable annually. The facility consists of a working capital facility in the amount of $10 million. An additional $10 million facility is available upon bank approval. The interest rate on the working capital facility is equal to the LIBOR plus 1.00% and the interest rate on the additional facility is equal to the LIBOR plus an applicable margin ranging from 1.00% to 1.50%.

Revolver Interest Rate Swaps. We entered into interest rate swap agreements (the “Revolver Swaps”) to swap $50 million of outstanding borrowings under the Revolver from a variable rate to a weighted average fixed rate of 5.34% plus the applicable margin. 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 in interest expense. After considering the applicable margin of 1.75% in effect as of September 30, 2007, the total interest rate on the $50 million portion of Revolver borrowings covered by the Revolver Swaps was 7.09% at September 30, 2007.

PVR Revolving Credit Facility. As of September 30, 2007, PVR had $300.2 million outstanding under its $450 million unsecured revolving credit facility (the “PVR Revolver”) that matures in December 2011. The PVR Revolver is available to PVR for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. PVR had outstanding letters of credit of $1.6 million as of September 30, 2007. At the current $450 million limit on the PVR Revolver, and given PVR’s outstanding balance of $300.2 million, net of $1.6 million of letters of credit, PVR could borrow up to $148.2 million. In the nine months ended September 30, 2007, PVR incurred commitment fees of $0.5 million on the unused portion of the PVR Revolver. On September 7, 2007, PVR increased the commitments under the Revolver from $300 million to $450 million. The interest rate under the PVR Revolver fluctuates based on the ratio of PVR’s total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 0.75% if PVR selects the base rate borrowing option under the PVR Revolver or at a rate derived from the London Inter Bank Offering Rate (“LIBOR”) plus an applicable margin ranging from 0.75% to 1.75% if PVR selects the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the PVR Revolver during the nine months ended September 30, 2007 was 5.9%.

The financial covenants under the PVR Revolver require PVR not to exceed specified debt-to-consolidated EBITDA and consolidated EBITDA-to-interest expense ratios. The PVR Revolver prohibits PVR from making distributions to its partners if any potential default, or event of default, as defined in the PVR Revolver, occurs or would result from the 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 its 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, 2007, PVR was in compliance with all of its covenants under the PVR Revolver.

PVR Senior Unsecured Notes. As of September 30, 2007, PVR owed $64.0 million under its senior unsecured notes (the “Notes”). The Notes bear interest at a fixed rate of 6.02% and mature in March 2013, with semi-annual principal and interest payments. The Notes are equal in right of payment with all of PVR’s other unsecured indebtedness, including the PVR Revolver. The Notes require PVR to obtain an annual confirmation of its credit rating, with a 1.00% increase in the interest rate payable on the Notes in the event that PVR’s credit rating falls below investment grade. In March 2007, PVR’s investment grade credit rating was confirmed by Dominion Bond Rating Services. The Notes contain various covenants similar to those contained in the PVR Revolver. As of September 30, 2007, PVR was in compliance with all of its covenants under the Notes.

PVR 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% 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 1.00% in effect as September 30, 2007, the total interest rate on the $60 million portion of PVR Revolver borrowings covered by the PVR Revolver Swaps was 5.22% at September 30, 2007.

Future Capital Needs and Commitments

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 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.

Including property acquisitions completed to date, we expect to make oil and gas segment capital expenditures of $486.0 million to $500.0 million in 2007. These expenditures are expected to be funded primarily by operating cash flow, cash distributions received from PVG and PVR and from the Revolver as needed. 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 operating activities and sources of debt financing are sufficient to fund our 2007 planned oil and gas capital expenditure program.

We believe our portfolio of assets provides us with opportunities for organic growth in 2008 which will require capital in excess of our internal sources. We expect to continue to rely on the Revolver to fund a large portion of our capital needs, supplemented by the issuance of additional debt and equity securities as needed.

Part of PVR’s strategy is to make acquisitions and other capital expenditures which increase cash available for distribution to its unitholders. 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. Including property acquisitions completed to date, PVR anticipates making capital expenditures in 2007 of $175.5 million to $185.7 million for coal reserve acquisitions, forestland acquisitions, oil and gas royalty acquisitions, coal services projects and other property and equipment and $50.0 million to $53.0 million for natural gas midstream system expansion projects and maintenance capital expenditures. PVR intends to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the PVR Revolver. PVR makes quarterly cash distributions of its available cash, generally defined as all of its cash and cash equivalents on hand at the end of each quarter less cash reserves. 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 PVR’s general partner and unitholders, are expected to be funded through operating cash flows. 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.

We have budgeted other capital expenditures of approximately $6 million to $8 million in 2007 for administrative purposes, including the implementation of a new accounting software system.

Results of Operations

Selected Financial Data—Consolidated

The following table sets forth a summary of certain consolidated financial data for the periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(in thousands, except per share data)
Revenues	$	215,758	$	188,393	$	624,426	$	568,450
Expenses		163,874		143,749		476,929		425,201

Operating income	$	51,884	$	44,644	$	147,497	$	143,249
Net income	$	17,114	$	22,881	$	45,395	$	65,206
Earnings per share, basic	$	0.45	$	0.61	$	1.20	$	1.75
Earnings per share, diluted	$	0.45	$	0.61	$	1.19	$	1.73
Cash flows provided by operating activities	$	76,184	$	47,161	$	208,981	$	197,061

Operating income increased in the three months and nine months ended September 30, 2007 compared to the same periods in 2006 primarily due to increases in operating income from the oil and gas and the natural gas midstream segments, partially offset by decreases in operating income from the coal and natural resources management segment.

Net income decreased in the three months ended September 30, 2007 compared to the same period in 2006 primarily due to a $22.4 million increase in derivative losses and a $3.7 million increase in interest expense, partially offset by the corresponding $3.5 million decrease in income tax expense and the $7.3 million increase in operating income. Net income decreased in the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to a $33.5 million increase in derivative losses and a $8.6 million increase in interest expense, partially offset by the corresponding $13.1 million decrease in income tax expense and the $4.3 million increase in operating income.

The assets, liabilities and earnings of PVG are fully consolidated in our financial statements, with the public unitholders’ interest (18% as of September 30, 2007) reflected as a minority interest in our consolidated financial statements. The assets, liabilities and earnings of PVR are fully consolidated in PVG’s financial statements, with the public unitholders’ interest (47%, after the effect of incentive distribution rights, as of September 30, 2007) reflected as minority interest in PVG’s condensed consolidated financial statements.

