CORRESP 1 filename1.htm

[PVA Letterhead]

December 14, 2009

Via EDGAR

Mr. H. Roger Schwall

Assistant Director

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street, N.E.

Washington, D.C. 20549

Re:	Penn Virginia Corporation
	Form 10-K for the Fiscal Year Ended December 31, 2008
	Filed February 27, 2009
	Form 10-Q for the Fiscal Quarter Ended September 30, 2009
	Filed November 6, 2009
	File No. 001-13283

Dear Mr. Schwall:

On November 30, 2009, the Staff of the Securities and Exchange Commission (the “Staff”) issued a comment letter to Penn Virginia Corporation (the “Company”) regarding the Company’s Form 10-K for the fiscal year ended December 31, 2008 (the “Form 10-K”) and the Company’s Form 10-Q for the fiscal quarter ended September 30, 2009.

The Staff’s comments and the Company’s responses thereto are as follows:

Form 10-K for the Fiscal Year Ended December 31, 2008

Financial Statements

Note 18 - Long Term Debt, page 121

We note in conjunction with the issuance of convertible notes you entered into separate convertible hedge transactions and warrant transactions with affiliates of the underwriters of the convertible notes. The convertible hedge transactions allow you to offset the potential dilution of the convertible notes in the event the market price of the common stock at the time of exercise is greater than the strike price of the note hedges, which corresponds to the initial conversion price of the convertible notes. In addition, the warrants that you sold to these parties require you to deliver shares of common stock equal to the difference between the then market price and the strike price of the warrants, which is $74.25. Please describe your accounting treatment for recognizing these transactions in your financial statements. Further, please identify where these transactions have been reflected in your financial statements.

United States Securities and Exchange Commission

December 14, 2009

Page 2

Response: The convertible note hedges (the “call options”) and the warrants resulted in the recognition of two separate equity instruments within shareholders’ equity as paid-in capital and were measured at their fair values upon the date of their issuance.

The Company determined the appropriate accounting treatment for the call options and warrants based on an analysis of U.S. generally accepted accounting principles (“GAAP”) in effect at the time of the transactions during the fourth quarter of 2007. The primary sources of GAAP that were considered in the analysis included the following:

Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted) and related Derivative Implementation Group Issues (“SFAS 133”).

EITF Issue No. 01-6, The Meaning of “Indexed to a Company’s Own Stock” (“EITF 01-6”); and

EITF Issue No. 00-19, Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock (“EITF 00-19”).

The scope of the Company’s accounting analysis encompassed the following:

Determine that the call options and warrants are considered issued or held for accounting purposes by the issuer and holder and indexed to the Company’s common stock within the meaning of EITF 00-19 and paragraph 11(a) of SFAS 133 as addressed in EITF 01-6.

Determine that the call options and warrants meet the requirements provided in EITF 00-19 for recognition and measurement as instruments to be classified in permanent shareholders’ equity.

Determine that the call options and warrants were eligible for the scope exception in paragraph 11(a) of SFAS 133 such that they would not be treated as derivatives subject to mark-to-market accounting.

A summary of the Company’s conclusions based on the aforementioned accounting analysis is as follows:

The call options and warrants are within the scope of EITF 01-6 because they are settled solely in shares of the Company’s common stock. In addition, outstanding instruments within the scope of EITF 01-6 are always considered “issued” for accounting purposes.

For instruments within the scope of EITF 01-6, they are considered indexed to a company’s own stock within the meaning of EITF 00-19 and paragraph 11(a) of SFAS 133 provided that (1) the contingency provisions are not based on (a) an observable index, other than the market for the issuer’s stock, or (b) an observable index, other than those calculated or measured solely by reference to the issuer’s own operations (for example EBITDA), and (2) once the contingent events have occurred, the instrument’s settlement amount is based solely on the issuer’s stock.

