UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

2012

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 Number)

Four Radnor Corporate Center, Suite 200

100 Matsonford Road

Radnor, Pennsylvania 19087

(Address of principal executive offices)

Registrant’s telephone number, including area code: (610) 687-8900

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Title of each class Name of exchange on which registered
Common Stock, $0.01 Par Value New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  x¨    No  ¨ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 (“Exchange Act”).    Yes  ¨    No  xý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  xý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  xý  No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)

Large accelerated filerx¨Accelerated filer¨ý
Non-accelerated filer¨Smaller reporting company¨

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

The aggregate market value of common stock held by non-affiliates of the registrant was $599,073,526$333,361,639 as of June 30, 20112012 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such stock as quoted on the New York Stock Exchange. For purposes of making this calculation only, the registrant has defined affiliates as including all directors and executive officers of the registrant. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 10, 2012, 45,714,19119, 2013, 55,117,346 shares of common stock of the registrant were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement relating to the registrant’s Annual Meeting of Shareholders, to be held on May 4, 2012,1, 2013, are incorporated by reference in Part III of this Form 10-K.




PENN VIRGINIA CORPORATION AND SUBSIDIARIES

ANNUAL REPORT ON FORM 10-K

For the Fiscal Year Ended December 31, 2011

2012

Table of Contents

 Page
Forward-Looking Statements1
Glossary of Certain Industry Terminology2
Part I
Item  
1.Business4
1A.Risk Factors9
1B.Unresolved Staff Comments14
2.Properties15
3.Legal Proceedings20
4.Reserved20
Part II
   
5.Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities20
6.Selected Financial Data22
7.Management’s Discussion and Analysis of Financial Condition and Results of Operations: 
 Overview of Business23
 Key Developments24
 Results of Operations26
 Year Ended December 31, 2011 Compared to the Year Ended December 31, 201026
 Year Ended December 31, 2010 Compared to the Year Ended December 31, 200933
 Liquidity and Capital Resources41
 Off-Balance Sheet Arrangements46
 Contractual Obligations46
 Environmental Matters47
 Critical Accounting Estimates47
 New Accounting Standards48
7A.Quantitative and Qualitative Disclosures About Market Risk48
8.Financial Statements and Supplemental Data50
9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure83
9A.Controls and Procedures83
9B.Other Information83
Part III
   
10.Directors, Executive Officers and Corporate Governance84
11.Executive Compensation84
12.Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters84
13.Certain Relationships and Related Transactions, and Director Independence84
14.Principal Accountant Fees and Services84
Part IV
   
15.Exhibits and Financial Statement Schedules85
  
Signatures88

 Page
Forward-Looking Statements
1
Glossary of Certain Industry Terminology
2
Part I
Item  
1.Business
4
1A.Risk Factors
10
1B.Unresolved Staff Comments
17
2.Properties
18
3.Legal Proceedings
24
4.Mine Safety Disclosures
24
Part II
   
5.Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
25
6.Selected Financial Data
26
7.Management’s Discussion and Analysis of Financial Condition and Results of Operations: 
 Overview of Business
28
 Key Developments
28
 Results of Operations:
31
 Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011
31
 Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010
39
 Liquidity and Capital Resources
45
 Off-Balance Sheet Arrangements
51
 Contractual Obligations
51
 Environmental Matters
51
 Critical Accounting Estimates
52
 New Accounting Standards
53
7A.Quantitative and Qualitative Disclosures About Market Risk
54
8.Financial Statements and Supplemental Data
56
9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
90
9A.Controls and Procedures
90
9B.Other Information
90
Part III
   
10.Directors, Executive Officers and Corporate Governance
91
11.Executive Compensation
91
12.Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
91
13.Certain Relationships and Related Transactions, and Director Independence
91
14.Principal Accountant Fees and Services
91
Part IV
   
15.Exhibits and Financial Statement Schedules
92
  
Signatures
95



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, or 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,oil, natural gas liquids and oil;natural gas;

our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;

our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;

any impairments, write-downs or write-offs of our reserves or assets;

the projected demand for and supply of natural gas,oil, natural gas liquids and oil;natural gas;

reductions in the borrowing base under our revolving credit facility (“Revolver”);facility;

our ability to contract for drilling rigs, supplies and services at reasonable costs;

our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices;

the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves;

drilling and operating risks;

our ability to compete effectively against other independent and major oil and natural gas companies;

our ability to successfully monetize select assets and repay our debt;

leasehold terms expiring before production can be established;

environmental liabilities that are not covered by an effective indemnity or insurance;

the timing of receipt of necessary regulatory permits;

the effect of commodity and financial derivative arrangements;

our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms;

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

our ability to retain or attract senior management and key technical employees;

counterparty risk related to their ability to meet their future obligations;

changes in governmental regulationregulations or enforcement practices, especially with respect to environmental, health and safety matters;

uncertainties relating to general domestic and international economic and political conditions; and

other risks set forth in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2011.2012.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. 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.


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Glossary of Certain Industry Terminology

The following are abbreviations and definitions commonly used in the oil and gas industry that are used within this Annual Report on Form 10-K.

Bbl
BblA standard barrel of 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
  
BcfOne billion cubic feet of natural gas.
  
BcfeOne billion cubic feet of natural gas equivalent with one barrel of crude oil, condensate or natural gas liquids converted to six thousand cubic feet of natural gas based on the estimated relative energy content.
  
BOEPDBarrels of oil equivalent per day.
  
Developed acreageLease acreage that is allocated or assignable to producing wells or wells capable of production.
  
Development wellA well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
  
Dry holeA well found to be incapable of producing either oil or gas in sufficient commercial quantities to justify completion of the well.
  
Exploratory wellA well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.
  
GAAPAccounting principles generally accepted in the Unites States of America.
  
Gross acre or wellAn acre or well in which a working interest is owned.
  
LIBORLondon Interbank Offered Rate.
  
MBblOne thousand barrels of oil or other liquid hydrocarbons.
  
MBOEOne thousand barrels of oil equivalent.
 
McfOne thousand cubic feet of natural gas.
  
McfeOne thousand cubic feet of natural gas equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content.
  
MMBblOne million barrels of oil or other liquid hydrocarbons.
  
MMBOEOne million barrels of oil equivalent.
 
MMBtuOne million British thermal units, a measure of energy content.
  
MMcfOne million cubic feet of natural gas.
  
MMcfeOne million cubic feet of natural gas equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content.
  
Net acre or wellThe number of gross acres or wells multiplied by the owned working interest in the gross acres or wells.
  
NGLNatural gas liquid.
  
NYMEXNew York Mercantile Exchange.
  
OperatorThe entity responsible for the exploration and/or production of a well or lease.
  
Productive wellsWells that are not dry holes.
  

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Proved reservesThose quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate.

Proved developed reservesProved reserves that can be expected to be recovered: (a) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (b) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
  
Proved undeveloped reservesProved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributable to any acreage for which application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir, or by other evidence using reliable technology establishing reasonable certainty. 
  
Standardized measureThe present value, discounted at 10% per year, of estimated future cash inflows from the production of proved reserves, computed by applying prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves (except for consideration of future price changes to the extent provided by contractual arrangements in existence at year-end), reduced by estimated future development and production costs, computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year (including the settlement of asset retirement obligations), based on year-end costs and assuming continuation of existing economic conditions, further reduced by estimated future income tax expenses, computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the proved oil and gas reserves, less the tax basis of the properties involved and giving effect to the tax deductions and tax credits and allowances relating to the proved oil and gas reserves.
  
Revenue interestAn economic interest in production of hydrocarbons from a specified property.
  
Royalty interestAn interest in the production of a well entitling the owner to a share of production generally free of the costs of exploration, development and production.
  
Undeveloped acreageLease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.
  
Working interestA cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease.


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Part I


Item 1Business

General

Penn Virginia Corporation (NYSE: PVA), a Virginia corporation formed in 1882, is an independent oil and gas company engaged primarily in the exploration, development and production of oil, NGLs and natural gas and oil in various domestic onshore regions of the United States, including Texas, Appalachia, the Mid-Continent and Mississippi.

We operate in and report our financial results and disclosures as one segment. Each of our operating regions has similar economic characteristics and meets the criteria for aggregation.


Unless the context requires otherwise, references to the “Company,” “Penn Virginia,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia Corporation and its subsidiaries.
Prior to June 2010, we indirectly owned partner interests in Penn Virginia Resource Partners, L.P., or PVR, a publicly traded limited partnership formed by us in 2001 that was engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in PVR were held principally through our general and limited partner interests in Penn Virginia GP Holdings, L.P., or PVG, a publicly traded limited partnership formed by us in 2006. In June 2010, we disposed of our remaining ownership interests in PVG and, indirectly, our interests in PVR. This divestiture completedAccordingly, PVG's results of operations, financial position and cash flows have been reported as discontinued operations for all applicable periods included herein.
Description of Business
Business Overview
As of December 31, 2012, our proved reserves were approximately 113 MMBOE, of which 41 percent were proved developed reserves and 40 percent were oil and NGLs. Our proved reserves and primary development plays are located in Texas, the processMid-Continent and Mississippi, which comprised 73 percent, 11 percent and 16 percent of our transformation intototal proved reserves, respectively, as of December 31, 2012. In 2012, our production totaled 6.5 MMBOE. Texas, the Mid-Continent, Mississippi and Appalachia comprised 56 percent, 19 percent, 13 percent and 12 percent of total production volumes, respectively, during 2012. In the three years ended December 31, 2012, we drilled 166 gross (117.0 net) wells, of which 96 percent were productive.

As of December 31, 2012, we had 1,103 gross (910.8 net) productive wells, approximately 97 percent of which we operate, and owned approximately 0.3 million gross (0.2 million net) acres of leasehold and royalty interests, approximately 53 percent of which were undeveloped. Our proved undeveloped locations and additional potential drilling locations are direct offsets or extensions from existing production. We believe we have multiple years of drilling opportunities on our existing undeveloped acreage based on our historical drilling rate. For a “pure play” explorationmore detailed discussion of our reserves, production, wells and production (E&P) company. Our Consolidated Financial Statementsacreage, see Item 2, “Properties.”

In 2012, our capital expenditures were approximately $385 million, of which approximately $287 million, or 74 percent, was related to development drilling, approximately $49 million, or 13 percent, was related to exploratory drilling and Notes presentapproximately $28 million, or seven percent, was related to leasehold acquisitions. The remaining $21 million, or six percent, was related to pipelines, gathering assets, facilities and corporate projects.

The past two years have been transformational for us as we have diversified our former interests in PVG as discontinued operations.

Unless the context requires otherwise, references to the “Company,” “Penn Virginia,” “we,” “us” or “our” in this Annual Report on Form 10-K refer to Penn Virginia Corporation and its subsidiaries.

Description of Business

Business Overview

Having completed our transformation to a “pure play” E&P company, we are now focusing our efforts onportfolio towards primarily oil and NGL investment opportunities rather than natural gas.opportunities. During 2011,2012, we grew our oil and NGL production to 28% (37%48 percent (56 percent for the 4th quarter of 2011)2012) of our total production, an increase of approximately 59%43 percent over 2010,2011, and we invested approximately $390$376 million in oiloil- and NGL-related capital projects. These investments have yielded higher cash flows and margins that more than offset the decline in production volumes and realized prices from our natural gas production assets. We expect our oil and NGL production to continue to grow as a percentage of our total production as we pursue higher rate-of-return projects in economically attractive oiloil- and NGL-rich areas.

As We have been very active in the Eagle Ford Shale play in South Texas, which provided approximately 36 percent of December 31, 2011, our proved reserves were2012 production. In addition, we invested approximately 883 Bcfe,$350 million, or 91 percent, of which 49% were proved developed reserves. Our operations currently include primarily unconventional developmental drilling opportunities and exploratory prospects.our 2012 capital program to projects in this play. We believe our emerging presenceproject inventory in the Eagle Ford Shale provides us opportunities for continued oiloil- and NGL-focused investments over the next several years.

years. Our proved reservescurrent operations consist primarily of drilling unconventional horizontal development wells in shale formations.



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In 2012, we sold our legacy natural gas assets in West Virginia, Kentucky and primary development plays are located in Texas, Appalachia, the Mid-Continent and Mississippi,Virginia which comprised 53%, 17%, 11% and 19%a significant portion of our total proved reserves asoperations in Appalachia. We have retained producing wells and significant undeveloped acreage in the Marcellus Shale area of December 31, 2011. In 2011, our production totaled 46.6 Bcfe, compared to 47.2 Bcfe in 2010. Texas, Appalachia, the Mid-Continent and Mississippi comprised 38%, 20%, 28% and 14% of total production volumes during 2011. In the three years ended December 31, 2011, we drilled 156 gross (105.0 net) wells, of which 92% were productive wells.Appalachian region. For a more detailed discussion of our reserves and production,additional information on this disposition, see Item 2, “Properties.”

In 2011, our capital expenditures were $446.7 million,7, “Management's Discussion and Analysis of which $307.8 million, or 69%, was related to development drilling, $64.1 million, or 14%, was related to exploratory drillingFinancial Condition and $50.0 million, or 11%, was related to leasehold acquisitions. The remaining $24.8 million, or 6%, was related to pipelines, gathering and facilities.