Oil and Gas Segment

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the periods indicated:


	Three Months Ended September 30,				% Change		Three Months Ended September 30,
	2007		2006		% Change		2007		2006
	(in thousands, except as noted)						(per Mcfe) (1)
Production
Natural gas (Mmcf)		10,406		7,332	42	%
Oil and condensate (thousand barrels)		116		97	20	%
Total production (Mmcfe)		11,102		7,914	40	%
Revenues
Natural gas	$	65,310	$	50,540	29	%	$	6.28	$	6.89
Oil and condensate		7,589		5,964	27	%		65.42		61.48
Gain on the sale of properties		12,312		—
Other income		120		402

Total revenues		85,331		56,906	50	%		7.69		7.19

Expenses
Operating		12,247		7,882	55	%		1.10		1.00
Taxes other than income		4,380		1,750	150	%		0.39		0.22
General and administrative		4,124		3,181	30	%		0.37		0.40

Production costs		20,751		12,813	62	%		1.87		1.62
Exploration		12,873		12,660	2	%		1.16		1.60
Impairment of oil and gas properties		2,405		—	—			0.22		—
Depreciation, depletion and amortization		22,152		13,365	66	%		2.00		1.69

Total expenses		58,181		38,838	50	%		5.24		4.91

Operating income	$	27,150	$	18,068	50	%	$	2.45	$	2.28

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

Production. Approximately 94% and 93% of production in the three months ended September 30, 2007 and 2006 was natural gas. Total production increased by 3.2 Bcfe, or 40%, from 7.9 Bcfe in the three months ended September 30, 2006 to 11.1 Bcfe in the same period in 2007 primarily due to increased natural gas production from new wells in the Mississippi, Oklahoma, east Texas and Gulf Coast regions. The increase in production was also due to $54.3 million in proved property acquisitions in the three months ended September 30, 2007, compared to none in the same period in 2006, and $90.1 million in oil and gas drilling in the three months ended September 30, 2007, compared to $55.0 million in the same period in 2006.

We drilled a total of 58 gross (43.6 net) development wells during the three months ended September 30, 2007 and three gross (0.7 net) exploratory wells. All wells were successful except one gross (1.0 net) development well.

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,		Three Months Ended September 30,
Region	2007	2006	2007		2006
	(MMcfe)		(in thousands)
Appalachia	3,376	3,243	$	21,843	$	22,711
Gulf Coast	2,364	1,210		17,626		10,961
Mississippi	2,015	1,556		13,551		10,598
East Texas	2,092	1,359		12,999		8,790
Mid-Continent	1,255	546		6,880		3,444

Total	11,102	7,914	$	72,899	$	56,504

Revenues. Natural gas revenues increased by $14.8 million, or 29%, from $50.5 million in the three months ended September 30, 2006 to $65.3 million in the same period in 2007 primarily due to increased natural gas production. Of the $14.8 million increase, $21.8 million was the result of increased natural gas production, partially offset by a $7.0 million decrease resulting from lower realized prices for natural gas. Our average realized price received for natural gas decreased by $0.61 per Mcf, or 9%, from $6.89 per Mcf in the three months ended September 30, 2006 to $6.28 per Mcf in the same period in 2007. Oil and condensate revenues increased by $1.6 million, or 27%, from $6.0 million in the three months ended September 30, 2006 to $7.6 million in the same period in 2007 primarily due to increased oil and condensate production and increased crude oil prices. Of the $1.6 million increase, $1.2 million was the result of increased oil production and $0.4 million was the result of increased realized prices for crude oil. Our average realized price received for oil increased by $3.94 per barrel, or 6%, from $61.48 per barrel in the three months ended September 30, 2006 to $65.42 per barrel in the same period in 2007.

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. Beginning in May 2006, none of our derivative contracts follow hedge accounting. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. 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 shows a summary of the effects of derivative activities on revenues and realized prices for the three months ended September 30, 2007 and 2006:


	Three Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(per Mcf)
Natural gas revenues, as reported	$	65,310		$	50,540		$	6.28		$	6.89
Derivatives (gains) losses included in natural gas revenues		166			(663	)		0.02			(0.09	)

Natural gas revenues before impact of derivatives		65,476			49,877			6.29			6.80
Cash settlements on natural gas derivatives		5,372			3,147			0.52			0.43

Natural gas revenues, adjusted for derivatives	$	70,849		$	53,024		$	6.81		$	7.23


							(per Bbl)
Crude oil revenues, as reported	$	7,589		$	5,964		$	65.42		$	61.48
Derivatives (gains) losses included in oil and condensate revenues		126			103			1.09			1.06

Oil and condensate revenues before impact of derivatives		7,715			6,067			66.51			62.55
Cash settlements on crude oil derivatives		(84	)		(19	)		(0.72	)		(0.20	)

Oil and condensate revenues, adjusted for derivatives	$	7,631		$	6,048		$	65.78		$	62.35

Gain on the Sale of Properties.In the three months ended September 30, 2007, we recognized a $12.4 million gain on our September 2007 sale of non-operated working interests in oil and gas properties.

Expenses. Aggregate operating costs and expenses increased by $19.7 million, or 51%, from $38.8 in the three months ended September 30, 2006 to $58.5 million in the same period in 2007 primarily due to increases in operating expenses, taxes other than income, impairment expense and depreciation, depletion and amortization (“DD&A”) expenses.

Operating expenses increased by $4.3 million, or 55%, from $7.9 million, or $1.00 per Mcfe, in the three months ended September 30, 2006 to $12.2 million, or $1.09 per Mcfe, in the same period in 2007 primarily due to increased repair and maintenance charges, gathering, transportation and processing charges and compressor rental charges resulting from increased production in the east Texas and Appalachian regions. The acquisition of our Mid-Continent assets and the related well operating costs also contributed to the increase in operating expenses.

Taxes other than income increased by $2.9 million, or 170%, from $1.8 million in the three months ended September 30, 2006 to $4.7 million in the same period in 2007 primarily due to a severance tax refund related to production in the Cotton Valley play and property tax adjustments in West Virginia received in the three months ended September 30, 2006.

General and administrative expenses increased by $0.9 million, or 30%, from $3.2 million in the three months ended September 30, 2006 to $4.1 million in the same period in 2007 primarily due to increased staffing and benefits costs related to an expansion of operations across the oil and gas segment and increased drilling activity and acquisitions.

