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
	Response Letter Dated December 14, 2009
	File No. 001-13283

On January 6, 2010, 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.

We have reviewed your response to prior comment two of our letter of November 30, 2009, regarding the risk associate with working interest owners that have the right to control the timing of drilling activities. Given that risk factors should be as specific to you as possible, also considering that 24% of your reserves are under this potential limitation of drilling activities, please disclose this fact along with your risk factor in future filings.

We have read your response to prior comment four, concerning the reserves associated with impairment charges that you reported in 2006 and 2007. Although you provided some details about the reserve write downs, you did not tell us why you believe the initial booking of these reserves as proved was appropriate. We re-issue prior comment four.

Response: The Company believes the booking of these reserves was correctly classified as proved reserves based on the definitions set forth in Rule 4-10(a) of Regulation S-X of the Securities Exchange Act of 1934, as well as the guidance provided by the Commission in its publication, Division of Corporate Finance: Frequently Requested Accounting and Financial Reporting Interpretations and Guidance, dated March 31, 2001. All of the reserves at issue were booked based on either volumetric or decline curve analysis by the Company’s in-house staff of geologists and engineers. With respect to reserves booked based on volumetric analysis, the Company utilized existing geological and engineering data and incorporated the use of digital logs, structure maps, isopach maps and available PVT data. Only that portion of the reservoir delineated by drilling and above the lowest known limit of hydrocarbons was considered proved. Under the economic and operating conditions existing at the time the analysis was performed, the Company believed with reasonable certainty that these reserves should be classified as proved reserves.

In 2006, the Company recorded an impairment charge of $8.5 million. As noted in the Company’s original response, the impairment charge related to six fields in Louisiana, Texas and West Virginia. Five of the six affected fields had reserve revisions associated with them. The total reserve revision associated with those five fields was 4.6 Bcfe, or less than one percent of the Company’s 2006 proved reserves, and one field, Portland South, accounted for 3.4 Bcfe, or 74%, of the total reserve revision.

Portland South: The Company booked proved reserves in this field based on volumetric analysis using all available geologic and engineering information, including the information described above. This field included one proved undeveloped (“PUD”) location. This location directly offset a productive well in which the Company had an interest and, based upon the past performance of producing wells in the reservoir, the Company was reasonably certain that all of the proved reserves would not be captured by the existing well. Subsequent to the booking of the PUD location, the Company sidetracked the existing well downdip into the thickest portion of the reservoir and acquired additional well data from an analogous field that necessitated a downward revision of the original volumetric estimate. As a result, the reserves associated with the PUD location were reduced to a point where the Company could no longer support the drilling of the PUD based on then current economic and operating conditions. The Company eliminated the PUD location from its 2006 reserve report, which resulted in the loss of 3.4 Bcfe, or 0.7% of the Company’s 2006 proved reserves.

Broussard: The Company booked proved reserves for a single well in this field based on volumetric analysis using all available geologic and engineering information, including the information described above. In 2006, water production in the Company’s well increased rapidly from 80 barrels per day to over 800 barrels per day, causing the well to “water” out and cease production. As a result, the Company reduced the proved reserves associated with this well by 0.3 Bcfe, or 0.06% of the Company’s 2006 proved reserves.

Bayou Carlin: The Company booked proved non-producing reserves for the drilling of a well based on volumetric analysis using all available geologic and engineering information, including the information described above. In 2006, the well was completed and the well was placed on production. The well underperformed original estimates, and the Company reduced the proved reserves associated with this well by 0.6 Bcfe, or 0.1% of the Company’s 2006 proved reserves.

Antonio Lopez: The Company booked proved producing reserves for this single well field based on decline curve analysis. In late 2006, well performance deteriorated from the previously forecast decline. As a result, the Company reduced the proved reserves associated with this well by 0.3 Bcfe, or 0.06% of the Company’s 2006 proved reserves.

Gebruder: The Company booked proved producing reserves for the three wells in this field based on decline curve analysis. In 2006, reserves for two of the wells were decreased by 0.07 Bcfe, and reserves for the third well were increased by 0.03 Bcfe based on then-current performance. This resulted in a net downward revision of 0.04 Bcfe, or 0.01% of the Company’s 2006 proved reserves.

In 2007, the Company recorded an impairment charge of $2.6 million. As noted in the Company’s original response, the impairment charge related to eight fields in Oklahoma and Texas. Of these eight affected fields, only three of the affected fields had reserve revisions associated with them. The total reserve revision associated with those three fields was 0.3 Bcfe, or less than one-tenth of one percent of the Company’s 2007 proved reserves.