AsResults of December 31, 2011, we owned approximately 1.1 million net acres of leasehold and royalty interests, approximately 29% of which were undeveloped. Many of our proved undeveloped locations and additional potential drilling locations are direct offsets or extensions from existing production. We believe we have several years of drilling opportunities on our existing undeveloped acreage based on our historical drilling rate.

Operations—Key Developments.”


Business Strategy

We intend to pursue the following business strategies:

•Continue our “Gas-to-Oil” transition. We anticipate oil and NGL production will provide approximately 42% of our total 2012 production, which is an increase of approximately 26% to 42% over our total 2011 oil and NGL production. Our planned 2012 capital projects are focused on oil and NGL exploration and development.
•Grow our cash flows and margins. We expect our operating cash flows and margins will continue to grow as we increase our oil and NGL production through investment in higher rate-of-return development oil projects.
•Expand oil and NGL reserves and drilling inventory. We anticipate spending up to approximately $325 million on oil and gas capital expenditures in 2012. We plan to allocate up to $245 million, or approximately 75% of this amount, to development drilling and related projects, primarily on our Eagle Ford Shale acreage in Gonzales County, Texas. We anticipate allocating the remaining $80 million, or approximately 25%, of our oil and gas capital expenditures to exploratory drilling projects in the Eagle Ford Shale and Mid-Continent region including our recently announced agreement to jointly explore approximately 13,000 gross acres of the Eagle Ford Shale in Lavaca County, Texas.

•Improve our liquidity and financial position.We expect to continue to use our operating cash flows and borrowings under our Revolver to fund our capital requirements in 2012. We expect to supplement these sources of liquidity with proceeds from the sale of non-core assets or by accessing the capital markets. Our Revolver provides for a maximum leverage of up to 4.5 times EBITDAX (as defined in the Revolver) through June 2013 and 4.0 times EBITDAX thereafter through its maturity in August 2016. We have no material debt maturities until 2016.
•Pursue selective divestitures of non-core assets to increase margins, operational focus and liquidity. Certain of our natural gas assets no longer represent core activities. We may dispose of certain of these assets and reinvest the proceeds into our oil and NGL-focused projects.
•Retain long-term optionality of our core natural gas assets. We maintain substantial natural gas properties, particularly in the Haynesville Shale and Cotton Valley Sands in East Texas and in the Selma Chalk in Mississippi, which are largely held by production. We plan to retain these assets, which provide us with the option to increase development in these regions when natural gas prices improve.
•Manage risk exposure through an active hedging program. We actively manage our exposure to commodity price fluctuations by hedging the commodity price risk for our expected production. The level of our hedging activity and duration of the instruments employed depend upon our cash flow at risk, available hedge prices and our operating strategy. For 2012, we have hedged approximately 47% of our estimated oil production at average floor/swap and ceiling prices of $97.08 and $99.61 per barrel. In addition, we have hedged approximately 32% of our estimated natural gas production at a weighted-average floor/swap price of $5.43 per MMBtu and ceiling price of $6.05 per MMBtu.

Continue to expand oil and NGL reserves and drilling inventory. We anticipate spending up to approximately $400 million for capital expenditures in 2013. We plan to allocate up to $345 million, or approximately 86 percent, to drilling and completion projects, primarily on our Eagle Ford Shale acreage in Gonzales and Lavaca Counties in South Texas. We plan to allocate up to $30 million, or approximately eight percent, to leasehold projects to further expand our drilling inventory. We anticipate allocating the remaining $25 million, or approximately six percent, to pipeline, gathering, seismic and and facilities projects.
Grow our cash flows and margins. We expect our operating cash flows and margins will continue to grow on a pro forma basis taking into consideration recent asset sales as we increase our oil and NGL production through investment in higher rate-of-return development oil projects.
Maintain our liquidity and financial position. We expect to continue to use our operating cash flows and borrowings under our revolving credit facility, or the Revolver, to fund our capital requirements in 2013. The Revolver limits our leverage to 4.5 times EBITDAX (as defined in the Revolver) through December 31, 2013, 4.25 times EBITDAX through June 30, 2014 and 4.0 times EBITDAX thereafter through its maturity in 2017. We have no material debt maturities until 2016.
Retain long-term optionality of our core natural gas assets. We maintain substantial natural gas properties, particularly in the Haynesville Shale and Cotton Valley Sands in East Texas, which are largely held by production. At this time, we plan to retain these assets, which provide us with the option to increase development in these regions when natural gas prices improve.
Pursue selective divestitures of non-core assets to increase margins, operational focus and liquidity. From time to time, we may dispose of certain non-core assets and reinvest the proceeds into our oil- and NGL-focused projects.
Manage risk exposure through an active hedging program. We actively manage our exposure to commodity price fluctuations by hedging the commodity price risk for our expected production. The level of our hedging activity and duration of the instruments employed depend upon our cash flows at risk, available hedge prices and our operating strategy. For 2013, we have hedged approximately 58 percent of our estimated crude oil production at average floor/swap and ceiling prices of $97.35 and $100.99 per barrel. In addition, we have hedged approximately 55 percent of our estimated natural gas production at a weighted-average floor/swap price of $3.76 per MMBtu and ceiling price of $4.19 per MMBtu.

Contracts

Transportation

We have entered into contracts that provide firm transportation capacity rights for specified volumes per day on various pipeline systems for terms ranging from one to 15 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion.

Marketing

We generally sell our crude oil, NGL and natural gas oil and NGL products using short-term floating price physical and spot market contracts. For the year ended December 31, 2011,2012, approximately 58%59 percent of our consolidated product revenue wasrevenues were attributable to five of ourfour customers: Connect Energy Services, LLC, a subsidiary of PVR; Enogex, LLC; Chesapeake Operating,Sunoco Refining and Marketing, Inc.; Plains Marketing LP; and Shell Trading (US) Company.

Company; Gulfmark Energy Inc.; and Enterprise Crude Oil LLC.

Commodity Derivative Contracts

We generally utilize collar, swap and swaption derivative contracts, among others, to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.


5


The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap 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 swaption contract gives our counterparties the option to enter into a fixed price swap with us at a future date. If the forward commodity price for the term of the swaption is higher than or equal to the swaption strike price on the exercise date, the counterparty will exercise its option to enter into a fixed price swap at the swaption strike price for the term of the swaption, at which point the contract functions as a fixed price swap. If the forward commodity price for the term of the swaption is lower than the swaption strike price on the exercise date, the option expires and no fixed price swap is in effect.

We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position.

Competition

The oil and natural gas industry is very competitive, and we compete with a substantial number of other companies that are large, well-established and have greater financial and operational resources than we do, which may adversely affect our ability to compete or grow our business. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. Competition is particularly intense in the acquisition of prospective oil and natural gas properties. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. We compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Such equipment and labor may be in short supply from time to time. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. We also compete with substantially larger oil and gas companies in the marketing and sale of oil and natural gas, and the oil and natural gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers.

5

Government Regulation and Environmental Matters


Our operations are subject to stringent and extensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. Compliance with these laws and regulations increases our cost of doing business. Also, environmental laws and regulations have been subject to frequent changes over the years and the imposition of more stringent requirements, including any significant limitation on hydraulic fracturing, could have a material adverse effect on our financial condition and results of operations.

The following is a summary of the significant environmental laws to which our business operations are subject.

CERCLA.The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, is also known as the “Superfund” law. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on parties that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible parties” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease properties that have been used for the exploration and production of oil and natural gas for a number of years. Many of these properties have been operated by third parties whose treatment or release of hydrocarbons or other wastes was not under our control. These properties, and any wastes that may have been released on them, may be subject to CERCLA, and we could potentially be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination.

RCRA. The Resource Conservation and Recovery Act, or the RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and clean up of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of RCRA. While there is currently an exclusion from RCRA for drilling fluids, produced waters and most of the other wastes

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associated with the exploration and production of oil or natural gas, it is possible that some of these wastes could be classified as hazardous waste in the future, and therefore be subject to RCRA.

Oil Pollution Act. The Oil Pollution Act of 1990, as amended, or the OPA, contains numerous restrictions relating to the prevention of and response to oil spills into waters of the United States. The term “waters of the United States” has been interpreted broadly to include inland water bodies, including wetlands and intermittent streams. The OPA subjects owners of facilities to strict, joint and several liability for all containment and clean up costs, and certain other damages arising from a spill.

Clean Water Act. The Federal Water Pollution Control Act, or the Clean Water Act, governs the discharge of certain pollutants into waters of the United States. The discharge of pollutants into regulated waters without a permit issued by the EPA or the state is prohibited. The Clean Water Act also requires the preparation and implementation of Spill Prevention, Control and Countermeasure Plans in connection with on-site storage of significant quantities of oil. Notably, in Pennsylvania, wastewater from the hydraulic fracturing process can no longer be sent to publicly owned treatment works directly. New wastewater discharges must be treated at a centralized waste treatment facility and comply with certain Total Dissolved Solids standards prior to being discharged to publicly owned treatment works. This restriction of disposal options for hydraulic fracturing waste may result in increased costs. The EPA is currently developing analogous pretreatment standards on the federal level.

Safe Drinking Water Act.The Safe Drinking Water Act, or the SDWA, and the Underground Injection Control Program promulgated under the SDWA, establish the requirements for salt water disposal well activities and prohibit the migration of fluid containing contaminants into underground sources of drinking water. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells in which we act as operator. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional plays like the Eagle Ford Shale, Granite Wash, Haynesville Shale and the Marcellus Shale formations. The U.S. Congress is currently considering the Fracturing Responsibility and Awareness of Chemicals Act tothat was introduced in both the 111th and 112th Congresses would subject hydraulic fracturing operations to federal regulation under the SDWA and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. Sponsors of these bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing. Such costs and burdens could delay the development of unconventional gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Additionally, the EPA has commenced a comprehensive research study to investigate the potential adverse environmental impacts of hydraulic fracturing including on drinking water quality and ground water. The EPA released a progress report on its study on December 21, 2012 and expects to release a final draft for public health,comment and a committeepeer review in 2014.
Additionally, certain states in which we operate have adopted regulations requiring the disclosure of chemicals used in the U.S. House of Representatives is also conducting an investigation into hydraulic fracturing practices. The initial EPA study results are expected to be available in late 2012.process. For instance, Mississippi, Oklahoma, Pennsylvania and Texas have implemented chemical disclosure requirements for hydraulic fracturing operations. We currently disclose all hydraulic fracturing additives we use on

Further, in light ofwww.FracFocus.org, a website created by the explosionGround Water Protection Council and fireInterstate Oil and Gas Compact Commission.

Prohibitions and Other Regulatory Limitations on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, thereHydraulic Fracturing. There have been a variety of regulatory initiatives at both the federal and state levelslevel to restrict oil and gas drilling operations in certain locations. For example, Pennsylvania has instituted a moratorium on leasing state forest land for gas drilling.drilling and municipalities in New York have banned or limited hydraulic fracturing within their borders. Additionally, the New York State Department of Environmental Conservation, or NYDEC, has ceased issuing drilling permits for horizontal drilling under the General Environmental Impact Statement, pending completion of the Supplemental General Environmental Impact Statement, or SGEIS, that takes into account the impacts of high volume hydraulic fracturing. However, the NYDEC has stated that it will consider individual, site-specific environmental reviews for any entity that wishes to proceed with a permit application as long as that review is of similar scope and depth as the SGEIS. The most recent draft of the SGEIS was released in September 2011 but final regulations have not yet been issued.
In addition to chemical disclosure rules, some states have implemented permitting, well construction or water withdrawal regulations that may increase the costs of hydraulic fracturing operations. Pennsylvania and West Virginia have issued setback regulations for wells. Colorado recently enacted new setback restrictions as well as requirements to conduct sampling on water wells before and after drilling. In addition, states such as Texas and Pennsylvania have water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source.

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Increased regulation of and attention given by environmental interest groups, as well as state and federal regulatory authorities, to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. These developments could also lead to litigation challenging proposed or operating wells. The adoption of federal, state or local laws or the implementation of regulations regarding hydraulic fracturing that are more stringent could cause a decrease in the completion of new oil and gas wells, as well as increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. We use hydraulic fracturing extensively and any increased federal, state, or local regulation of hydraulic fracturing could reduce the volumes of oil and natural gas that we can economically recover.

Certain states in which we operate have adopted regulations requiring the disclosure of chemicals used in the hydraulic fracturing process. For instance, Texas, Pennsylvania and West Virginia have implemented chemical disclosure requirements for hydraulic fracturing operations. We currently disclose all hydraulic fracturing additives we use on www.FracFocus.org, a website created by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission. In addition to chemical disclosure rules, some states have implemented permitting, well construction or water withdrawal regulations that may increase the costs of hydraulic fracturing operations.

Clean Air Act. Our operations are subject to the Clean Air Act, or the CAA, and comparable state and local requirements. In 1990, the U.S. Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed, and continue to develop, regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Further, stricter requirements could negatively impact our production and operations. For example, the Texas Commission on Environmental Quality and the Railroad Commission of Texas have been evaluating possible additional regulation of air emissions in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state and federal levels.