Exploration expenses in the three months ended September 30, 2007 and 2006 consisted of the following:


	Three Months Ended September 30,
	2007		2006
	(in thousands)
Dry hole costs	$	6,318	$	6,697
Geological and geophysical		627		1,425
Unproved leasehold		5,664		2,898
Other		264		1,640

Total	$	12,873	$	12,660

Exploration expenses increased by $0.2 million, or 2%, from $12.7 million in the three months ended September 30, 2006 to $12.9 million in the same period in 2007 primarily due to increased unproved leasehold expenses, partially offset by decreases in dry hole costs, geological and geophysical expenses and other costs. Geological and geophysical expenses decreased primarily due to a decrease in core-hole drilling as well as the timing of seismic data purchases. The increase in unproved leasehold expenses was primarily due to a $2.7 million write-off of a prospect in the Williston basin. The decrease in dry hole costs was primarily due to the write-off of one exploratory well in the east Texas region and one exploratory well in the Gulf Coast region in the three months ended September 30, 2007, compared to the write-off of two exploratory wells in the Appalachian region and three exploratory wells in the Gulf Coast region in the same period in 2006. The decrease in other costs was primarily due a decrease in delay rental payments. In the three months ended September 30, of 2006, we incurred $1.7 million of delay rental charges due to delays in our drilling program in Louisiana.

We recorded $2.4 million of impairment charges in the three months ended September 30, 2007 related to changes in estimates of the reserve bases of several relatively small fields in the Gulf Coast and Mid-Continent regions.

DD&A expenses increased by $8.8 million, or 66%, from $13.4 million in the three months ended September 30, 2006 to $22.2 million in the same period in 2007 primarily due to the 41% increase in equivalent production and higher depletion rates. Our average depletion rate increased from $1.69 per Mcfe in the three months ended September 30, 2006 to $2.00 per Mcfe in the three months ended September 30, 2007 primarily due to a greater percentage of production coming from our Mid-Continent properties acquired in 2006 and our relatively higher-cost horizontal CBM and Cotton Valley wells.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for our oil and gas segment and the percentage change for the periods indicated:


	Nine Months Ended September 30,				% Change		Nine Months Ended September 30,
	2007		2006		% Change		2007		2006
	(in thousands, except as noted)						(per Mcfe) (1)
Production
Natural gas (Mmcf)		27,872		21,009	33	%
Oil and condensate (thousand barrels)		336		283	19	%
Total production (Mmcfe)		29,888		22,707	32	%
Revenues
Natural gas	$	193,961	$	160,384	21	%	$	6.96	$	7.63
Oil and condensate		18,443		16,378	13	%		54.89		57.87
Gain on the sale of properties		12,239		—
Other income		868		1,521	(43	%)

Total revenues		225,511		178,283	26	%		7.55		7.85

Expenses
Operating		31,190		19,490	60	%		1.04		0.86
Taxes other than income		13,249		9,162	45	%		0.44		0.40
General and administrative		11,026		8,649	27	%		0.37		0.38

Production costs		55,465		37,301	49	%		1.86		1.64
Exploration		23,610		26,061	(9	%)		0.79		1.15
Impairment of oil and gas properties		2,405		—	0	%		0.08		—
Depreciation, depletion and amortization		58,628		38,755	51	%		1.96		1.71

Total expenses		140,108		102,117	37	%		4.69		4.50

Operating income	$	85,403	$	76,166	12	%	$	2.86	$	3.35

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

Production.Approximately 93% of production in the nine months ended September 30, 2007 and 2006 was natural gas. Total production increased by 7.2 million, or 32%, from 22.7 Bcfe in the nine months ended September 30, 2006 to 29.9 Bcfe in the same period in 2007 primarily due to increased natural gas production in the east Texas, Gulf Coast, Mid-Continent and Mississippi regions, partially offset by a decrease in production in the Appalachian region. The increase in production was also due to $265.1 million in oil and gas drilling in the nine months ended September 30, 2007, compared to $139.8 million in the same period in 2006.

We drilled a total of 196 gross (149.4 net) development wells during the nine months ended September 30, 2007 and 10 gross (3.7 net) exploratory wells. All wells were successful except three gross (2.6 net) development wells.

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
	Nine Months Ended September 30,		Nine Months Ended September 30,
Region	2007	2006	2007		2006
	(MMcfe)		(in thousands)
Appalachia	9,425	9,718	$	66,817	$	75,947
Gulf Coast	6,566	4,609		50,480		37,275
Mississippi	5,663	4,644		40,606		35,787
East Texas	5,307	3,084		37,436		23,737
Mid-Continent	2,927	652		17,065		4,016

Total	29,888	22,707	$	212,404	$	176,762

Revenues. Natural gas revenues increased by $33.6 million, or 21%, from $160.4 million in the nine months ended September 30, 2006 to $194.0 million in the same period in 2007 primarily due to increased natural gas production, partially offset by decreased realized prices for natural gas. Of the $33.6 million increase in natural gas revenues, $53.1 million was the result of increased natural gas production, partially offset by a $19.4 million decrease resulting from lower realized prices for natural gas. Our average realized price received for natural gas decreased by $0.67 per Mcf, or 9%, from $7.63 per Mcf in the nine months ended September 30, 2006 to $6.96 per Mcf in the same period in 2007. Oil and condensate revenues increased by $2.0 million, or 13%, from $16.4 million in the nine months ended September 30, 2006 to $18.4 million in the same period in 2007 primarily due to increased oil and condensate production, partially offset by decreased crude oil prices. Of the $2.0 million increase in oil and condensate revenues, $3.0 million was the result of increased oil production, partially offset by a $1.0 million decrease resulting from decreased realized prices for crude oil. Our average realized price for oil decreased by $2.98, or 5%, from $57.87 per barrel in the nine months ended September 30, 2006 to $54.89 per barrel in the same period in 2007.


	Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(per Mcf)
Natural gas revenues, as reported	$	193,961		$	160,384		$	6.96		$	7.63
Derivatives (gains) losses included in natural gas revenues		(315	)		(247	)		(0.01	)		(0.01	)

Natural gas revenues before impact of derivatives		193,646			160,137			6.95			7.62
Cash settlements on natural gas derivatives		11,241			5,181			0.40			0.25

Natural gas revenues, adjusted for derivatives	$	204,887		$	165,318		$	7.35		$	7.87


							(per Bbl)
Crude oil revenues, as reported	$	18,443		$	16,378		$	54.89		$	57.87
Derivatives (gains) losses included in oil and condensate revenues		383			333			1.14			1.18

Oil and condensate revenues before impact of derivatives		18,826			16,711			56.03			59.05
Cash settlements on crude oil derivatives		3			(209	)		0.01			(0.74	)

Oil and condensate revenues, adjusted for derivatives	$	18,829		$	16,502		$	56.04		$	58.31

Gain on the Sale of Properties.In the nine months ended September 30, 2007, we recognized a $12.4 million gain on our September 2007 sale of non-operated working interests in oil and gas properties.