Bayou Carlin: The Company booked proved producing reserves for a new producing well in this field based on volumetric analysis using all available geologic and engineering information, including the information described above. In 2007, the well began to underperform compared to the original volume estimate, and the Company reduced the proved reserves associated with this well by 0.3 Bcfe, or 0.04% of the Company’s 2007 proved reserves.

Esperanza: The Company booked proved producing reserves for the two wells in this field based on decline curve analysis. In 2007, reserves for one well increased by 0.008 Bcfe as a result in a change in economic conditions. The second well had proved reserves reduced by 0.011 Bcfe based on then-current performance. As a result, the Company reduced its 2007 proved reserves associated with this field by 0.003 Bcfe.

Donna/Santa Ana: The Company booked proved producing reserves in this field based on decline curve analysis. In 2007, one of the wells in this field underperformed the original estimate, and the Company reduced its 2007 proved reserves associated with this well by 0.003 Bcfe.

We note that you have response to prior comments five and six, pertaining to the disclosures required by paragraph 11 of SFAS 69. While reserves added through extensions and discoveries are generally understood to be attributable to additional drilling, we would expect that you would need to provide more meaningful explanations, such as the location where drilling took place and summarizing the results, so that investors are able to understand the nature and type of reserve which you have added. And although you may have discussed reserve changes elsewhere in the document, you would need to include explanations for each significant change depicted in the reserve tables along with the other reserve disclosures that are required in this note to your financial statements. Please confirm that that you will comply with this guidance in future filings.

We also note in response to prior comment six you state that for the first time you were able to report PUD reserves on the Mingo properties because you completed a geologic study in anticipation of a possible sale of your interest. However, given that you only own a royalty interest in these properties it is not clear how you were able to conclude that it is reasonably certain that the 812 PUD locations will be drilled by the operators, or are even being contemplated being drilled since the operators are not generally under an obligation to inform royalty owners for their plans. Please describe the manner by which you have established reasonable certainty; and submit for review and form of verification of drilling plans received from the operators. If you are unable to provide adequate support, these quantities should not be included as proved reserves.

Response: While the Company does not receive detailed drilling plans from the operators of the Mingo properties, the Company believes that the number of proved undeveloped (“PUD”) locations added during 2008 for these properties were reasonably certain based on the Company’s geologic and engineering understanding of the properties and the Company’s own active development of analogous properties (within the meaning of Commission rules) on which it is the operator.

2.	The Company receives monthly production data on a well-by-well basis from each operator. Currently, the Company actively monitors over 2,000 producing wells which are operated by approximately 22 different operators, many of whom are larger public companies.

4.	Once a well is approved and drilled, the operators are required to file completion reports with the state within 90 days. Therefore, utilizing internal staff monitoring and third party search firms, the Company is able to update its internal file and mapping systems to keep well data current.

The Company’s staff has completed a detailed geologic study and mapped every proved developed (“PDP”) well. The Company has assigned PUD reserves only to direct offsets of PDP wells. As mentioned above, there are over 2,000 active producing wells on the Mingo properties, which consist of over 500,000 net acres, and the Company had included proved reserves from only 812 PUD locations as of December 31, 2008.

The productive formations underlying the Mingo properties are considered “blanket” formations. The Company has a current success rate of approximately 97% on analogous properties on which it is an active operator. Based on publicly available data, other operators in the area have had similar success rates.

The Company schedules the PUD locations to be drilled by utilizing the historical annual average drilling activity of the various operators on the Mingo properties. The table set forth below shows annual drilling activity by year on the Mingo properties since 1997. The table also includes the average number of wells drilled per year, as well as the 5-year and 10-year averages. While the Company does not receive detailed drilling plans from each operator, the historical drilling record over the last 12 years has been relatively constant.

Penn Virginia Oil & Gas Corporation
Mingo Properties
Historical Drilling Activity

Year	Vertical Wells	Horizontal Wells	Equivalent Wells¹

1997	56	0	56
1998	87	0	87
1999	68	0	68
2000	74	0	74
2001	64	0	64
2002	115	0	115
2003	82	0	82
2004	81	0	81
2005	103	0	103
2006	107	0	107
2007	80	0	80
2008	58	18	112

Averages:
Last 12 years (1997-2008)			86
Last 10 years (1999-2008)			89
Last 5 years (2004-2008)			97


¹ Based on the Company’s operating experience, a single horizontal well will replace three vertical wells.

cc:	Nancy M. Snyder
	Jenifer Gallagher