Additionally, on July 28, 2011,April 17, 2012, the EPA issued proposednew rules that would subjectsubjecting all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs. The EPA published these proposed regulations to comply with a consent decree which required publication of proposed standards on or before July 28, 2011, and promulgation of final standards on or before April 3, 2012. The new rules would regulate emissions from several types of emission sources that have never before been subject to federal standards, and also include NSPS standards for completion of hydraulically fractured gas wells. The standards would apply to newly drilled and fractured wells, as well as existing wells that are refractured. The proposed NESHAPS regulations would apply to certain major sources of hazardous air pollutants not currentlypreviously subject to Maximum Achievable Control Technology, or MACT, standards. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup, or October 15, 2012, whichever is later. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. We are currently researching the effect these proposednew rules couldwill have on our business, but generally expect them to add to the cost and expense of our operations.

There have been recent claims asserted that individual wells and other facilities should be “aggregated” together and their collective emissions considered in determining whether major source permitting requirements apply under the CAA. WereIf we were required to aggregate individual wells and other facilities, it could bring us within the ambit of the Title V permitting program, as well as consideration asand we could be considered a major source for MACT applicability.

Increased regulation of For example, though the Sixth Circuit recently vacated an EPA determination to aggregate natural gas wells and attention given by environmental interest groups, as well as state and federal regulatory authorities, toa sweetening plant in Summit Petroleum Corp. v. EPA et al., the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costsEPA released a December 21, 2012 memorandum stating that although the EPA will follow the court's interpretation when considering aggregation in the productionSixth Circuit, it will continue to follow its current practice of oil and natural gas, including fromconsidering interrelatedness in other jurisdictions. In addition, in Citizens for Pennsylvania's Future v. Ultra Resources, Inc., a case challenging a decision not to aggregate certain facilities in Pennsylvania, the developing shale plays, or could make it more difficultcourt allowed the case to perform hydraulic fracturing. These developments could also leadmove forward by denying defendant's motion to litigation challenging proposed or operating wells. The adoption of federal, state or local laws ordismiss, even though the implementation of regulations regarding hydraulic fracturing that are more stringent could cause a decrease inplaintiff had not exhausted review procedures with the completion of new oil and gas wells, as well as increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

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administrative agency.

Greenhouse Gas Emissions. Both in the United States and worldwide, there is increasing attention being paid to the issue of climate change and the contributing effect of greenhouse gas, or GHG, emissions. On June 28, 2010, the EPA issued the “Final Mandatory Reporting of Greenhouse Gases” Rule, or the Reporting Rule, requiring all stationary sources that emit more than 25,000 tons of greenhouse gasesGHGs per year to collect and report to the EPA data regarding such emissions. The Reporting Rule establishes a new comprehensive scheme, beginningwhich began in 2011, requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions occurring in the prior calendar year on a facility-by-facility basis. On November 9, 2010, the EPA issued final rules applying these regulations to the oil and gas source category, including oil and natural gas production, natural gas processing, transmission, distribution and storage facilities (Subpart W). This action does not require control of GHGs. However, the EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits.

In addition, in 2009, the EPA issued a final rule known as the EPA’sEPA's Endangerment Finding finding that current and projected concentrations of six key GHGs in the atmosphere threaten public health and the environment, as well as the welfare of current and future generations. Legal challenges to these findings have been asserted, and the U.S. Congress is considering legislation to delay or repeal the EPA’sEPA's actions, but we cannot predict the outcome of this litigation or these efforts. The EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. These

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rules are currentlywere subject to judicial challenge, but on June 26, 2012, the D.C.U.S. Court of Appeals for the District of Columbia Circuit has refusedrejected challenges to stay their implementation while the challenges are pending.

Astailoring rule and other EPA rules relating to the regulation of GHGs under the CAA.

Starting July 1, 2011, the EPA requiresrequired facilities that must already obtain New Source Review permits for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year. In December 2010,On March 27, 2012, the EPA issued its plan to update pollution standardsproposed NSPS for fossil fuelcarbon dioxide emissions standard from new and modified power plants and petroleum refineries. The EPA had stated that it intended to propose standards for power plants in July 2011 and for refineries in December 2011 and issue final standardsheld public hearings on the rule in May 2012 and November 2012, respectively. Asaccepted written comments until June 25, 2012. The U.S. Congress has considered a number of early December 2011, the EPA reportedly has prepared a proposallegislative proposals to regulaterestrict GHG emissions from only new plants, not existing ones, but that proposal is pending review at the Office of Management and Budget, and is not yet public. The EPA’s failure to propose rules by the required date will delay final action, as well.

emissions. Also, many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities.

The U.S. Congress has considered a number of legislative proposals to restrict GHG emissions. It presently appears unlikely that comprehensive climate legislation will be passed by either house of the U.S. Congress in the near future, although energy legislation and other initiatives continue to be proposed that may be relevant to GHG emissions issues. In addition, various states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce GHG emissions. While it is not possible at this time to predict how regulation that may be enactedany regulations to addressrestrict GHG emissions would impact our business, the modification of existing lawsmay come into force, these and other legislative and regulatory proposals for restricting GHG emissions or regulations,otherwise addressing climate change could require us to incur additional operating costs or the adoption of new laws or regulations curtailingcurtail oil and gas explorationoperations in thecertain areas of the United States in which we operateand could also adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for the oil and gas.

natural gas we sell.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

OSHA. We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requiresmaintenance of information about hazardous materials used or produced in operations, and the provision of such information to employees,state and local government authorities and citizens.Other OSHA standards regulate specific worker safety aspects of our operations.

Endangered Species Act. The Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species.

Employees and Labor Relations

We and our subsidiaries had a total of 153130 employees as of December 31, 2011.2012. We consider our current employee relations to be favorable. We and our employees are not subject to any collective bargaining agreements.

Available Information

Our internet address ishttp://www.pennvirginia.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics, Audit Committee Charter, Compensation and Benefits Committee Charter and Nominating and Governance Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

All references in this Annual Report on Form 10-K to the “NYSE” refer to the New York Stock Exchange, and all references to the “SEC” refer to the Securities and Exchange Commission.


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 Item 1A    Risk Factors

Item 1ARisk Factors

Our business and operations are subject to a number of risks and uncertainties as described below. However, the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we may currently deem immaterial, may become important factors that harm our business, financial condition or results of operations. If any of the following risks actually occur, our business, financial condition or results of operations could suffer.

Natural

Crude oil, NGL and natural gas and crude oil prices are volatile, and a substantial or extended decline in prices would hurt our profitability and financial condition.


Our revenues, operating results, cash flows, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for natural gas, crude oil, NGLs and NGLs.natural gas. Historically, gascrude oil, NGL and oilnatural gas prices have been volatile, and they are likely to continue to be volatile. Even relatively modest drops in prices can affect significantly our financial results and impede our growth. Wide fluctuations in natural gas, crude oil, NGLs and NGLnatural gas prices may result from relatively minor changes in the supply of and demand for gasoil and oil,natural gas, market demand and other factors that are beyond our control, including:

domestic and foreign supplies of crude oil, NGLs and natural gasgas;
domestic and NGLs;foreign consumer demand for oil and natural gas;

political and economic conditions in oil or gas producing regions;

overall domestic and foreign economic conditions;

prices and availability of, and demand for, alternative fuels;

the availability of gathering, processing and transportation facilities;

weather conditions; and

domestic and foreign governmental regulation.

Some


Many of our projections and estimates are based on assumptions as to the future prices of gascrude oil, NGLs and oil.natural gas. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future will likely differ from our estimates. Any substantial or extended decline in the actual prices of crude oil, NGLs or natural gas or crude oil would have a material adverse effect on our business, financial position and results of operations (including reduced cash flows, borrowing capacity and possible asset impairment), the quantities of gasoil and oilnatural gas reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.

Our future performance depends on our ability to find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operations. We have historically succeeded in substantially replacing reserves primarily through exploration and development and, to a lesser extent, acquisitions. We have conducted such activities on our existing oil and gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves and production from such activities at acceptable costs. Currently depressed gas prices may further limit the types of reserves that can be developed at acceptable costs.economically. Lower prices also decrease our cash flows and may cause us to reduce capital expenditures.

The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves if cash flows from operations are reduced and external sources of capital are limited. In addition, exploration and development activities involve numerous risks that may result in dry holes, the failure to produce oil and gas in commercial quantities and the inability to fully produce discovered reserves.

We are continually identifying and evaluating acquisition opportunities. However, competition for producing oil and gas properties is intense and many of our competitors have financial and other resources substantially greater than those available to us. In the event we are successful in completing an acquisition, we cannot ensure that such acquisition will consist of properties that contain economically recoverable reserves or that such acquisition will be profitably integrated into our operations.



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We may not be able to fund our planned capital expenditures.

We make, and will continue to make, substantial capital expenditures to find, acquire, develop and produce oil and natural gas reserves. In 2012,2013, we anticipate making capital expenditures, excluding acquisitions, of up to approximately $325$400 million.


If crude oil or NGL prices decrease, natural gas prices fail to recover or we encounter operating difficulties that result in our cash flow from operations being less than expected, we may have to reduce theour capital we can spendexpenditures unless we have borrowing capacity under our Revolver, or we can raise additional funds through asset sales or a debt or equity financing.

the Revolver.


Future cash flows and the availability of financing will also be subject to a number of variables, such as our success in locating and producing new reserves, the level of production from existing wells and prices of crude oil, NGLs and natural gas.

If our revenues were to decrease due to lower crude oil, NGL and natural gas prices, decreased production or other reasons, and if we could not obtain capital through the Revolver, or otherwise on acceptable terms, our ability to execute our development plans, replace our reserves or maintain production levels could be greatly limited.

We have a significant amount of indebtedness and our ability to service our indebtedness depends on certain financial, business and other factors, many of which are beyond our control.

At December 31, 2012, we had an aggregate of approximately $600 million of debt outstanding and would have been able to incur an additional $297.9 million (net of $2.1 million of letters of credit) under the Revolver. We may incur additional indebtedness in the future. Subject to certain conditions, our existing debt instruments do not prohibit us from incurring additional indebtedness. Any increase in our level of indebtedness will have several important effects on our future operations, including, without limitation:

we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;
increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry conditions, as well as to competitive pressure; and
depending on the levels of our outstanding debt, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited.

Our ability to make scheduled payments of principal and interest on our indebtedness or to refinance our debt obligations depends on our future financial condition and operating performance, which will be subject to general economic conditions and to certain financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flows from operations in the future to service our debt, we may be forced, among other things, to:
seek additional financing in the debt or equity markets;
refinance or restructure all or a portion of our indebtedness;
sell selected assets;
reduce or delay planned capital expenditures; or
reduce or delay planned operating expenditures.

Such measures might not be successful and might not enable us to service our debt. In addition, any such financing, refinancing or sale of assets might not be available on economically favorable terms.

The borrowing base under ourthe Revolver may be reduced in the future if commodity prices decline.


The borrowing base under ourthe Revolver is $380$300 million as of December 31, 2011.2012. Our borrowing base is re-determined twice a year and is scheduled to be redetermined during April 2012. Due primarily to depressed2013. If crude oil, NGL or natural gas prices and a decrease in our proved developed reserves, we anticipate thatdecline, the borrowing base under the Revolver may be materially reduced. As a result, we may be unable to obtain adequate funding under ourthe Revolver. If funding is not available when or in the amounts needed, or is available only on unfavorable terms, it might adversely affect our development plan as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, financial condition and results of operations.


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The Revolver and our other debt instruments have restrictive covenants that could limit our financial flexibility.

The Revolver and the indentures related to our outstanding senior notes contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the Revolver is subject to compliance with certain financial covenants, including leverage and interest coverage ratios. The Revolver includes other restrictions that, among other things, limit our ability to incur indebtedness; grant liens; engage in mergers, consolidations and liquidations; make asset dispositions, restricted payments and investments; enter into transactions with affiliates; and amend, modify or prepay certain indebtedness. The indentures related to our outstanding senior notes contain limitations on our ability to effect mergers and change of control events, as well as other limitations, including:
limitations on the declaration and payment of dividends or other restricted payments;
limitations on incurring additional indebtedness or issuing preferred stock;
limitations on the creation or existence of certain liens;
limitations on incurring restrictions on the ability of certain of our subsidiaries to pay dividends or other payments;
limitations on transactions with affiliates; and
limitations on the sale of assets.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

Exploration and development drilling may not result in commercially productive reserves.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas or oil reserves will be found. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

unexpected drilling conditions;

elevated pressure or irregularities in geologic formations;

equipment failures or accidents;

costs, of, or shortages or delays in the availability of drilling rigs, crews, equipment and materials;

shortages in experienced labor;

failure to or delays in securing necessary regulatory approvals and permits, including delays due to potential hydraulic fracturing regulations;

title problems;

fires, explosions, blow-outs and surface cratering; and

adverse weather conditions.


The prevailing prices of crude oil, NGLs and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs and equipment can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.