Expenses. Aggregate operating costs and expenses increased by $38.3 million, or 38%, from $102.1 million in the nine months ended September 30, 2006 to $140.5 million in the same period in 2007 primarily due to increases in operating expenses, taxes other than income, general and administrative expenses and DD&A expenses, partially offset by a decrease in exploration expenses.

Operating expenses increased by $11.7 million, or 60%, from $19.5 million in the nine months ended September 30, 2006 to $31.2 million in the same period in 2007. In addition to a general increase in oilfield service costs and activity in all operating areas, the increase was due to the production increase and additional expenses in a number of operating areas related to workovers, water disposal, compression and maintenance.

Taxes other than income increased by $4.4 million, or 48%, from $9.2 million in the nine months ended September 30, 2006 to $13.6 million in the same period in 2007 primarily due to the production increase and a severance tax refund related to production in the cotton Valley play and property tax adjustments in West Virginia received in the nine months ended September 30, 2006.

General and administrative expenses increased by $2.4 million, or 27%, from $8.6 million in the nine months ended September 30, 2006 to $11.0 million in the same period in 2007 primarily due to increased staffing and benefits costs related to an expansion of operations across the oil and gas segment and increased drilling activity and acquisitions.

Exploration expenses for the nine months ended September 30, 2007 and 2006 consisted of the following:


	Nine Months Ended September 30,
	2007		2006
	(in thousands)
Dry hole costs	$	10,045	$	12,533
Geological and geophysical		2,209		5,064
Unproved leasehold		10,401		5,406
Other		955		3,058

Total	$	23,610	$	26,061

Exploration expenses decreased by $2.5 million, or 9%, from $26.1 million in the nine months ended September 30, 2006 to $23.6 million in the same period in 2007 primarily due to decreases in dry hole costs, geological and geophysical expenses and other costs, partially offset by an increase in unproved leasehold expenses. The decrease in dry hole costs was primarily due to the write-off of three exploratory wells in the Gulf Coast region and one exploratory well in the east Texas region in the nine months ended September 30, 2007, compared to the write-off of six exploratory wells in the Gulf Coast region, two exploratory wells in the Appalachian region and one exploratory well in the east Texas region in the same period in 2006. Geological and geophysical expenses decreased primarily due to a decrease in core-hole drilling as well as the timing of seismic data purchases. The decrease in other costs was primarily due to a decrease in delay rental payments. In the nine months ended September 30, 2006, we incurred $1.7 million of delay rental charges due to delays in our drilling program in Louisiana and $0.6 million of delay rental charges due to delays in our drilling program in West Virginia. The increase in unproved leasehold expenses was primarily due to the amortization of unproved properties acquired over the past year, as well as a $2.7 million write-off of a prospect in the Williston basin.

We recorded $2.4 million of impairment charges in the nine months ended September 30, 2007 related to changes in estimates of the reserve bases of fields in the Gulf Coast and Mid-Continent regions.

DD&A expenses increased by $19.9 million, or 51%, from $38.7 million in the nine months ended September 30, 2006 to $58.6 in the same period in 2007 primarily due to the 32% increase in equivalent production and higher depletion rates. Our average depletion rate increased from $1.71 per Mcfe in the nine months ended September 30, 2006 to $1.96 per Mcfe in the nine months ended September 30, 2007 primarily due to a greater percentage of production coming from our Mid-Continent properties acquired in 2006 and our relatively higher-cost horizontal CBM and Cotton Valley wells.

PVR Coal and Natural Resource Management Segment

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the periods indicated:


	Three Months Ended September 30,				% Change
	2007		2006		% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	24,426	$	26,612	(8	%)
Coal services		1,955		1,515	29	%
Other		2,035		1,763	15	%

Total revenues		28,416		29,890	(5	%)

Expenses
Coal royalties expense		979		2,893	(66	%)
Other operating		1,020		447	128	%
Taxes other than income		242		154	57	%
General and administrative		2,630		2,095	26	%
Depreciation, depletion and amortization		5,833		5,551	5	%

Total expenses		10,704		11,140	(4	%)

Operating income	$	17,712	$	18,750	(6	%)

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,842		8,781	1	%
Average royalty per ton ($/ton)	$	2.76	$	3.03	(9	%)

Revenues. Coal royalties revenues decreased by $2.2 million, or 8%, from $26.6 million in the three months ended September 30, 2006 to $24.4 million in the same period in 2007. Tons produced by PVR’s lessees remained relatively constant in the three months ended September 30, 2007 compared to the same period in 2006. The mix of production shifted from the prior year’s quarter, with higher lessee production in the Illinois Basin, the San Juan Basin and Northern Appalachia, which have lower average coal royalties per ton, offset by lower lessee production in Central Appalachia, which has higher average coal royalties per ton. Primarily due to the combination of increased production in the relatively lower royalty rate Illinois Basin and reduced production in Central Appalachia, PVR’s average gross royalty per ton decreased by $0.27, or 9%, from $3.03 in the three months ended September 30, 2006 to $2.76 in the same period in 2007. Net of coal royalties expense, PVR’s average royalty per ton decreased $0.05, or 2%, from $2.70 in the three months ended September 30, 2006 to $2.65 in the same period in 2007.

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


	Coal Production		Coal Royalties Revenues
	Three Months Ended September 30,		Three Months Ended September 30,
Property	2007	2006	2007		2006
	(tons in thousands)		(in thousands)
Central Appalachia	4,660	5,494	$	16,799	$	20,971
Northern Appalachia	1,338	1,305		2,051		1,893
Illinois Basin	1,292	550		2,470		1,055
San Juan Basin	1,552	1,432		3,106		2,693

Total	8,842	8,781	$	24,426	$	26,612

Coal services revenues increased by $0.5 million, or 29%, from $1.5 million in the three months ended September 30, 2006 to $2.0 million in the same period in 2007 primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. In the three months ended September 30, 2007, the facility in Knott County, Kentucky contributed $0.4 million to coal services revenues.