United States Securities and Exchange Commission

December 14, 2009

Page 3

The call options allow the Company to receive from the counterparties shares of the Company’s common stock contingent upon the conversion and delivery of shares to holders of the convertible notes. These call options are considered to be indexed to the Company’s own stock within the meaning of EITF 00-19 and paragraph 11(a) of SFAS 133 because (1) the contingent event (the conversion of the convertible notes) is not an observable market or an observable index and (2) once the contingent event occurs, the call options are settled solely in shares of the Company’s common stock.

The warrants permit the counterparty to purchase from the Company shares of the Company’s common stock for a fixed price at a certain date in the future. These warrants are considered to be indexed to the Company’s own stock with the meaning of EITF 00-19 and paragraph 11(a) of SFAS 133 because (1) the contingent event (the passage of time) is not an observable market or an observable index and (2) once the contingent event occurs, the warrants are settled solely in shares of the Company’s common stock.

Paragraphs 12 through 32 of EITF 00-19 provide for a number of conditions necessary to support classification as an equity instrument. A brief review of those conditions (references are to paragraphs of EITF 00-19) as applicable to the call options and warrants (the “instruments”) is as follows:

The instruments do not include any provision for a net-cash settlement except under specific circumstances (see (g.) below) (paragraph 12).

The instruments permit the Company to settle in unregistered shares (paragraphs 14-18).

The Company has sufficient shares to settle the instruments after considering all other potential commitments (paragraph 19).

The instruments contain an explicit limit on the number of shares to be delivered in a share settlement (paragraphs 20-24).

There are no required cash payments to the counterparties in the event the Company fails to make timely filings with the Commission (paragraph 25).

The instruments do not require cash payments with respect to any “make-whole” or “top-off” provisions (paragraph 26).

The instruments only require net-cash settlement in specific circumstances (i.e., tender offer, etc.) in which holders of shares underlying the instruments also would receive cash in exchange for their shares (paragraphs 27-28).

There are no provisions in the instruments that indicate that the counterparties have rights that rank higher than those of a holder of the Company’s common stock (paragraphs 29-31).

There is no requirement in the instruments to post collateral at any point for any reason (paragraph 32).

United States Securities and Exchange Commission

December 14, 2009

Page 4

Based on the accounting analysis as summarized above, the call options and warrants were initially measured at their fair values on the date of issuance and were recognized and classified as separate instruments in permanent shareholders’ equity.

In addition, the call options and warrants meet the scope exception of SFAS 133, paragraph 11(a) because they are instruments held by the Company that are both (a) indexed to the Company’s common stock and (b) classified in shareholders’ equity. Accordingly, they are not considered to be derivatives subject to mark-to-market accounting.

For the year ended December 31, 2007, the call options and warrants, net of tax effects, were included as an increase to paid-in capital. The issuance of the convertible notes, as well as the issuance of the call options and warrants, was completed concurrently with a common stock offering of 3,450,000 shares of the Company’s common stock. Because these transactions were completed concurrently in an effort to modify the Company’s total capitalization, the Company reported the net impact on shareholders’ equity within a single caption in the consolidated statements of shareholders’ equity and comprehensive income included in the Form 10-K. The following presentation provides the individual transaction components reflected in the single line presentation included in the Form 10-K:

								Total
	Shares		Common		Paid-in			Shareholders'
	Outstanding		Stock		Capital			Equity
Common stock offering		3,450	$	35	$	135,371		$	135,406
Purchase of call options		-		-		(36,817	)		(36,817	)
Tax benefit of call options		-		-		14,580			14,580
Sale of warrants		-		-		18,187			18,187

Common stock offering, as reported		3,450	$	35	$	131,321		$	131,356

For clarity purposes, the Company intends to provide this level of detail in the consolidated statements of shareholders’ equity and comprehensive income to be included in its Form 10-K for the year ended December 31, 2009.

Engineering Comments

Risk Related to Our Oil and Gas Business, page 21

Certain working interest owners in our properties have the right to control the timing of drilling activities on our properties under certain circumstances, page 25

We would like to understand the level of exposure you may have to the risk factor described in this section. Please tell us the percentage of your reserves that are potentially impacted by this risk factor, and indicate the extent to which coal mining activities may be given priority over oil and gas activities. Please also quantify the oil and gas proved reserves that you have reported for these properties and provide the dates when they were first booked as proved reserves. Tell us if the coal companies have any deadlines on when they must begin their coal mining activities.