The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas or oil is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. In addition, limitations on the use of hydraulic fracturing could have an adverse affecteffect on our ability to develop and produce oil and natural gas from new wells, which would reduce our rate of return on these wells and our cash flows. Drilling activities can result in dry wells or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs.


Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our business, financial condition and results of operations. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.


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We are exposed to the credit risk of our customers, and joint interest partners, and nonpayment or nonperformance by these parties would reduce our cash flows.

We are subject to risk from loss resulting from our customers’ and joint interest partners’customers' nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of revenues. In 2011, 58%2012, 59 percent of our total consolidated product revenues resulted from fivefour of our customers. Any nonpayment or nonperformance by our customers would reduce our cash flows.


We participate in oil and gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.
We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one party. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. In addition, the possibility of an economic downturn and the volatility in commodity prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established than we, are not able to fulfill their joint activity obligations. Some of our project partners have experienced liquidity and cash flow problems. These problems may lead our partners to attempt to delay the pace of drilling or project development in order to preserve cash. A partner may be unable or unwilling to pay its share of project costs. In some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial condition and results of operations.

Our business involves many operating risks, including hydraulic fracturing, that may result in substantial losses for which insurance may be unavailable or inadequate.

Our operations are subject to all of the risks and hazards typically associated with the exploitation, development and exploration for and the production and transportation of oil and natural gas, including well stimulation and completion activities such as hydraulic fracturing. These operating risks include:

fires, explosions, blowouts, cratering and casing collapses;

formations with abnormal pressures;

pipeline ruptures or spills;

uncontrollable flows of oil, natural gas or well fluids;

migration of fracturing fluids into surrounding groundwater;

spills or releases of fracturing fluids including from trucks sometimes used to deliver these materials;

spills or releases of brine or other produced water that may go off-site;

subsurface conditions that prevent us from (i) stimulating the planned number of stages, (ii) accessing the entirety of the wellbore with our tools during completion or (iii) removing all fracturing materials from the wellbore to allow production to begin;

environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases;

personal injuries and death; and

natural disasters.


Any of these risks could result in substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

If we experience any of these problems with well stimulation and completion activities, such as hydraulic fracturing, our ability to explore for and produce oil or natural gas or oil may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of:

the need to shutdown,shut down, abandon and relocate drilling operations;
the need to sample, test and monitor drinking water in particular areas and to provide filtration or other drinking water supplies to users of water supplies that may have been impacted or threatened by potential contamination from fracturing fluids;

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the need to modify drill sites to ensure there are no spills or releases off-site and to investigate and/or remediate any spills or releases that might have occurred; andor
suspension of our operations.


In accordance with industry practice, we maintain insurance at a level that balances the cost of insurance with our assessment of the risk and our ability to achieve a reasonable rate of return on our investments. We cannot assure you that our insurance will be adequate to cover losses or liabilities or that we can purchase insurance against all possible losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our business, financial condition and results of operations.

Our business depends on gathering, processing and transportation facilities owned by others.

We deliver substantially all of our oil and natural gas production through pipelines that we do not own. The marketability of our production depends upon the availability, proximity and capacity of these pipelines, as well as gathering systems and processing facilities. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal, state and local regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather, process and market our oil and natural gas.

Estimates of oil and natural gas reserves are not precise.

This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to crude oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and, therefore, changes often occur as these variables evolve and commodity prices fluctuate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the estimated quantities and present value of our reserves.

Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil, NGL and natural gas prices and other factors, many of which are beyond our control.

At December 31, 2011,2012, approximately 51%59 percent of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.


Moreover, the reserve estimation standards provide that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These standards may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not develop those reserves within the required five-year time frame or cannot demonstrate that we could do so. We removed approximately 8.7 MMBOE of proved undeveloped reserves in 2012 as a result of the five-year limitation.
You should not assume that the present value of estimated future net cash flows (standardized measure) referred to herein is the current fair value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. As a result, net present value estimates using actual prices and costs may be significantly less than the SEC estimate that is

14


provided herein. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor for us.

We may record impairment losses on our oil and gas properties.

Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment. Lower crude oil, NGL and natural gas prices may have the impact of shortening the economic lives on certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, thus reducing proved property reserve estimates. If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of depreciation, depletion and amortization, or DD&A, on the affected properties, which would decrease earnings or result in losses through higher DD&A expense. The revisions may also be sufficient enough to cause impairment losses on certain properties that would result in a further non-cash charge to reported earnings.

GAAP requires that the carrying value of oil and gas properties be reviewed on a periodic basis for possible impairment. An impairment charge is recognized when the carrying value of oil and gas properties is greater than the undiscounted future net cash flows attributable to the property. In addition to revisions to reserves and the impact of lower commodity prices, impairments may occur due to increases in estimated operating and development costs.costs and other factors. During the past several years, we have been required to impair certain of our oil and gas properties and related assets. If natural gas, crude oil, NGL and NGLnatural gas prices decline or we drill uneconomic wells, it is reasonably possible that we will have to record a significant impairment in the future. While an impairment charge reflects our ability to recover the carrying value of our investments, it does not impact our cash flows from operating activities.

We have limited control over the activities on properties we do not operate.

In 2011,2012, other companies operated approximately 23%17 percent of our net production. Our success in properties operated by others will depend upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’soperator's expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.

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

Under certain circumstances, certain of the other working interest owners in our properties have the right to limit the amount of drilling activities that can take place on our properties at any given time. If these working interest owners chose to exercise this right, we could be required to scale back anticipated drilling activities on the affected properties. In such an event, production from the affected properties would be deferred, thereby decreasing production from the properties in the short-term.

Our producing property acquisitions carry significant risks.

Acquisition of producing oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. In the event we do complete an acquisition, its success will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future crude oil, NGL and natural gas prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves, actual future production rates and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.


15


We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state and local laws and regulations, including complex environmental laws. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations or financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs and land owners may file claims for alternative water supplies, property damage or bodily injury. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. In addition, pollution and similar environmental risks generally are not fully insurable. These liabilities and costs could have a material adverse effect on our business, financial condition or results of operations. See Item 1, “Business—“Business — Government Regulation and Environmental Matters.”

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The practice of hydraulic fracturing has come under increased scrutiny by the environmental community. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into prospective rock formations to stimulate oil and natural gas production. We use this completion technique on substantially all of our wells. The EPA has commenced a study of the potential environmental impact of hydraulic fracturing, with initial results of the study anticipated to be available by late 2012.fracturing. The EPA also announced that one of its enforcement initiatives for 2011 to 2013 is to focus on environmental compliance by the energy extraction sector. Also, the Secretary of Energy Advisory Board has established a Natural Gas Subcommittee to make recommendations on improving safety and environmental performance of hydraulic fracturing. In addition, some states and local governments have enacted legislation or adopted regulations, and the U.S. Congress and other states are considering enacting legislation or adopting regulations, that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Individually or collectively, such new legislation or regulation could result in increased compliance and operating costs, delays or additional operating restrictions. If the use of hydraulic fracturing is limited, prohibited or prohibited, itsubjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition and results of operations.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The U.S. Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act, was signed into law on July 21, 2010 and requires the Commodities Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. The Act may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, financial condition and  results of operations.

Derivative transactions may limit our potential gains and involve other risks.

In order to manage our exposure to price risks in the sale of our crude oil, NGLs and natural gas, we periodically enter into oil and gascommodity price hedging arrangements with respect to a portion of our expected production. Our hedges are limited in duration, usually for periods of two years or less. While intended to reduce the effects of volatile crude oil, NGL and natural gas prices, such transactions may limit our potential gains if crude oil, NGL or natural gas prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how crude oil, NGL or natural gas prices fluctuate in the future.

In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

our production is less than expected;

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

the counterparties to our futures contracts fail to perform under the contracts; or

a sudden, unexpected event materially impacts crude oil, NGL or natural gas prices.


In addition, derivative instruments involve basis risk. Basis risk in a derivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.



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The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act, was enacted that establishes federal oversight regulation of over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodities Futures Trading Commission, or CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September 2012, although the CFTC has stated that it will appeal the District Court's decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements, although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us or the timing of such effects. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Act and associated regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and associated regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.

Our ability to utilize U.S. net operating loss. or NOL, carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended, or the Code. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of our stock by 5% shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. As of December 31, 2012, we do not believe that an ownership change has occurred; however, to the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than they otherwise would be paid if such limitations were not in effect.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation.

Legislation has been proposed in the U.S. Congress that would, if enacted into law, make significant changes to U.S. federal income tax laws, including

President Obama's budget proposal for fiscal year 2013 recommended the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, the repeal of the percentage depletion allowance for oil and natural gas properties, the elimination of current deductions for intangible drilling and development costs, the elimination of the deduction for certain domesticUnited States production activities for oil and gas production, and an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could have a material adverse effect on us.





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Item 1BUnresolved Staff Comments

We have received no written SEC staff comments regarding our periodic or current reports under the Exchange Act whichthat were issued 180 days or more preceding the end of our 20112012 fiscal year thatand remain unresolved.


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Item 2
Properties


The following map shows the general locations of our oil and gas production investments and our regional office locations as of December 31, 2011:

2012:

Facilities

We are headquartered


Our headquarters and corporate office is located in Radnor, Pennsylvania with regional officesand our primary operations are conducted from our office in Pittsburgh, Pennsylvania and Houston, Texas. We also have district operations facilities at various locations in Texas, Oklahoma Mississippi, Pennsylvania and West Virginia.Mississippi. All of our office facilities are leased with the exception of our district operations facilities in Scottsville, Texas and Ravencliff, West Virginia.Texas. We believe that our facilities are adequate for our current needs.


Title to Oil and Gas Properties

Prior to completing an acquisition of producing oil and gas assets, we review title opinions on all material leases. However, as is customary in the oil and gas industry, we make only a cursory review of title to farmout acreage and towhen we acquire undeveloped oil and gas leases. Prior to the commencement of drilling operations, a thorough title examination is conducted. To the extent the title examination reflects defects, we cure such title defects. If we are unable to cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, we could suffer a loss of our investment in the property. Our oil and gas properties are subject to customary royalty interests, liens for debt obligations, current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties. We believe that we have satisfactory title to all of our properties and the associated oil and natural gas in accordance with standards generally accepted in the oil and natural gas industries.


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Preparation of Reserves Estimates

Our policies and practices regarding the recording of reserves isare structured to objectively and accurately estimate our oil and gas reservesreserve quantities and present values in compliance with the SEC’s regulations and GAAP. Our Manager of Engineering is primarily responsible for overseeing the preparation of the reserve estimate by our independent third party engineers, Wright & Company, Inc. Our Manager of Engineering has over 2627 years of industry experience in the estimation and evaluation of reserve information, holds a B.S. degree in Petroleum Engineering from Texas A&M University and is licensed by the stateState of Texas as a Professional Engineer. The Company’sOur internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

The technical person primarily responsible for review of our reserve estimates at Wright & Company, Inc., meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Wright & Company, Inc. is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. For additional information about the risks inherent in our estimates of proved reserves, see Item 1A, “Risk-Factors.“Risk Factors.”


Summary of Oil and Gas Reserves

Proved Reserves

The following tables present certain information regarding our proved reserves as of December 31, 2012, 2011 2010 and 2009.2010. The proved reserve estimates presented below were prepared by Wright & Company, Inc., independent petroleum engineers. For additional information regarding estimates of proved reserves and other information about our oil and natural gas reserves, see the Supplemental Information on Oil and Gas Producing Activities (Unaudited) in the Notes to the Consolidated Financial Statements and the report of Wright & Company, Inc., which is included as an Exhibit to this Annual Report on Form 10-K. We did not file any reports during the year ended December 31, 20112012 with any federal authority or agency with respect to our estimate of oil and natural gas reserves.

  Natural 
  Natural
Gas		  Oil and
Condensate		  Gas
Equivalents		  Standardized
Measure		  Price Measurement Used1 
  (Bcf)  (MMBbl)  (Bcfe)  $ in millions  $/MMBtu  $/Bbl 
2011                        
 Developed  331   16.5   429  $602         
 Undeveloped  339   19.1   454   52         
  670   35.6   883  $654  $3.95  $92.22 
2010                        
 Developed  413   14.8   502  $574         
Undeveloped  332   18.0   440   67         
  745   32.8   942  $641  $4.38  $79.43 
2009                        
 Developed  388   8.4   439  $425         
 Undeveloped  389   18.0   496   100         
  777   26.4   935  $525  $3.87  $61.18 

 Oil NGLs 
Natural
Gas
 
Oil
Equivalents
 
Standardized
Measure
 
Price Measurement Used 1
 (MMBbl) (MMBbl) (Bcf) (MMBOE) $ in millions $/Bbl of Oil $/Bbl of NGLs $/MMBtu
2012 
    
  
  
  
  
  
Developed10.5
 8.3
 169
 47.0
 $452
  
  
  
Undeveloped14.4
 12.4
 238
 66.5
 46
  
  
  
 24.9
 20.7
 407
 113.5
 $498
 $102.24
 $39.48
 $2.47
2011 
    
  
  
  
  
  
Developed7.1
 9.4
 331
 71.6
 $602
  
  
  
Undeveloped7.0
 12.1
 339
 75.6
 52
  
  
  
 14.1
 21.5
 670
 147.2
 $654
 $92.22
 $50.69
 $3.95
2010 
    
  
  
  
  
  
Developed4.0
 10.8
 413
 83.6
 $574
  
  
  
Undeveloped4.0
 14.0
 332
 73.4
 67
  
  
  
 8.0
 24.8
 745
 157.0
 $641
 $79.43
 $41.14
 $4.38

1Natural gasOil, NGL and oilnatural gas prices were based on average (beginning of month basis) sales prices per McfBbl and BblMMBtu with the representative price of natural gas adjusted for basis premium and energy content to arrive at the appropriate net price.