Other revenues increased by $0.2 million, or 15%, from $1.8 million in the three months ended September 30, 2006 to $2.0 million in the same period in 2007 primarily due to an increase in wheelage income from PVR’s Central Appalachian properties.

Expenses. Coal royalties expense decreased by $1.9 million, or 66%, from $2.9 million in the three months ended September 30, 2006 to $1.0 million in the same period of 2007 primarily due to a decrease in production from property we sublease in Central Appalachia. Other operating expenses increased by $0.6 million, or 128%, from $0.4 million in the three months ended September 30, 2006 to $1.0 million in for the same period in 2007 primarily due to an increase in mine maintenance and core-hole drilling expenses on our Central Appalachian and Illinois Basin properties. General and administrative expenses increased by $0.5 million, or 26%, from $2.1 million in the three months ended September 30, 2006 to $2.6 million in the same period in 2007 primarily due to increased staffing costs. DD&A expenses increased by $0.2 million, or 5%, from $5.6 million in the three months ended September 30, 2006 to $5.8 million in the same period in 2007 primarily due to depreciation on new coal services facilities.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for the PVR coal and natural resource management segment and the percentage change for the periods indicated:


	Nine Months Ended September 30,				% Change
	2007		2006		% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	73,455	$	73,288	0	%
Coal services		5,648		4,345	30	%
Other		6,207		5,482	13	%

Total revenues		85,310		83,115	3	%

Expenses
Coal royalties expense		4,582		4,411	4	%
Other operating		2,086		1,152	81	%
Taxes other than income		832		565	47	%
General and administrative		7,989		6,794	18	%
Depreciation, depletion and amortization		16,643		15,050	11	%

Total expenses		32,132		27,972	15	%

Operating income	$	53,178	$	55,143	(4	%)

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		25,186		24,467	3	%
Average royalty per ton ($/ton)	$	2.92	$	3.00	(3	%)

Revenues. Coal royalties revenues remained relatively constant in the nine months ended September 30, 2007 compared to the same period in 2006. Tons produced by PVR’s lessees increased by 0.7 million tons, or 3%, from 24.5 million tons in the nine months ended September 30, 2006 to 25.2 million tons in the same period in 2007. PVR’s average gross royalty per ton decreased by $0.08, or 3%, from $3.00 in the nine months ended September 30, 2006 to $2.92 in the same period in 2007. Net of coal royalties expense, PVR’s average royalty per ton decreased $0.09, or 3%, from $2.82 in the nine months ended September 30, 2006 to $2.73 in the same period in 2007. This decrease was primarily due to a shift in the mix of coal production by PVR’s lessees, with higher lessee production in the Illinois Basin and the San Juan Basin, which have lower average coal royalties per ton, partially offset by lower lessee production in Central Appalachia, which has higher average coal royalties per ton.

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


	Coal Production		Coal Royalties Revenues
	Nine Months Ended September 30,		Nine Months Ended September 30,
Property	2007	2006	2007		2006
	(tons in thousands)		(in thousands)
Central Appalachia	14,635	14,933	$	53,983	$	56,892
Northern Appalachia	3,787	3,929		5,808		5,746
Illinois Basin	2,413	1,891		4,957		3,666
San Juan Basin	4,351	3,714		8,707		6,984

Total	25,186	24,467	$	73,455	$	73,288

Coal services revenues increased by $1.3 million, or 30%, from $4.3 million in the nine months ended September 30, 2006 to $5.6 million in the same period in 2007 primarily due the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. In the nine months ended September 30, 2007, the facility in Knott County, Kentucky contributed $1.1 million to coal services revenues.

Other revenues increased by $0.7 million, or 13%, from $5.5 million in the nine months ended September 30, 2006 to $6.2 million in the same period in 2007 primarily due to an increase in wheelage income from PVR’s Central Appalachian properties.

Expenses. Coal royalties expense increased by $0.2 million, or 4%, from $4.4 million in the nine months ended September 30, 2006 to $4.6 million in the same period in 2007 primarily due to an increase in production from property we sublease in Central Appalachia, where royalties per ton are higher. Other operating expenses increased by $0.9 million, or 81%, from $1.2 million in the nine months ended September 30, 2006 to $2.1 million in the same period in 2007 primarily due to an increase in mine maintenance and core-hole drilling expenses on our central Appalachian and Illinois Basin properties. General and administrative expenses increased by $1.2 million, or 18%, from $6.8 million in the nine months ended September 30, 2006 to $8.0 million in the same period in 2007 primarily due to increased staffing costs and corporate reimbursements to our general partner. DD&A expenses increased by $1.5 million, or 11%, from $15.1 million in the nine months ended September 30, 2006 to $16.6 million in the same period in 2007 primarily due to depreciation of new of coal services facilities.

PVR Natural Gas Midstream Segment

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the periods indicated:


	Three Months Ended September 30,				% Change
	2007		2006		% Change
	(in thousands)
Financial Highlights
Revenues
Residue gas	$	52,343	$	62,408	(16	%)
Natural gas liquids		42,510		35,363	20	%
Condensate		3,251		2,323	40	%
Gathering and transportation fees		2,266		715	217	%

Total natural gas midstream revenues		100,370		100,809	(0	%)
Producer services		1,418		795	78	%

Total revenues		101,788		101,604	0	%

Expenses
Cost of midstream gas purchased		76,192		80,272	(5	%)
Operating		3,225		3,038	6	%
Taxes other than income		424		329	29	%
General and administrative		3,076		2,504	23	%
Depreciation and amortization		4,812		4,313	12	%

Total operating expenses		87,729		90,456	(3	%)

Operating income	$	14,059	$	11,148	26	%

Operating Statistics
System throughput volumes (MMcf)		17,844		16,586	8	%
Gross processing margin	$	24,178	$	20,537	18	%

Revenues. Natural gas midstream revenues remained relatively constant in the three months ended September 30, 2007 compared to the same period in 2006. Revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput 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 its gathering systems and processing plants. The pricing environment was such that the decrease in PVR’s realized prices for natural gas was offset by increases in PVR’s realized prices for NGLs and condensate. Gathering and transportation revenues benefited from a short-term gathering contract that was entered into and completed during the three months ended September 30, 2007. These gathered volumes contributed to PVR’s overall system throughput increase but did not result in a corresponding increase in throughput volumes at PVR’s processing plants because the volumes were delivered off of the gathering system prior to reaching the processing plant.