United States Securities and Exchange Commission

December 14, 2009

Page 5

Response: The above-referenced risk factor was not intended to refer to coal companies. Instead, it deals with risk posed by other working interest owners in certain reserves in which the Company also has an interest. In those situations in which there are other working interest owners, the Company, like its peers, enters into industry-standard joint operating, participation or other similar agreements which govern the relationship among the various owners of the subject reserves. In addition to industry-standard joint operating agreements, the Company is also a party to one particular joint operating agreement pursuant to which either the Company or the other working interest owner may limit the number of drilling rigs that may be operated at a given time. The properties subject to this agreement contain 222.6 Bcfe of proved reserves as of December 31, 2008, which represents approximately 24% of the Company’s proved reserves as of December 31, 2008. The proved reserves attributed to these properties were first booked in 2004, but the vast majority of the proved reserves were booked in 2007 and 2008.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 50

Oil and Gas Segment, page 51

We note that you have reported potential locations beyond those identified for proved reserves. The guidance in Instruction 5 to Item 102 of Regulation S-K generally prohibits disclosing estimates of oil and gas other than proved reserves in SEC filings. Please amend your document to remove the number of potential locations.

Response: Instruction 5 to Item 102 of Regulation S-K provides, in pertinent part, that “[e]stimates of oil or gas reserves other than proved … and any estimated values of such reserves shall not be disclosed in any document publicly filed with the Commission….” The Company’s interpretation of Instruction 5 is that Instruction 5 only prohibits estimates of unproved reserves or values. The referenced portion of the Company’s Form 10-K references “locations,” but not reserves or values as prohibited by Instruction 5. Nevertheless, the Company will remove disclosure of potential locations from its future filings with the Commission.

Year Ended December 31, 2007 Compared With Year Ended December 31, 2006, page 72

We note that you recorded impairment charges of $2.6 million in 2007 due to changes in estimates of the reserve bases of fields on certain properties in Oklahoma and Texas, and $8.5 million in 2006 due to changes in estimates of reserve bases of certain fields in Louisiana, Texas and West Virginia which were primarily due to well performance. Please provide us with details of these reserve write downs and explain why you believe the initial volumes classified as proved reserves were correct.

United States Securities and Exchange Commission

December 14, 2009

Page 6

Response: The following table sets forth a detailed explanation of the Company’s 2006 impairment charges:

	2006
	Impairments		Revisions
Field	(M$)		(Bcfe)		Comments

Portland South		1,735		-3.4	Dropped the State Tract 25-5 (PUD) from the Company’s reserve report when the well could not be economically justified based on the reservoir having a higher than previously assumed abandonment pressure.

Broussard		260		-0.3	Mayo Trust #1 – Reserves were developed based on volumetrics. This is a strong water drive reservoir, and water production increased from 80 B/D to over 800 B/D in the latter part of 2006. The resulting revision essentially zeroed out the reserves for this well.

Bayou Carlin		4,140		-0.6	Reef Exploration Miami Corp #1 S/T2 was a new well and under performed initial volumetric estimates.

Antonio Lopez		1,127		-0.3	Degoche #1 – Reserves were initially estimated by decline curve analysis using limited production history. The well began producing at lower than anticipated rates in 2006.

Esperanza		152		0	Write-down not the result of any reserve revision.

Gebruder		1,103		-0.04	Reserves were estimated by decline curve. Of the three wells in the field, two had combined downward revisions of 69 MMcfe, and the third had an upward revision of 26 MMcf.

Total		8,517		-4.6

United States Securities and Exchange Commission

December 14, 2009

Page 7

The following table sets forth a detailed explanation of the Company’s 2007 impairment charges:

	2007
	Impairments		Revisions
Field	(M$)		(Bcfe)		Comments

Bayou Carlin		1,523		-0.3	Miami Corp #1 – Well was drilled late 2006. Actual well performance underperformed original volumetric estimates and was revised downward during the Company’s internal mid-year 2007 reserve report.