19


All of our reserves are located in the continental United Sates.States. The following table sets forth by region the estimated quantities of proved reserves and the percentages thereof that are represented by proved developed reserves as of December 31, 2011:

     % of Total    
  Proved  Proved  % Proved 
Region Reserves  Reserves  Developed 
    (Bcfe)         
Texas  468   53%  36%
Appalachia  146   17%  74%
Mid-Continent  99   11%  71%
Mississippi  170   19%  47%
   883   100%    

Significant Reserves

Our Carthage field in the Cotton Valley and Haynesville Shale plays in East Texas represents approximately 29% of our total proved reserves as of December 31, 2011. This is the only field that comprises 15% or more of our total proved reserves as of that date. The following table sets forth certain information with respect to our Carthage field for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Production:            
 Natural gas (MMcf)  8,417   9,725   9,081 
 Crude oil and NGLs (MBbl)  546   496   517 
             
Average prices:            
 Natural gas ($ per Mcfe) $3.69  $4.13  $3.71 
 Crude oil  and NGLs ($ per Bbl) $58.36  $47.28  $34.84 
             
Production cost (aggregate $ per Mcfe) $1.36  $1.03  $1.27 

2012:

  Proved 
% of Total
Proved
 % Proved
Region Reserves Reserves Developed
  (MMBOE)  
  
Texas 82.9
 73.0% 33.2%
Mid-Continent 12.5
 11.0% 79.2%
Mississippi 17.6
 15.5% 53.8%
Appalachia (Marcellus Shale) 0.5
 0.5% 22.6%
  113.5
 100.0%  

Proved Undeveloped Reserves

The proved undeveloped reserves included in our reserve estimates relate to wells that are forecasted to be drilled within the next five years. The following table sets forth the changes in our proved undeveloped reserves during the year ended December 31, 2011:

     Oil and  Natural Gas 
  Natural Gas  Condensate  Equivalents 
    (Bcf)    (MMBbl)    (Bcfe) 
             
Proved undeveloped reserves at beginning of year  332   18.0   440 
 Revisions of previous estimates  (22)  (2.6)  (38)
 Extensions, discoveries and other additions  46   4.8   76 
 Sale of reserves in place  (9)  -   (9)
 Conversion to proved developed reserves  (8)  (1.1)  (15)
Proved undeveloped reserves at end of year  339   19.1   454 

As of December 31, 2011,2012:

 Oil NGLs Natural Gas Oil Equivalents
 (MMBbl) (MMBbl) (Bcf) (MMBOE)
Proved undeveloped reserves at beginning of year7.0
 12.1
 339
 75.6
Revisions of previous estimates(1.0) (1.3) (104) (19.6)
Extensions, discoveries and other additions10.6
 2.2
 11
 14.6
Sale of reserves in place—
 —
 (4) (0.6)
Conversion to proved developed reserves(2.2) (0.6) (4) (3.5)
Proved undeveloped reserves at end of year14.4
 12.4
 238
 66.5

In 2012, our proved undeveloped reserves increaseddecreased by 9.1 MMBOE to 454 Bcfe from 440 Bcfe66.5 MMBOE as of December 31, 2010.2012 from 75.6 MMBOE as of December 31, 2011. We experienced performance-relatednegative revisions of approximately 38 Bcfe, including downward revisions19.6 MMBOE, consisting of 20 Bcfe10.5 MMBOE due primarily to interference with offsetting and adjacent wells in the Granite Wash and minor performance-related revisions in other areas, as well as 18 Bcfe due to a combination of factors that included non-participation, lease expirations, the effect of lower natural gas pricespricing and 9.1 MMBOE due to locations that are not expected to be developeddrilled during a five-year period. During 2011, we had proved undeveloped reserveperiod (primarily in the Selma Chalk and Haynesville plays), non-participation and lease expirations. Extensions, discoveries and other additions of 76 Bcfe, including approximately 45 Bcfe of natural gas primarily in the Marcellus Shale in Pennsylvania and Selma Chalk in Mississippi and approximately 31 Bcfe of natural gas, crude oil and NGLs14.6 MMBOE were attributable exclusively to our activities in the Eagle Ford Shale in Texas.Shale. We had a decrease of 9 Bcfe0.6 MMBOE due to the sale of substantially all of our properties, including proved undeveloped locations, in the Arkoma Basin. Finally,West Virginia, Kentucky and Virginia. In addition, we converted approximately 15 Bcfe, primarily3.5 MMBOE from proved undeveloped to proved developed classification, consisting of 16 wells in the Eagle Ford Shale (2.4 MMBOE) and six wells in the Granite Wash to proved developed reserves.

(1.1 MMBOE).


During 2011,2012, we incurred capital expenditures of approximately $40$116.9 million in connection with the conversion of proved undeveloped reserves to proved developed reserves.

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20


Oil and Gas Production Volumes, Prices and Costs

Oil and Gas Production by Region

The following tables set forth by region the average daily production and total production for the periods presented:

  Average Daily Production  Total Production 
  for the Year Ended December 31,  for the Year Ended December 31, 
Region 2011  2010  2009  2011  2010  2009 
        (MMcfe)             (MMcfe)      
Texas  48.9   37.1   35.9   17,854   13,526   13,116 
Appalachia  24.8   28.5   31.4   9,063   10,397   11,465 
Mid-Continent 1  35.8   42.0   35.1   13,082   15,340   12,826 
Mississippi  18.0   20.9   21.5   6,554   7,643   7,822 
Gulf Coast2  -   0.8   15.8   -   295   5,771 
   127.5   129.3   139.7   46,553   47,201   51,000 

  
Average Daily Production
for the Year Ended December 31,
 
Total Production
for the Year Ended December 31,
Region 2012 2011 2010 2012 2011 2010
   
 (BOEPD)   
  
 (MBOE)   
Texas 10,030
 8,150
 6,175
 3,671
 2,976
 2,254
Mid-Continent 1
 3,309
 5,973
 7,005
 1,211
 2,180
 2,557
Mississippi 2,314
 2,993
 3,490
 847
 1,092
 1,274
Appalachia 2
 2,143
 4,138
 4,747
 784
 1,511
 1,733
Gulf Coast 3
 —
 —
 135
 —
 —
 49
  17,796
 21,254
 21,552
 6,513
 7,759
 7,867
________________________
1We sold a substantial portion of our Arkoma Basin properties in August 2011, which represented estimated annual production ofapproximately 4 Bcfe.

700 MBOE (1,800 BOEPD).

2 We sold all of our properties in West Virginia, Kentucky and Virginia in July 2012, which represented annual production of approximately 1,500 MBOE (4,100 BOEPD).
3We completed the sale of our Gulf Coast properties in January 2010.


Production Prices and Costs

The following table sets forth the average sales prices per unit of volume and our production costs, not including ad valorem and severance taxes, per unit of production for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Average prices:         
 Natural gas ($ per Mcf) $4.10  $4.40  $3.91 
 Crude oil ($ per Bbl) $93.19  $75.56  $57.68 
 NGLs ($ per Bbl) $47.83  $39.69  $29.86 
             
Production cost (aggregate $ per Mcfe) $1.12  $1.06  $1.09 

 Year Ended December 31,
 2012 2011 2010
Average prices:     
Crude oil ($ per Bbl)$101.95
 $93.19
 $75.56
NGLs ($ per Bbl)$35.13
 $47.83
 $39.69
Natural gas ($ per Mcf)$2.46
 $4.10
 $4.40
Production cost (aggregate $ per BOE)$6.98
 $6.72
 $6.35

21


Significant Fields
Our Carthage field in East Texas, consisting of our Cotton Valley and Haynesville Shale properties, represents approximately 35% of our total equivalent proved reserve quantities as of December 31, 2012. Our Eagle Ford Shale play in Gonzales and Lavaca Counties in South Texas, which primarily contains oil reserves, represents approximately 23% of our total equivalent proved reserve quantities as of December 31, 2012. These are the only fields that comprise 15% or more of our total proved reserves as of that date.
The following table sets forth certain information with respect to these fields for the periods presented:
 Year Ended December 31,
 2012 2011 2010
Carthage Field     
Production: 
  
  
Crude oil (MBbl)68
 106
 106
NGLs (MBbl)281
 440
 390
Natural gas (MMcf)5,467
 8,417
 9,725
Average prices: 
  
  
Crude oil ($ per Bbl)$96.61
 $93.97
 $77.89
NGLs ($ per Bbl)$36.31
 $49.82
 $39.00
Natural gas ($ per Mcfe)$2.30
 $3.69
 $4.13
Production cost (aggregate $ per BOE)$6.24
 $8.16
 $6.18
      
Eagle Ford Shale 1
     
Production:     
Crude oil (MBbl)1,960
 751
 —
NGLs (MBbl)205
 55
 —
Natural gas (MMcf)1,015
 277
 —
Average prices:     
Crude oil ($ per Bbl)$103.33
 $93.74
 $—
NGLs ($ per Bbl)$31.43
 $51.21
 $—
Natural gas ($ per Mcfe)$2.56
 $3.66
 $—
Production cost (aggregate $ per BOE)$8.83
 $6.26
 $—
___________________
1 Production began in the Eagle Ford Shale in 2011.


22


Drilling Activities


Wells Drilled


The following table sets forth the gross and net exploratorydevelopment and developmentexploratory wells that we drilled during the years ended December 31, 2012, 2011 and 2010 and 2009 as well as wells that were in progress at the end of each year. The number of wells drilled refers to the number of wells completed at any time during the year, regardless of when drilling was initiated.

  2011  2010  2009 
  Gross  Net  Gross  Net  Gross  Net 
Development                        
Productive  45   32.1   59   40.0   25   16.9 
Non-productive  -   -   -   -   1   1.0 
Under evaluation  2   1.3   -   -   4   1.8 
Total development  47   33.4   59   40.0   30   19.7 
                         
Exploratory                        
Productive  5   3.8   5   2.7   2   1.0 
Non-productive  4   2.7   3   1.2   -   - 
Under evaluation  -   -   1   0.5   -   - 
Total exploratory  9   6.5   9   4.4   2   1.0 
Total  56   39.9   68   44.4   32   20.7 
                         
Wells in progress at end of year  7   5.8   6   3.5   2   1.5 

 2012 2011 2010
 Gross Net Gross Net Gross Net
Development 
  
  
  
  
  
Productive36
 27.8
 45
 32.1
 59
 40.0
Non-productive—
 —
 —
 —
 —
 —
Under evaluation—
 —
 2
 1.3
 —
 —
Total development36
 27.8
 47
 33.4
 59
 40.0
            
Exploratory 
  
  
  
  
  
Productive5
 3.9
 5
 3.8
 5
 2.7
Non-productive—
 —
 4
 2.7
 3
 1.2
Under evaluation1
 1.0
 —
 —
 1
 0.5
Total exploratory6
 4.9
 9
 6.5
 9
 4.4
Total42
 32.7
 56
 39.9
 68
 44.4
            
Wells in progress at end of year3
 2.7
 7
 5.8
 6
 3.5
The following table sets forth the regions in which we drilled our wells for the periods presented:

  2011  2010  2009 
Region Gross  Net  Gross  Net  Gross  Net 
Texas  32   26.7   12   11.1   10   9.5 
Appalachia  5   4.3   1   0.8   2   2.0 
Mid-Continent  19   8.9   41   18.7   17   6.2 
Mississippi  -   -   14   13.8   3   3.0 
Total  56   39.9   68   44.4   32   20.7 

  2012 2011 2010
Region Gross Net Gross Net Gross Net
Texas 35
 29.5
 32
 26.7
 12
 11.1
Mid-Continent 7
 3.2
 19
 8.9
 41
 18.7
Mississippi —
 —
 —
 —
 14
 13.8
Appalachia —
 —
 5
 4.3
 1
 0.8

 42
 32.7
 56
 39.9
 68
 44.4
Present Activities

As of December 31, 2011,2012, we had seventhree gross (5.8(2.7 net) wells in progress, all of which were located in the Eagle Ford Shale play in South Texas. As of February 21, 2011, six20, 2013, two of these wells, which were Eagle Ford Shale wells, had been successfully completed and placed on production and theproduction. The remaining well is waiting on completion. Our two (1.3) net wellstargeting the Pearsall Shale remains under evaluation are located in the Marcellus Shale in Pennsylvania.

evaluation.