Producer services revenues increased by $0.6 million, or 78%, from $0.8 million in the three months ended September 30, 2006 to $1.4 million in the same period in 2007 primarily due to an increase in marketed gas volumes.

Expenses. Operating costs and expenses decreased due to a decrease in the cost of midstream gas purchased, partially offset by minor increases in operating expenses, taxes other than income, general and administrative expenses and DD&A expenses.

Cost of midstream gas purchased decreased by $4.1 million, or 5%, from $80.3 million in the three months ended September 30, 2006 to $76.2 million in the same period in 2007 primarily due to the decrease in realized natural gas prices. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

PVR’s gross processing margin is the difference between its natural gas midstream revenues and its cost of midstream gas purchased. PVR’s gross processing margin increased by $3.7 million, or 18%, from $20.5 million in the three months ended September 30, 2006 to $24.2 million in the same period in 2007 primarily due to a higher frac spread caused by higher NGL sale prices and lower natural gas purchase prices.

System throughput volumes at PVR’s gas processing plants and gathering systems increased by 14 MMcfd, or 8%, from 180 MMcfd in the three months ended September 30, 2006 to 194 MMcfd in the same period in 2007 primarily due to a short-term gathering contract that was entered into and completed in the third quarter of 2007.

PVR’s natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the three months ended September 30, 2007, PVR generated a majority of its gross margin from contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. The following table shows a summary of the effects of derivative activities on PVR’s gross processing margin:


	Three Months Ended September 30,
	2007			2006
	(in thousands)
Gross processing margin, as reported	$	24,178		$	20,537
Derivatives (gains) losses included in gross processing margin		1,304			825

Gross processing margin before impact of derivatives		25,482			21,362
Cash settlements on derivatives		(4,702	)		(7,344	)

Gross processing margin, adjusted for derivatives	$	20,780		$	14,018

Operating expenses increased by $0.2 million, or 6%, from $3.0 million in the three months ended September 30, 2006 to $3.2 million in the same period in 2007. DD&A expenses increased by $0.5 million, or 12%, from $4.3 million in the three months ended September 30, 2006 to $4.8 million in the same period in 2007. Both increases were due to acquisitions and gathering system construction. General and administrative expenses increased by $0.6 million, or 23%, from $2.5 million in the three months ended September 30, 2006 to $3.1 million in the same period in 2007 primarily due to increased staffing costs.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for the PVR natural gas midstream segment and the percentage change for the periods indicated:


	Nine Months Ended September 30,				% Change
	2007		2006		% Change
	(in thousands)
Financial Highlights
Revenues
Residue gas	$	181,407	$	199,096	(9	%)
Natural gas liquids		115,660		97,591	19	%
Condensate		9,324		7,165	30	%
Gathering and transportation fees		3,704		1,488	149	%

Total natural gas midstream revenues		310,095		305,340	2	%
Producer services		3,143		1,666	89	%

Total revenues		313,238		307,006	2	%

Expenses
Cost of midstream gas purchased		251,000		254,615	(1	%)
Operating		9,567		8,387	14	%
Taxes other than income		1,280		1,054	21	%
General and administrative		9,119		8,209	11	%
Depreciation and amortization		13,957		12,451	12	%

Total operating expenses		284,923		284,716	0	%

Operating income	$	28,315	$	22,290	27	%

Operating Statistics
System throughput volumes (MMcf)		50,763		45,234	12	%
Gross processing margin	$	59,095	$	50,725	17	%

Revenues. Natural gas midstream revenues increased by $4.8 million, or 2%, from $305.3 million in the nine months ended September 30, 2006 to $310.1 million in the same period in 2007 primarily due to a more favorable pricing environment combined with increased system throughput volumes. A June 2006 pipeline acquisition and a short-term gathering contract that was entered into and completed during third quarter of 2007 contributed to the volume increase. Revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput 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.

Producer services revenues increased by $1.4 million, or 89%, from $1.7 million in the nine months ended September 30, 2006 to $3.1 million in the same period in 2007 primarily due to an increase in marketed gas volumes.

Expenses. Operating costs and expenses were relatively constant in the nine months ended September 30, 2007 compared to the same period in 2006.

Cost of midstream gas purchased decreased by $3.6 million, or 1%, from $254.6 million in the nine months ended September 30, 2006 to $251.0 million in the same period in 2007. There was a $4.6 million non-cash charge recorded to reserves in the nine months ended September 30, 2006 for amounts related to balances assumed as part of the acquisition of PVR’s natural gas midstream business in 2005. Excluding this reserve, the cost of midstream gas purchased increased for the comparative periods. Higher volumes, partially offset by lower realized natural gas prices, accounted for the increase, excluding the non-cash charge, in the cost of midstream gas purchased. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

PVR’s gross processing margin for its natural gas midstream operations increased by $8.4 million, or 17%, from $50.7 million in the nine months ended September 30, 2006 to $59.1 million in the same period in 2007 primarily due to a more favorable pricing environment and higher system throughput volumes.

System throughput volumes at PVR’s gas processing plants and gathering systems increased by 20 MMcfd, or 12%, from 166 MMcfd in the nine months ended September 30, 2006 to 186 MMcfd in the same period in 2007 primarily due to the June 2006 pipeline acquisition, a short-term gathering contract that was entered into and completed in the third quarter of 2007, successful drilling of local producers and expansion of PVR’s current facilities.

PVR’s natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the nine months ended September 30, 2007, PVR generated a majority of its gross margin from contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of PVR’s risk management strategy, PVR uses derivative financial instruments to economically hedge NGLs sold and natural gas purchased. The following table shows a summary of the effects of derivative activities on PVR’s gross processing margin:


	Nine Months Ended September 30,
	2007			2006
	(in thousands)
Gross processing margin, as reported	$	59,095		$	50,725
Derivatives (gains) losses included in gross processing margin		3,432			1,275

Gross processing margin before impact of derivatives		62,527			52,000
Cash settlements on derivatives		(8,963	)		(15,405	)

Gross processing margin, adjusted for derivatives	$	53,564		$	36,595

Operating expenses increased by $1.2 million, or 14%, from $8.4 million in the nine months ended September 30, 2006 to $9.6 million in the same period in 2007. DD&A expenses increased by $1.5 million, or 12%, from $12.5 million in the nine months ended September 30, 2006 to $14.0 million in the same period in 2007. Both increases were due to acquisitions and gathering system construction. General and administrative expenses increased by $0.9 million, or 11%, from $8.2 million in the nine months ended September 30, 2006 to $9.1 million in the same period in 2007 primarily due to increased staffing costs.