Esperanza		431		-0.003	Revised the reserves of the Mayo Trust #1 upward by 8 MMcfe at YE07 (forecast unchanged between YE06 and YE07 – only economic limit changed). The reserves of the Friedrich #1 were revised downward by 11 MMcf at YE07 based on actual well performance using decline curve analysis.

Donna/Santa Ana		39		-0.003	Minor reserve change to Santa Ana #1 based on decline curve analysis.

Cruce North		1		0	Write-down not the result of any reserve revision.

Lamar East		181		0	Write-down not the result of any reserve revision.

Milder		6		0	Write-down not the result of any reserve revision.

Norman South		399		0	Write-down not the result of any reserve revision.

Perrytown West		6		0	Write-down not the result of any reserve revision.

Total		2,585		-0.3

Supplemental Information on Oil and Gas Producing Activities, page 136

Oil and Gas Reserves, page 138

5.	We note that your reserve reconciliation table includes a number of significant changes with no accompanying explanation. Please disclose your explanations for all significant reserve changes to comply with paragraph 11 of SFAS 69.

Response: In 2006, reserves increased significantly because of two factors. First, the Company purchased approximately 48.3 Bcfe of reserves, most of which occurred in three transactions, the largest being the Company’s acquisition of Crow Creek Energy in the Mid-Continent. The Crow Creek Energy acquisition was discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of the Form 10-K. The Crow Creek Energy acquisition accounted for approximately 44 Bcfe of the additional purchased reserves. Second, extensions, discoveries and other additions increased due to the drilling of 103 wells on locations which were not classified as proved undeveloped (“PUD”) locations in the Company’s 2005 year-end reserve report and the addition of 161 new PUD locations as a result of the Company’s 2006 drilling activities.

In 2007, reserves increased significantly because of two factors. First, the Company purchased approximately 74.4 Bcfe of reserves, most of which occurred in four transactions. Three of these transactions were discussed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of the Form 10-K. Second, extensions, discoveries and other additions increased due to the drilling of 151 wells on locations which were not classified as PUD locations in the Company’s 2006 year-end reserve report and the addition of 229 new PUD locations as a result of the Company’s 2007 drilling activities.

United States Securities and Exchange Commission

December 14, 2009

Page 8

The only significant reserve change in 2008 was due to the increase in extensions, discoveries and other additions. This increase was due to the drilling of 158 wells on locations which were not classified as PUD locations in the Company’s 2007 year-end reserve report and the addition of 1,031 new PUD locations as a result of the Company’s 2008 drilling activities. Please see the response to Question #6 below for more detail surrounding these locations.

6.	We note a 50% increase in proved reserves in 2008 due to extensions and discoveries. Please provide us with a detailed explanation of these increases.

Response: “Extensions, discoveries and other additions” for 2008 was the result of drilling 159 wells on locations which were not classified as PUD locations in the Company’s 2007 year-end reserve report. In addition, 201 new PUD locations were added to the Company’s 2007 year-end reserve report as a result of the Company’s 2008 drilling activities. An additional 812 PUD locations were added at the Company’s Mingo properties. In Mingo, the Company owns the oil and gas in mineral fee and has no working interest in these properties. The Company has leased these minerals to other oil and gas companies and has retained a royalty interest. The proved reserves booked by the Company are primarily associated with a 12.5% royalty interest retained by the Company as the lessor. Prior to the 2008 reserve report, the Company did not report PUD reserves associated with the Mingo properties because it did not have sufficiently detailed data regarding non-producing properties. In 2008, the Company completed a comprehensive geologic study of the Mingo properties in connection with a possible sale of such properties. As a result of the study, the Company was able to report PUD reserves associated with the Mingo properties in its 2008-year end reserve report.