Delivery Commitments

We generally sell our oil, NGL and natural gas oil and NGL products using short-term floating price physical and spot market contracts. Although it is not our general practice, from time to time we enter into certain transactions in which we provide production commitments extending beyond one month. As of December 31, 2011,2012, we did not have any material commitments to provide a fixed and determinable quantity of our natural gas, crude oil or NGL productionproducts beyond the current month.


23


Productive Wells


The following table sets forth the number of productive wells in which we had a working interest as of December 31, 2011:

  Primarily Natural Gas  Primarily Oil  Total 
Region Gross  Net  Gross  Net  Gross  Net 
Texas  359   255.6   29   24.3   388   279.9 
Appalachia  671   566.0   -   -   671   566.0 
Mid-Continent  94   40.7   10   6.8   104   47.5 
Mississippi  569   549.2   -   -   569   549.2 
   1,693   1,411.5   39   31.1   1,732   1,442.6 

2012:

  Primarily Oil Primarily Natural Gas Total
Region Gross Net Gross Net Gross Net
Texas 69
 57.4
 358
 254.9
 427
 312.3
Mid-Continent 11
 7.1
 97
 41.8
 108
 48.9
Mississippi —
 —
 565
 546.6
 565
 546.6
Appalachia —
 —
 3
 3.0
 3
 3.0
  80
 64.5
 1,023
 846.3
 1,103
 910.8
Of the total wells presented in the table above, we are the operator of 1,5031,007 gross (1,465 gas(78 oil and 38 oil)929 gas) and 1,358.7880.5 net (1,328.1 gas(63.9 oil and 30.6 oil)816.6 gas) wells. In addition to the above working interest wells, we own royalty interests in 2,884seven gross wells.


Acreage


The following table sets forth our developed and undeveloped acreage as of December 31, 20112012 (in thousands):

 Developed   Undeveloped   Total 
 Gross   Net   Gross   Net   Gross   Net 
                         875                          813                          465                          274                       1,340                       1,087

  Developed  Undeveloped  Total 
Region Gross  Net  Gross  Net  Gross  Net 
Texas 68
 50.3
 25
 17.5
 93
 67.8
Mid-Continent 20
 10.7
 83
 44.6
 103
 55.3
Mississippi 37
 27.7
 3
 1.9
 40
 29.6
Appalachia 2
 1.3
 46
 37.0
 48
 38.3
  127
 90.0
 157
 101.0
 284
 191.0

Our total net acreage is locateddecreased by approximately 80 percent in Texas, Appalachia,2012 due to the Mid-Continentsale of our legacy properties in West Virginia, Kentucky and Mississippi regions of the United States.Virginia. The primary terms of our remaining leases generally range from three to five years and we do not have any concessions. As of December 31, 2011,2012, our net undeveloped acreage is scheduled to expire as shown in the table below, unless the primary lease terms are extended, held by production or otherwise changed:

   2012   2013  2014   Thereafter
 Percent of gross undeveloped acreage  16%  38%  9%  37%
 Percent of net undeveloped acreage  13%  18%  10%  59%

 2013 2014 2015 Thereafter
Percent of gross undeveloped acreage56% 23% 15% 6%
Percent of net undeveloped acreage47% 27% 17% 9%

We do not believe that the scheduled expiration of our undeveloped acreage will substantially affect our ability or plans to conduct our exploration and development activities. The amount of acreage expiring in 2013 includes a large non-operated lease positionis located primarily in Appalachia in which we hold a 25% interest; we have no remaining capitalized costs relatedthe Anadarko Basin and the Marcellus Shale, areas that are not integral to this lease. 

our capital program.
Item 3Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. See Item 1, “Business—Government Regulation and Environmental Matters,” for a more detailed discussion of our material environmental obligations.


Item 4ReservedMine Safety Disclosures


Not applicable.

24


Part II


Item 5Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock is traded on the NYSE under the symbol “PVA.” The high and low sales prices (composite transactions) and dividends declared related to each fiscal quarter in 20112012 and 20102011 were as follows:

        Cash 
  Sales Price  Dividends 
Quarter Ended High  Low  Declared 
December 31, 2011 $6.97  $4.21  $0.05625 
September 30, 2011 $14.12  $5.47  $0.05625 
June 30, 2011 $17.20  $12.88  $0.05625 
March 31, 2011 $18.31  $14.40  $0.05625 
December 31, 2010 $18.80  $13.99  $0.05625 
September 30, 2010 $20.50  $13.38  $0.05625 
June 30, 2010 $29.25  $19.63  $0.05625 
March 31, 2010 $27.80  $21.64  $0.05625 

      Cash
  Sales Price Dividends
Quarter Ended High Low Declared
December 31, 2012 $6.72
 $4.07
 $—
September 30, 2012 $7.74
 $6.01
 $—
June 30, 2012 $7.37
 $3.92
 $0.05625
March 31, 2012 $6.27
 $4.27
 $0.05625
December 31, 2011 $6.97
 $4.21
 $0.05625
September 30, 2011 $14.12
 $5.47
 $0.05625
June 30, 2011 $17.20
 $12.88
 $0.05625
March 31, 2011 $18.31
 $14.40
 $0.05625
Equity Holders


As of February 10, 2012,15, 2013, there were 453440 record holders and approximately 6,3307,216 beneficial owners (held in street name) of our common stock.



25


Performance Graph

The following graph compares our five-year cumulative total shareholder return (assuming reinvestment of dividends) with the cumulative total return of the Standard & Poor’s 600 Oil & Gas Exploration & Production Index and the Standard & Poor’s Small Cap 600 Index. As of December 31, 2011,2012, there were nineten companies in the Standard & Poor’s 600 Oil & Gas Exploration & Production Index: Approach Resources Inc., Carrizo Oil & Gas, Inc., Comstock Resources, Inc., Contango Oil & Gas Company, GeoResources Inc., Gulfport Energy Corporation, PDC Energy, Inc., Penn Virginia Corporation, Petroleum Development Corporation, PetroquestPetroQuest Energy, Inc., Stone Energy Corporation and Swift Energy Company. The graph assumes $100 is invested on January 1, 20072008 in us and each index at December 31, 20062007 closing prices.

  December 31, 
  2007  2008  2009  2010  2011 
 Penn Virginia Corporation $125.30  $74.98  $62.25  $49.79  $16.05 
 S&P Small Cap 600 Index $99.70  $68.72  $86.29  $109.00  $110.10 
 S&P 600 Oil & Gas Exploration & Production Index $126.64  $58.42  $74.42  $108.20  $101.88 


 
 December 31,
 2008 2009 2010 2011 2012
Penn Virginia Corporation$59.84
 $49.68
 $39.74
 $12.81
 $10.91
S&P Small Cap 600 Index$68.93
 $86.55
 $109.32
 $110.43
 $128.46
S&P 600 Oil & Gas Exploration & Production Index$46.13
 $58.76
 $85.44
 $80.45
 $72.71

26


21
Item 6Selected Financial Data

The following selected historical financial information was derived from our Consolidated Financial Statements as of and for the years ended December 31, 2012, 2011, 2010, 2009 2008 and 2007.2008. The selected financial data should be read in conjunction with our Consolidated Financial Statements and the accompanying Notes and Supplemental Data in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 8, “Financial Statements and Supplemental Data.”

  2011  2010  2009  2008  2007 
  (in thousands, except per share amounts) 
Statements of Income Data1:                    
Revenues $306,005  $254,438  $235,206  $469,490  $303,505 
Depreciation, depletion and amortization $162,534  $134,700  $154,351  $135,687  $88,237 
Operating income (loss)2 $(155,419) $(98,808) $(205,346) $142,034  $77,155 
Income (loss) from continuing operations $(132,915) $(65,327) $(130,856) $93,619  $35,196 
Net income (loss)3 $(132,915) $19,667  $(77,368) $181,520  $80,810 
Income (loss) attributable to Penn Virginia Corporation $(132,915) $(8,423) $(114,643) $121,084  $50,491 
                     
Common Stock Data1:                    
Earnings (loss) per common share, basic                    
Continuing operations $(2.90) $(1.44) $(2.99) $2.23  $0.92 
Discontinued operations $-  $0.12  $0.37  $0.66  $0.40 
Gain on sale of discontinued operations $-  $1.13  $-  $-  $- 
Net income (loss) $(2.90) $(0.19) $(2.62) $2.89  $1.32 
Earnings (loss) per common share, diluted                    
Continuing operations $(2.90) $(1.44) $(2.99) $2.22  $0.91 
Discontinued operations $-  $0.12  $0.37  $0.65  $0.40 
Gain on sale of discontinued operations $-  $1.13  $-  $-  $- 
Net income (loss) $(2.90) $(0.19) $(2.62) $2.87  $1.31 
Weighted-average shares outstanding:                    
Basic  45,784   45,553   43,811   41,760   38,061 
Diluted  45,784   45,553   43,811   42,031   38,358 
Actual shares outstanding at year-end  45,714   45,557   45,272   41,786   41,331 
Dividends declared per share $0.225  $0.225  $0.225  $0.225  $0.225 
Market value at year-end $5.29  $16.82  $21.29  $25.66  $42.89 
Number of shareholders  6,787   6,708   3,486   8,761   8,196 
                     
Balance Sheet and Other Financial Data1:                    
Property and equipment, net $1,777,575  $1,705,584  $1,479,452  $1,646,215  $1,198,506 
Total assets $1,943,053  $1,944,600  $2,888,507  $2,996,565  $2,253,461 
Total debt $697,307  $506,536  $498,427  $539,438  $315,655 
Shareholders' equity $846,309  $980,276  $1,237,999  $1,222,442  $911,700 
Cash provided by operating activities $144,741  $79,839  $117,733  $246,587  $186,550 
Cash paid for capital expenditures $445,623  $405,994  $205,676  $547,058  $488,470 
                     
Other Statistical Data:                    
Total production (MMcfe)  46,553   47,201   51,000   46,881   40,569 
Proved reserves (Bcfe)  883   942   935   916   680 

 2012 2011 2010 2009 2008
 (in thousands, except per share amounts)
Statements of Income Data: 1
 
  
  
  
  
Revenues$317,149
 $306,005
 $254,438
 $235,206
 $469,490
Depreciation, depletion and amortization$206,336
 $162,534
 $134,700
 $154,351
 $135,687
Operating income (loss) 2
$(147,091) $(155,419) $(98,808) $(205,346) $142,034
Income (loss) from continuing operations$(104,589) $(132,915) $(65,327) $(130,856) $93,619
Net income (loss) 3
$(104,589) $(132,915) $19,667
 $(77,368) $181,520
Income (loss) attributable to Penn Virginia Corporation$(104,589) $(132,915) $(8,423) $(114,643) $121,084
Preferred stock dividends$1,687
 $—
 $—
 $—
 $—
Income (loss) attributable to common shareholders$(106,276) $(132,915) $(8,423) $(114,643) $121,084
          
Common Stock Data: 1
 
  
  
  
  
Earnings (loss) per common share, basic 
  
  
  
  
Continuing operations$(2.22) $(2.90) $(1.44) $(2.99) $2.23
Discontinued operations$—
 $—
 $0.12
 $0.37
 $0.66
Gain on sale of discontinued operations$—
 $—
 $1.13
 $—
 $—
Net income (loss)$(2.22) $(2.90) $(0.19) $(2.62) $2.89
Earnings (loss) per common share, diluted 
  
  
  
  
Continuing operations$(2.22) $(2.90) $(1.44) $(2.99) $2.22
Discontinued operations$—
 $—
 $0.12
 $0.37
 $0.65
Gain on sale of discontinued operations$—
 $—
 $1.13
 $—
 $—
Net income (loss)$(2.22) $(2.90) $(0.19) $(2.62) $2.87
Weighted-average shares outstanding: 
  
  
  
  
Basic47,919
 45,784
 45,553
 43,811
 41,760
Diluted47,919
 45,784
 45,553
 43,811
 42,031
Actual shares outstanding at year-end55,117
 45,714
 45,557
 45,272
 41,786
Dividends declared per share of common stock$0.1125
 $0.225
 $0.225
 $0.225
 $0.225
Market value at year-end$4.41
 $5.29
 $16.82
 $21.29
 $25.66
Number of shareholders7,656
 6,787
 6,708
 3,486
 8,761
          
Balance Sheet and Other Financial Data: 1
 
  
  
  
  
Property and equipment, net$1,723,359
 $1,777,575
 $1,705,584
 $1,479,452
 $1,646,215
Total assets$1,842,989
 $1,943,053
 $1,944,600
 $2,888,507
 $2,996,565
Total debt$594,759
 $697,307
 $506,536
 $498,427
 $539,438
Shareholders' equity$895,116
 $846,309
 $980,276
 $1,237,999
 $1,222,442
Cash provided by operating activities$241,458
 $144,741
 $79,839
 $117,733
 $246,587
Cash paid for capital expenditures$370,907
 $445,623
 $405,994
 $205,676
 $547,058
          
Other Statistical Data: 
  
  
  
  
Total production (MBOE)6,513
 7,759
 7,867
 8,500
 7,814
Proved reserves (MMBOE)113
 147
 157
 156
 153
______________________

1 PVG's results of operations, financial position and cash flows have been reported as discontinued operations for all periods presented. Accordingly, all items presented above not classified as discontinued operations exclude amounts attributable to PVG unless indicated otherwise.