Corporate and Other

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

Expenses. Corporate operating expenses increased by $3.6 million, or 109%, from $3.3 million in the three months ended September 30, 2006 to $6.9 million in the three months ended September 30, 2007, and by $9.2 million, or 88%, from $10.4 million in the nine months ended September 30, 2006 to $19.4 million in the nine months ended September 30, 2007. These increases were primarily related to increased general and administrative expenses, which included higher payroll costs as a result of wages increases, new personnel and the granting of stock-based compensation in 2007. In addition, PVG also incurred general and administrative expenses in the three months and nine months ended September 30, 2007, which were not incurred in the same periods in 2006.

Interest Expense. Interest expense increased by $3.7 million, or 53%, from $7.1 million in the three months ended September 30, 2006 to $10.8 million in the same period in 2007. Interest expense increased by $8.6 million, or 50%, from $17.3 million in the nine months ended September 30, 2006 to $25.9 million in the same period in 2007. The increases in both periods were primarily due to interest incurred on additional borrowings under the Revolver to finance the acquisition of our Mid-Continent oil and gas properties, as well as additional drilling and development on our current oil and gas properties, partially offset by a $0.6 million and $1.9 million decrease in PVR’s interest expense for the three months and nine months ended September 30, 2007. PVR used the proceeds from the sale of common units and Class B units in December 2006 to pay down $114.6 million of the PVR Revolver. We capitalized interest costs amounting to $0.6 million and $0.9 million in the three months ended September 30, 2007 and 2006 and $2.5 million and $1.8 million in the nine months ended September 30, 2007 and 2006 because the borrowings funded the preparation of unproved oil and gas properties for their development.

Derivatives. Derivative losses increased by $22.4 million, or 125%, from a $17.9 million gain in the three months ended September 30, 2006 to a $4.5 million loss in the same period in 2007. The derivative losses in the three months ended September 30, 2007 consisted of a $10.7 million loss on natural gas midstream derivatives, partially offset by a $6.2 million gain on oil and gas derivatives. Derivative losses increased by $33.4 million, or 294%, from a $11.4 million gain in the nine months ended September 30, 2006 to a $22.0 million loss in the same period in 2007. The derivative losses in the nine months ended September 30, 2007 consisted of a $1.1 million loss on oil and gas derivatives and a $20.9 million loss on natural gas midstream derivatives. The increases in both periods were primarily due to valuation adjustments of unrealized derivative positions using mark-to-market accounting.

Summary of 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. Proven and probable coal reserves have been estimated by PVR’s own geologists and outside consultants. PVR’s estimates of coal reserves are updated annually 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.

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.

Coal Royalties Revenues

Coal royalties 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 coal mines, it does not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results 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 settles. Because during the first quarter of 2006 a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting and to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future 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 future earnings through 2008 as the original hedged transactions settle. We expect to recognize hedging losses of $0.2 million for the remainder of 2007 related to settlements of oil and gas transactions. PVR expects to recognize hedging losses of $1.2 million for the remainder of 2007 and $5.5 million for 2008 related to settlements of natural gas midstream transactions. The discontinuation of hedge accounting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, 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, 2007, the costs attributable to unproved properties were approximately $106.3 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 write downs of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.

Environmental Matters

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.

To dispose of mining overburden generated by their surface mining activities, PVR’s lessees need to obtain government approvals, including Federal Clean Water Act (“CWA”) Section 404 permits to construct valley fills and sediment control ponds. Two CWA Section 404 permits issued to Alex Energy, Inc. (“Alex Energy”), one of PVR’s surface coal mine lessees in West Virginia, were recently challenged in a lawsuit,Ohio Valley Environmental Coalition (“OVEC”) v. United States Army Corps of Engineers. On March 23, 2007, the U.S. District Court for the Southern District of West Virginia rescinded and remanded the permit authorizing several valley fills and sediment ponds that may be constructed at the Republic No. 2 Mine and enjoined Alex Energy from taking any further actions under this permit. The district court has yet to rule on whether the other CWA Section 404 permit for the construction of valley fills and associated sediment ponds at the Republic No. 1 Mine was also invalidly issued. Although portions of the Republic No. 2 Mine continue to operate based on a subsequent order allowing the mine to fully utilize and complete some of its partially constructed valley fills, the construction of new valley fills at other portions of the Republic No. 2 Mine is enjoined pending a final outcome of this litigation. On June 13, 2007, the district court also issued a declaratory judgment indicating that the mining companies subject to theOVEC decision may also be required to obtain new, separate CWA Section 402 permit authorizations for the stream segments located between the toes of their valley fills and their respective sediment pond embankments.

The district court’s March 23, 2007 decision is currently on appeal to the U.S. Court of Appeals for the Fourth Circuit. While PVR is still reviewing the district court’s ruling, its lessees may not be able to obtain or may experience delays in securing additional CWA Section 404 permits for surface mining operations. Unless theOVEC decision is overturned or further limited in subsequent proceedings, the ruling and its collateral consequences could ultimately have an adverse effect on PVR’s coal royalties revenues.

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

•

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 natural gas, crude oil, 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 crude oil;

•

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

•

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

•

the availability of required drilling rigs, production equipment and materials;

•

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 natural gas midstream and coal and natural resource management 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 and natural resource management or natural gas midstream businesses;

•

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

•

the price for which PVR can acquire coal reserves;

•

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

•

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

•

hazards or operating risks incidental to natural gas midstream operations;

•

unanticipated geological problems;

•

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

•

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 its 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 natural gas midstream customers, including their ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others;

•

PVR’s ability to expand its natural gas 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;

•

PVG’s ability to generate sufficient cash from its interests in PVR to maintain and pay the quarterly distribution to its general partner and its unitholders; and

•

other risks set forth in Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2006.

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, 2006. 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 customers and PVR’s customers and lessees. If our customers or PVR’s customers or lessees become financially insolvent, they may not be able to continue to operate 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. 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.

For the nine months ended September 30, 2007, we reported a net $22.1 million derivative loss for mark-to-market adjustments. Because during the first quarter of 2006 a large portion of our natural gas derivatives and NGL derivatives no longer qualified for hedge accounting and to increase clarity in our consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future 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 settle. We expect to recognize hedging losses of $0.2 million for the remainder of 2007 related to settlements of oil and gas segment transactions. PVR expects to recognize hedging losses of $1.2 million for the remainder of 2007 and $5.5 million for 2008 related to settlements of natural gas midstream segment transactions. The discontinuation of hedge accounting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, oil and gas prices. See the discussion and tables in Note 7 in the Notes to Consolidated Financial Statements for a description of our derivatives program.