The following table summarizes the wells drilled on non-PUD locations, the added PUD locations and the associated reserves numbers by field:

Field	Wells Drilled on Non-PUD Locations		Added PUD Locations		Reserves (Bcfe)

East Texas Cotton Valley		52		104		119.1
East Texas Lower Bossier		7		12		69.0
Granite Wash		13		21		63.0
Mingo		0		812		27.1
Mississippi Selma Chalk		21		32		24.8
Miscellaneous		65		32		40.8
Total		158		1,013		343.9

United States Securities and Exchange Commission

December 14, 2009

Page 9

7.	Please tell us how much of your oil and gas revisions for each year presented were due to price changes and how much were due to performance changes.

Response: The following table shows total oil and gas revisions for each of 2006, 2007 and 2008 broken out by price revisions and performance revisions:

Revisions	Natural Gas (MMcf)			Oil and Condensation (MBbl)			Total Equivalents (MMcfe)

2006
Price revisions		(12,315	)		(89	)		(12,851	)
Performance revisions		2,133			485			5,044
Total revisions		(10,182	)		396			(7,807	)

2007
Price revisions		8,051			260			9,611
Performance revisions		(27,605	)		3,593			(6,046	)
Total revisions		(19,554	)		3,853			3,566

2008
Price revisions		(30,483	)		(2,172	)		(43,514	)
Performance revisions		(29,345	)		2,041			(17,099	)
Total revisions		(59,827	)		(131	)		(60,613	)

8.	Please tell us the amount of oil and gas production that you forecasted for 2008 in the Total Proved Reserve Case of your 2007 reserve report, and reconcile, with explanation, the differences between forecasted amounts and actual production.

Response: The Company’s 2007 reserve report forecasted 2008 production of 54.5 Bcfe. The Company internally budgeted 2008 production of 53.9 Bcfe. The Company’s budgeted production routinely varies slightly from reserve report forecasted production because the two estimates are prepared for different purposes and pursuant to different guidelines. In any event, the variance between reserve report forecasted production and budgeted production for 2008 was approximately 1%. The Company routinely reconciles actual production to budgeted production, but it does not reconcile actual production to reserve report forecasted production. The table below sets forth a reconciliation of the Company’s actual 2008 production to the Company’s budgeted 2008 production:

United States Securities and Exchange Commission

December 14, 2009

Page 10

	Total Equiv. (Bcfe)		Percent Change

2007 Reserve Report Production Forecast for 2008		54.5

Budgeting Variance		-0.6		-1	%

Budgeted 2008 Production		53.9

Production Variance
Shift in drilling program from Cotton Valley to Lower Bossier in east Texas, which caused delays in production due to increased drilling times associated with the Lower Bossier		-3.0		-6	%
Delay in start-up of a processing plant and associated pipeline curtailments in east Texas		-2.7		-5	%
Hurricane Ike and other weather-related problems		-1.6		-3	%
Completion delays and pipeline capacity issues with Southern West Virginia HCBM		-1.3		-2	%
Rig delays in the Selma Chalk in Mississippi and Bakken Shale in North Dakota		-0.6		-1	%
Halted Mid-Continent drilling in 4Q08 due to commodity prices		-0.4		-1	%
Installation of refrigeration unit at Starks in south Louisiana		0.2		0	%
Better well performance for Mid-Continent Granite Wash wells		0.2		0	%
South Texas well workovers		0.4		1	%
Additional drilling at South Creole in south Louisiana		0.5		1	%
Increased working interest in Woodford Shale wells in Oklahoma		0.5		1	%
Earlier payout on Bayou Carlin Peterson #1 well in south Louisiana		0.7		1	%
Better well performance at Bayou Postillion in south Louisiana		0.8		1	%
Miscellaneous well performance issues		-0.8		-1	%
Total		-7.1		-13	%

Actual 2008 Production		46.8

United States Securities and Exchange Commission

December 14, 2009

Page 11

In connection with this response letter, the Company acknowledges that:

the Company is responsible for the adequacy and accuracy of the disclosure in its filings with the Commission;

Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the Company’s filings; and

the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please contact me at (610) 687-8900 if you need additional information or would like to discuss any questions or comments.

	Sincerely,

	/s/ Frank A. Pici
	Frank A. Pici
	Executive Vice President and Chief Financial Officer

cc:	Nancy M. Snyder

Jenifer Gallagher