2 Operating income (loss) for 2012, 2011, 2010, 2009 2008 and 20072008 included impairment charges of $104.5 million, $104.7 million, $46.0 million, $106.4 million $20.0 million and $2.6$20.0 million related to our oil and gas properties and other assets.

3 Net income (loss) for 2010 includes a gain of $51.5 million, net of tax, on the sale of discontinued operations representing the final disposition of our interests in PVG.


27


22

Item 7Management’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 and its subsidiaries (“Penn Virginia,” “we,” “us” or “our”) should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, “Financial Statements and Supplemental Data.” All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas and oil in various domestic onshore regions. We have a geographically diverse asset base with areas ofactive operations in Texas, Appalachia, the Mid-Continent and Mississippi regions ofregions. Our operations are concentrated in the United States.Eagle Ford Shale, the Granite Wash, Haynesville Shale, Cotton Valley and Selma Chalk plays. As discussed in the Key Developments that follow, we sold our legacy natural gas assets in West Virginia, Kentucky and Virginia in July 2012. As of December 31, 2011,2012, we had proved oil and natural gas and oil reserves of approximately 883 Bcfe.113.5 MMBOE. Our current operations includeconsist primarily theof drilling of unconventional horizontal development wells and exploring for new exploitable resources.

in shale formations.

We are currently primarily focused on development and expansion in the Eagle Ford Shale in South Texas. During 2011, we brought on line approximately 30 gross wells in this play. In 2011, weWe also pursued selectedpursue select drilling opportunities in the horizontal Granite Wash play in ourthe Mid-Continent region through participation in wells drilled by our joint venture partner.

The following table sets forth certain summary operating and financial statistics for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Total production (MMcfe)  46,553   47,201   51,000 
Daily production (MMcfe per day)  127.5   129.3   139.7 
             
Product revenues, as reported $300,046  $251,336  $228,659 
Product revenues, as adjusted for derivatives $323,608  $284,816  $288,565 
             
Operating loss $(155,419) $(98,808) $(205,346)
Interest expense $56,216  $53,679  $44,231 
             
Cash provided by operating activities $144,741  $79,839  $117,733 
Cash paid for capital expenditures $445,623  $405,994  $205,676 
             
Cash and cash equivalents at end of period $7,512  $120,911  $79,017 
Debt outstanding, net of discounts, at end of period $697,307  $506,536  $498,427 
Credit available under revolving credit facility at end of period1 $199,600  $299,268  $299,268 
             
Net development wells drilled  33.4   40.0   19.7 
Net exploratory wells drilled  6.5   4.4   1.0 
 Year Ended December 31,
 2012 2011 2010
Total production (MBOE)6,513
 7,759
 7,867
Daily production (BOEPD)17,796

21,254

21,552
      
Product revenues, as reported$310,484
 $300,046
 $251,336
Product revenues, as adjusted for derivatives$338,802
 $323,608
 $284,816
      
Cash provided by operating activities$241,458
 $144,741
 $79,839
Cash paid for capital expenditures$370,907
 $445,623
 $405,994
      
Cash and cash equivalents at end of period$17,650
 $7,512
 $120,911
Debt outstanding, net of discounts, at end of period$594,759
 $697,307
 $506,536
Liquidation preference of convertible preferred stock outstanding at end of period$115,000
 $—
 $—
Credit available under revolving credit facility at end of period 1
$297,922
 $199,600
 $299,268
      
Net development wells drilled27.8
 33.4
 40.0
Net exploratory wells drilled4.9
 6.5
 4.4

1 As reduced by outstanding borrowings and letters of credit.

23


28



Key Developments

During 2011,


Currently, the following general business developments and corporate actions hadhave an important impact on the financial reporting and disclosure of our results of operations, financial position and financial position:cash flows: (i) drilling results in the Eagle Ford Shale Granite Wash and Marcellus Shaleother plays, (ii) acquiring properties incontinuing to shift the Eagle Ford Shale play,focus of our production from natural gas to oil and NGLs, (iii) selling our Arkoma Basin assets and related restructuring activities, (iv) entering into a new five-year revolving credit facility, or the Revolver, (iv) completing an offering of common and preferred stock, (v) offeringselling our legacy West Virginia, Kentucky and selling $300 millionVirginia natural gas assets and related restructuring and exit activities and (vi) hedging a portion of our 7.25% Senior Notes due 2019, or 2019 Senior Notes, together withoil and natural gas production through calendar year 2014 to the tender offerlevels permitted by the Revolver and our internal policies. We believe that these actions will provide sufficient liquidity in 2013 so that we will be able to repurchasefund our 4.50% Convertible Senior Subordinated Notes due 2012, or the Convertible Notes.

capital program.

Drilling Results and Future Development Plans

During 2011,2012, we drilled a total of 39.932.7 net wells, including 26.729.5 net wells in the Eagle Ford Shale 8.9and 3.2 net wells in the Mid-Continent region, primarily in the Granite Wash, and 4.3 netMid-Continent.
During 2012, we drilled 35 gross (29.5 net) operated wells in the Marcellus Shale.

We currently have three rigs drilling in the Eagle Ford Shale. WeShale, all of which were successful. Since December 2012, we have drilled a total of 39completed two gross (1.9 net) wells, since we began operations in this play during the second half of 2010. Ofbringing the total to 69 gross (56.2 net) producing wells, drilled, 35 (29.2with three gross (2.7 net) wells are producing, one is waiting on completion and three are in progress as of February 22, 2012.being drilled. The producing wells have had aninitial 30-day average peak gross production rate for 59 of approximately 1,000 BOEPD per well.these wells with a 30-day production history was 651 BOEPD. Our Eagle Ford Shale production was approximately 9,800 (6,280 net)6,377 net BOEPD at the end of Januaryduring 2012, with oil comprising approximately 8984 percent, NGLs comprising approximately sixnine percent and natural gas comprising approximately fiveseven percent. We expect to continue drilling in this play for the remainder of 2012 and beyond. We have allocated approximately 85%88 percent of our anticipated capital expenditures during 2012 for2013 to activities in the Eagle Ford Shale.

In

Included in the Mid-Continent region, we successfully drilledtotals for 2012 presented above for the Eagle Ford Shale are four gross (2.9 net) exploratory wells and completed 6.2 netnine gross (8.1 net) development wells in Lavaca County, Texas drilled under a joint exploration agreement with an industry partner that we entered into in December 2011 to jointly explore a 13,500 acre area of mutual interest, or AMI. Under the Granite Washterms of the agreement, we were required to commence drilling on six wells by September 1, 2012, as well as carry our partner for its working interest share of the costs of the first three wells, to earn our entire interest in the acreage. We fulfilled this requirement during 2011. We plan to continue our Granite Wash development program, primarilythe third quarter of 2012 and as a non-operator. Our exploratory programresult, earned an approximately 60 percent interest in the Mid-Continent region, excluding the Granite Wash, resulted in four dry holes (2.7 net) at an aggregate cost of $18.9 million during 2011.

acreage.


In 2011, we drilled five gross (4.3 net) and completed three horizontal test wellsDecember 2012, our 40 percent industry partner in the Marcellus Shale located in the central portion of our approximately 35,000 net acreage position in Potter and Tioga counties, Pennsylvania. The completed wells are connected to a pipeline and have been producing since October 2011 at an average rate of 2.5 MMcf per day. Completion of the remaining two wells and all other significant exploration and development activities have been deferred due primarily to the recent decline in natural gas prices. We will monitor long-term production of the existing wells and natural gas prices to determine the potential resumption of a development program in this area.

Eagle Ford Property Acquisitions

During 2011, we acquired approximately 7,300 netLavaca County Eagle Ford Shale acresacreage elected to not participate in the last 17 initial unit wells to be drilled on this acreage. Upon the drilling of each of the initial unit wells, our industry partner will have no participatory rights in any subsequent wells drilled in such unit. We are presently seeking a partner to acquire a 40 percent working interest in the acreage in which our industry partner has elected not to participate.


Our remaining Eagle Ford Shale wells are located in Gonzales County, Texas for approximately $27 million, or approximately $3,700 per acre. The acreage acquired in these transactions is in close proximity to our initial 2010 Eagle Ford Shale acquisition, which was approximately 6,800 net acres for $31.1 million.Texas. We are the operator of the combinedall of our Gonzales County acreage with an average working interest of approximately 81%.

84 percent.


In December 2011,addition to the acreage earned in Lavaca County, we entered into an agreement with a major oil and gas company to jointly exploreacquired approximately 13,000 gross4,100 net acres ofin the Eagle Ford Shale in Gonzales and Lavaca County, Texas. The agreement establishes an areaCounties, Texas in 2012 for approximately $10 million, increasing our net Eagle Ford Shale acreage position to approximately 32,500 net acres.
Production Focus

Since 2011, we have allocated approximately 80 percent of mutual interest near our existing acreage in Gonzales County. Depending on the future participation of other companies, our minimum working interest will be approximately 50%. Under the terms of the agreement, we must drill six wells by September 1, 2012capital expenditures to earn our entire interestexplore and develop oil- and NGL-rich areas in the acreage. We will carry our counterparty on its working interest in the first three wells.

Disposition of Arkoma Basin Properties and Related Restructuring Action

In August 2011, we sold a substantial portionEagle Ford Shale. Approximately 56 percent of our Arkoma Basin assets for approximately $30 million, excluding transaction coststotal production during the quarter ended December 31, 2012 was attributable to oil and subject to customary purchase and sale adjustments. Upon the final settlement, we recognizedNGLs, an insignificant loss in connection with the transaction, following an impairmentincrease of approximately $71 million in21 percent over the secondcorresponding prior year period. For the quarter ended December 31, 2012, approximately 83 percent of 2011. The sale, which was effective July 1, 2011, included primarily natural gasour product revenues were attributable to oil and coal bed methane properties comprising approximately 73,000 net acres in Oklahoma and Texas with proved reservesNGLs, an increase of approximately 37.1 Bcfe as well as related inventory and equipment. For 2011, these properties represented production of approximately 2 Bcfe.

During 2011, we completed an organizational restructuring due primarily to our decision to exit17 percent over the Arkoma Basin and to consolidate certain operations functions to our Houston, Texas location. This restructuring and consolidation resulted in the termination of approximately 40 employees, most of whom were based out of our Tulsa, Oklahoma office, as well as certain corporate positions in connection with a reallocation of administrative responsibilities. We recorded a charge of $2.3 million, including termination benefits, employee and office relocation costs, and a lease charge in connection with this action.

corresponding prior year period.

24
29


Completion of a New Credit Facility

In August 2011,September 2012, we entered into the Revolver whichto replace our previous revolving credit facility that was entered into in August 2011. The Revolver provides for a $300 million revolving credit commitment includingand an accordion feature to expand commitment amounts by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. At December 31, 2011, theThe Revolver had ahas an initial borrowing base of $380$300 million, which takes into account the Arkoma Basin sale discussed above, and an accordion feature that allows us to increase the commitment up to the lower ofis $70 million higher than the borrowing base or $600 millionunder our previous revolving credit facility at the time it was replaced by the Revolver. The applicable interest rate margin under the Revolver ranges from LIBOR plus 1.50 percent to LIBOR plus 2.50 percent, depending upon receiving additional commitmentsthe amount drawn as a percentage of the commitment. This rate is unchanged from one or more lenders.our previous credit facility. The permittedmaximum leverage ratio (net debt divided by EBITDAX, as defined in the Revolver) is 4.54.50 through periods ending on or beforeDecember 31, 2013, 4.25 through June 30, 2013, after which it will be 4.0.

2014 and 4.00 through maturity in 2017. The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries, or the Guarantor Subsidiaries. The obligationsborrowing base under the Revolver are secured bywill be re-determined based on a first priority lien on substantially allsemi-annual review of our total proved crude oil, NGL and natural gas reserves starting in the spring of 2013.


Common and Preferred Stock Offering

In October 2012, we completed a pledgeregistered offering of 9.2 million shares of our equity interests in the Guarantor Subsidiaries. The Revolver will mature in August 2016.

In January 2012, we amended the Revolver to enhance our ability to hedge production. Previously, our hedging was limited to the lessercommon stock that provided approximately $44 million of certain fixed percentages of our reasonably anticipated production from proved developed reserves and total proved reserves. The amendment expands the potential volume subject to hedging to certain percentages of reasonably anticipated production from proved undeveloped reserves as well as proved developed reserves. The permitted percentages vary depending on the future period to which the hedging transaction relates.

Senior Note Offering and Tender Offer to Repurchase Convertible Notes

In April 2011, we completed the offering of the 2019 Senior Notes. Total proceeds received from the offering were $293.5 million, net of underwriting fees and debt issuance costs. We used $237.1Concurrently, we completed a registered offering of 1,150,000 depositary shares each representing 1/100th interest in a share of our 6% Series A Convertible Perpetual Preferred Stock, or the 6% Preferred Stock, that provided approximately $110 million of proceeds net of underwriting fees and issuance costs. The proceeds from the proceedscombined offerings were used to repurchasefully repay outstanding borrowings under the Revolver and for general corporate purposes.