The following tables list our open mark-to-market derivative agreements and their fair values as of September 30, 2007:

Oil and Gas Segment


	Average Volume Per Day		Weighted Average Price						Estimated Fair Value
	Average Volume Per Day		Additional Put Option		Floor		Ceiling		Estimated Fair Value
									(in thousands)
	(in MMbtus)		(per MMbtu)
Natural Gas Costless Collars
Fourth quarter 2007	11,685	��			$	8.28	$	15.78	$	1,544
First quarter 2008	10,000				$	9.00	$	17.95		1,322
Second quarter 2008	10,000				$	7.50	$	9.10		243
Third quarter 2008	10,000				$	7.50	$	9.10		243
Fourth quarter 2008 (October only)	10,000				$	7.50	$	9.10		81

	(in MMbtus)		(per MMbtu)
Natural Gas Three-Way Collars
Fourth quarter 2007	26,370		$	5.25	$	7.74	$	11.14		2,372
First quarter 2008	22,500		$	5.44	$	8.00	$	12.64		1,313
Second quarter 2008	22,500		$	5.00	$	7.11	$	9.09		(140	)
Third quarter 2008	22,500		$	5.00	$	7.11	$	9.09		74
Fourth quarter 2008	22,500		$	5.44	$	7.70	$	11.40		558
First quarter 2009	20,000		$	5.75	$	8.00	$	12.80		291

	(in barrels)		(per barrel)
Crude Oil Costless Collars
Fourth quarter 2007	200				$	60.00	$	72.20		(157	)

	(in barrels)		(per barrel)
Crude Oil Swaps
Fourth quarter 2007	300				$	69.00				(307	)
Settlements to be paid in subsequent period										(141	)

Oil and gas segment commodity derivatives - net asset									$	7,296

PVR Natural Gas Midstream Segment


	Average Volume Per Day	Weighted Average Price		Weighted Average Price Collars				Estimated Fair Value
	Average Volume Per Day	Weighted Average Price		Put		Call		Estimated Fair Value
								(in thousands)
	(in gallons)	(per gallon)
Ethane Swaps
Fourth quarter 2007	34,440	$	0.5050					$	(1,240	)
First quarter 2008 through fourth quarter 2008	34,440	$	0.4700						(3,299	)

	(in gallons)	(per gallon)
Propane Swaps
Fourth quarter 2007	26,040	$	0.7550						(1,384	)
First quarter 2008 through fourth quarter 2008	26,040	$	0.7175						(4,592	)

	(in barrels)	(per barrel)
Crude Oil Swaps
Fourth quarter 2007	560	$	50.80						(1,502	)
First quarter 2008 through fourth quarter 2008	560	$	49.27						(5,355	)

	(in MMbtu)	(per MMbtu)
Natural Gas Swaps (Purchase)
Fourth quarter 2007 through fourth quarter 2008	4,000	$	6.97						1,405

	(in gallons / in barrels)	(per gallon / per barrel)
Natural Gasoline Swap/Crude Oil Swap (purchase)
Fourth quarter 2007	23,520 / 560		1.265 / 57.12						33

	(in gallons)			(per gallon)
Ethane Collar
Fourth quarter 2007	5,000			$	0.6100	$	0.7125		(88	)

	(in gallons)			(per gallon)
Propane Collar
Fourth quarter 2007	9,000			$	1.0300	$	1.1640		(148	)

	(in gallons)			(per gallon)
Natural Gasoline Collar
Fourth quarter 2007 through fourth quarter 2008	6,300			$	1.4800	$	1.6465		(366	)

	(in barrels)			(per barrel)
Crude Oil Collar
First quarter 2008 through fourth quarter 2008	400			$	65.00	$	75.25		(600	)

	(in MMbtu)	(per MMbtu)
Frac Spread
Fourth quarter 2007	7,128	$	4.55						(2,601	)
First quarter 2008 through fourth quarter 2008	4,193	$	4.30						(1,933	)
First quarter 2008 through fourth quarter 2008 - (a)	3,631	$	5.85						—
Settlements to be paid in subsequent period									(2,428	)

Natural gas midstream segment commodity derivatives - net liability								$	(24,098	)

(a) – Entered into in October 2007

Interest Rate Risk

As of September 30, 2007, we had $414.5 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver Swaps 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% plus the applicable margin. The interest rate swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% 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, 2007 would cost us approximately $3.6 million in additional interest expense.

As of September 30, 2007, PVR had $300.2 million of outstanding indebtedness under the PVR Revolver, which carries a variable interest rate throughout its term. PVR entered into the PVR Revolver Swaps 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% plus the applicable margin. The PVR Revolver Swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% 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, 2007 would cost PVR approximately $2.4 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, 2007. 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, 2007, such disclosure controls and procedures were effective.

(b)

Changes in Internal Control over Financial Reporting

On July 1, 2007, we migrated to our new enterprise resource planning (“ERP”) system. As a result of moving to the new ERP system, several process level control procedures were changed in order to conform to the new ERP system. While we believe that the new ERP system will ultimately strengthen our internal control over financial reporting, there are inherent weaknesses in implementing any new system and we could experience control and implementation issues impacting our financial reporting. In the event that such an issue occurs, we have manual procedures in place which would allow us to continue to record and report results from the new ERP system. We are continuing to implement additional features and aspects of our new ERP system and will monitor, test and evaluate the impact and effect of the new ERP system on our internal controls and procedures as part of our evaluation of our internal control over financial reporting for 2007. Except for the new ERP system implementation, there were no changes 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.

PART II. OTHER INFORMATION

Items 1, 1A, 2, 3, 4 and 5 are not applicable and have been omitted.

Item 6

Exhibits



10.1		Eighth Amendment to Amended and Restated Credit Agreement dated as of August 1, 2007 among Penn Virginia Corporation, the lenders party thereto and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on August 2, 2007).

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 1, 2007	By:	/s/ Frank A. Pici
			Frank A. Pici
			Executive Vice President and Chief Financial Officer

Date:	November 1, 2007	By:	/s/ Forrest W. McNair
			Forrest W. McNair
			Vice President and Controller

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Ranger Oil (ROCC) 10-Q2007 Q3 Quarterly report

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