Disposition of Appalachian Assets

In July 2012, we sold our legacy natural gas assets in West Virginia, Kentucky and Virginia for approximately 98%$100 million, excluding transaction costs and before customary purchase and sale adjustments. The assets sold included vertical and horizontal coalbed methane and vertical conventional properties, a gathering system and royalty interests. These assets had net production of approximately 20 MMcfe per day (3,333 BOEPD) and estimated proved reserves of approximately 106 Bcfe (17.7 MMBOE), of which 96 percent was proved developed and almost 100 percent was natural gas. An impairment charge of $28.6 million was recognized in the Convertible Notes plus accrued interest,second quarter of 2012 with respect to these assets.

During 2012, we recorded certain restructuring and exit costs in connection with the sale, including those attributable to the closing of our office in Canonsburg, Pennsylvania. Furthermore, we have a total of $4.9 million (principal amount) of Convertible Notes currently outstanding. We usedcontractual commitment for certain firm transportation capacity in the remainderAppalachian region that expires in 2022 and, as a result of the proceedssale, we no longer have production to provide working capitalsatisfy this commitment. While we intend to sell our unused firm transportation in the future to the extent possible, we recorded a charge of $17.3 million during the third quarter of 2012 representing the liability for general corporate purposes, including capital expenditures.

estimated discounted future net cash outflows over the remaining term of the contract.


Commodity Hedging Activities
For 2013, we have approximately 58 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $97.35 and $100.99 per barrel. For 2014, we have approximately 16 percent of our estimated oil production hedged at a weighted-average swap price of $100.33 per barrel.

For 2013, we have approximately 55 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of $3.76 and $4.19 per MMBtu. We have 5,000 MMBtu per day hedged in the first quarter of 2014 with a floor/swap and ceiling prices of $4.00 and $4.50 per MMBtu. We do not have any NGLs hedged.

30



Results of Operations


Year Ended December 31, 20112012 Compared to the Year Ended December 31, 2010

2011

The following table sets forth a summary of certain operating and financial performance for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Total Production:                
Natural gas (MMcf)  33,410   38,919   (5,509)  (14)%
Crude oil (MBbl)  1,283   709   574   81%
NGL (MBbl)  907   672   235   35%
Total production (MMcfe)  46,553   47,201   (648)  (1)%
                 
Realized prices, before derivatives:                
Natural gas ($/Mcf) $4.10  $4.40  $(0.30)  (7)%
Crude oil ($/Bbl)  93.19   75.56   17.63   23%
NGL ($/Bbl)  47.83   39.69   8.14   21%
Total ($/Mcfe) $6.45  $5.32  $1.13   21%
                 
Revenues                
Natural gas $137,070  $171,141  $(34,071)  (20)%
Crude oil  119,582   53,532   66,050   123%
NGL  43,394   26,663   16,731   63%
Total product revenues  300,046   251,336   48,710   19%
Gain on sales of property and equipment  3,570   648   2,922   451%
Other income  2,389   2,454   (65)  (3)%
Total revenues  306,005   254,438   51,567   20%
                 
Operating Expenses                
Lease operating  36,988   35,757   (1,231)  (3)%
Gathering, processing and transportation  15,157   14,180   (977)  (7)%
Production and ad valorem taxes  13,690   13,917   227   2%
General and administrative  48,328   58,383   10,055   17%
Exploration  78,943   49,641   (29,302)  (59)%
Depreciation, depletion and amortization  162,534   134,700   (27,834)  (21)%
Impairments  104,688   45,959   (58,729)  (128)%
Other  1,096   709   (387)  (55)%
Total operating expenses  461,424   353,246   (108,178)  (31)%
                 
Operating loss  (155,419)  (98,808)  (56,611)  (57)%
Other income (expense)                
Interest expense  (56,216)  (53,679)  (2,537)  (5)%
Loss on extinguishment of debt  (25,421)  -   (25,421)  NM 
Derivatives  15,651   41,906   (26,255)  (63)%
Other  335   2,403   (2,068)  (86)%
Loss from continuing operations before income taxes  (221,070)  (108,178)  (112,892)  (104)%
Income tax benefit  88,155   42,851   45,304   106%
Loss from continuing operations  (132,915)  (65,327)  (67,588)  (103)%
Income from discontinued operations, net of tax  -   33,448   (33,448)  NM 
Gain on sale of discontinued operations  -   51,546   (51,546)  NM 
Net income (loss)  (132,915)  19,667   (152,582)  NM 
Less net income attributable to noncontrolling interests  -   (28,090)  28,090   NM 
Loss attributable to Penn Virginia Corporation $(132,915) $(8,423) $(124,492)  NM 
                 
NM - Not meaningful                

 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Total production: 
  
  
  
Crude oil (MBbl)2,252
 1,283
 969
 76 %
NGL (MBbl)884
 907
 (23) (3)%
Natural gas (MMcf)20,261
 33,410
 (13,149) (39)%
Total production (MBOE)6,513
 7,759
 (1,246) (16)%
Realized prices, before derivatives: 
  
  
  
Crude oil ($/Bbl)$101.95
 $93.19
 $8.76
 9 %
NGL ($/Bbl)35.13
 47.83
 (12.70) (27)%
Natural gas ($/Mcf)2.46
 4.10
 (1.64) (40)%
Total ($/BOE)$47.67
 $38.67
 $9.00
 23 %
Revenues 
  
  
  
Crude oil$229,572
 $119,582
 $109,990
 92 %
NGL31,051
 43,394
 (12,343) (28)%
Natural gas49,861
 137,070
 (87,209) (64)%
Total product revenues310,484
 300,046
 10,438
 3 %
Gain on sales of property and equipment4,282
 3,570
 712
 20 %
Other income2,383
 2,389
 (6) — %
Total revenues317,149
 306,005
 11,144
 4 %
Operating expenses 
  
  
  
Lease operating31,266
 36,988
 5,722
 15 %
Gathering, processing and transportation14,196
 15,157
 961
 6 %
Production and ad valorem taxes10,634
 13,690
 3,056
 22 %
General and administrative45,900
 48,328
 2,428
 5 %
Exploration34,092
 78,943
 44,851
 57 %
Depreciation, depletion and amortization206,336
 162,534
 (43,802) (27)%
Impairments104,484
 104,688
 204
 — %
Loss on firm transportation commitment17,332
 —
 (17,332) NM
Other—
 1,096
 1,096
 100 %
Total operating expenses464,240
 461,424
 (2,816) (1)%
Operating loss(147,091) (155,419) 8,328
 5 %
Other income (expense) 
  
  
  
Interest expense(59,339) (56,216) (3,123) (6)%
Loss on extinguishment of debt(3,164) (25,421) 22,257
 88 %
Derivatives36,187
 15,651
 20,536
 131 %
Other116
 335
 (219) (65)%
Loss before income taxes(173,291) (221,070) 47,779
 22 %
Income tax benefit68,702
 88,155
 (19,453) (22)%
Net loss(104,589) (132,915) 28,326
 21 %
Preferred stock dividends(1,687) —
 (1,687) NM
Loss attributable to common shareholders$(106,276) $(132,915) $26,639
 20 %
NM - Not meaningful 
  
  
  

31


Production

The following tables set forth a summary of our total and daily production volumes by product and geographicalgeographic region for the periods presented:

Natural Gas Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable)  % Change 
  (MMcfe)     (MMcfe per day)       
Texas  9,670   10,510   (840)  26.5   28.8   (2.3)  (8)%
Appalachia  9,055   10,358   (1,303)  24.8   28.4   (3.6)  (13)%
Mid-Continent  8,244   10,338   (2,094)  22.6   28.3   (5.7)  (20)%
Mississippi  6,441   7,505   (1,064)  17.6   20.6   (3.0)  (14)%
Gulf Coast (Divested)  -   208   (208)  -   0.6   (0.6)  (100)%
Total production  33,410   38,919   (5,509)  91.5   106.7   (15.2)  (14)%

Crude Oil Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable)  % Change 
  (MBbl)     (MBbl per day)       
Texas  868.7   113.5   755.2   2.38   0.31   2.07   665%
Appalachia  0.5   5.1   (4.6)  0.00   0.01   (0.01)  (90)%
Mid-Continent  395.1   559.3   (164.2)  1.08   1.53   (0.45)  (29)%
Mississippi  18.9   22.9   (4.0)  0.05   0.06   (0.01)  (17)%
Gulf Coast (Divested)  -   7.7   (7.7)  -   0.02   (0.02)  (100)%
Total production  1,283.2   708.5   574.7   3.51   1.93   1.58   81%

NGLs Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable)  % Change 
  (MBbl)     (MBbl per day)       
Texas  495.2   389.1   106.1   1.36   1.07   0.29   27%
Appalachia  0.9   1.4   (0.5)  0.00   0.00   (0.00)  (36)%
Mid-Continent  411.1   274.4   136.7   1.13   0.75   0.38   50%
Gulf Coast (Divested)  -   6.9   (6.9)  -   0.02   (0.02)  (100)%
Total production  907.2   671.8   235.4   2.49   1.84   0.65   35%

Combined Total Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable)  % Change 
  (MMcfe)     (MMcfe per day)       
Texas  17,854   13,526   4,328   48.9   37.1   11.8   32%
Appalachia  9,063   10,397   (1,334)  24.8   28.5   (3.7)  (13)%
Mid-Continent  13,082   15,340   (2,258)  35.8   42.0   (6.2)  (15)%
Mississippi  6,554   7,643   (1,089)  18.0   20.9   (2.9)  (14)%
Gulf Coast (Divested)  -   295   (295)  -   0.8   (0.8)  (100)%
Total production  46,553   47,201   (648)  127.5   129.3   (1.8)  (1)%

Crude OilYear Ended December 31, Favorable Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
 (MBbl)   (Bbl per day)    
Texas    

 
 
 

 

Eagle Ford Shale1,959.6
 751.2
 1,208.4
 5,354.1
 2,058.1
 3,296.0
 161 %
East Texas71.1
 117.5
 (46.4) 194.3
 321.9
 (127.6) (39)%
Mid-Continent206.2
 395.1
 (188.9) 563.4
 1,082.6
 (519.2) (48)%
Mississippi14.1
 18.9
 (4.8) 38.5
 51.7
 (13.2) (25)%
Appalachia1.0
 0.5
 0.5
 2.7
 1.3
 1.4
 105 %
 2,251.9
 1,283.2
 968.8
 6,153.0
 3,515.5
 2,637.4
 75 %
NGLsYear Ended December 31, Favorable Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
 (MBbl)   (Bbl per day)    
Texas    

 
 
 

 

Eagle Ford Shale205.2
 54.9
 150.3
 560.7
 150.4
 410.3
 274 %
East Texas280.7
 440.3
 (159.6) 766.9
 1,206.3
 (439.4) (36)%
Mid-Continent397.2
 411.1
 (13.9) 1,085.2
 1,126.3
 (41.1) (3)%
Mississippi—
 —
 —
 —
 —
 —
 — %
Appalachia0.8
 0.9
 (0.1) 2.2
 2.5
 (0.3) (11)%
 884.0
 907.2
 (23.3) 2,415.0
 2,485.5
 (70.5) (3)%
Natural GasYear Ended December 31, Favorable Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
 (MMcfe)   (MMcfe per day)    
Texas    

 

 

 

 

Eagle Ford Shale1,015
 277
 738
 2.8
 0.8
 2.0
 266 %
East Texas5,909
 9,393
 (3,484) 16.1
 25.7
 (9.6) (37)%
Mid-Continent3,646
 8,244
 (4,598) 10.0
 22.6
 (12.6) (56)%
Mississippi4,997
 6,441
 (1,444) 13.7
 17.6
 (3.9) (22)%
Appalachia4,695
 9,055
 (4,360) 12.8
 24.8
 (12.0) (48)%
 20,261
 33,410
 (13,148) 55.4
 91.5
 (36.1) (39)%
Combined TotalYear Ended December 31, Favorable Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable) % Change
 (MBOE)   (BOE per day)    
Texas
 

 

 
 
 

 

Eagle Ford Shale2,334
 852
 1,482
 6,377
 2,334
 4,043
 174 %
East Texas1,337
 2,123
 (786) 3,653
 5,816
 (2,163) (37)%
Mid-Continent1,211
 2,180
 (969) 3,309
 5,973
 (2,664) (44)%
Mississippi847
 1,092
 (245) 2,314
 2,993
 (678) (22)%
Appalachia784
 1,511
 (727) 2,143
 4,138
 (1,996) (48)%
 6,513
 7,759
 (1,245) 17,796
 21,254
 (3,458) (16)%
Certain results in the tables above may not calculate due to rounding.        

The decline in total production during 2012 compared to 2011 was due primarily to natural production declines as well as the effect of the sale of Appalachian and Arkoma Basin natural gas properties in July 2012 and August 2011, respectively. The effect of the sale of the Appalachian properties was approximately 4.4 Bcfe (700 MBOE) and the Arkoma Basin properties was approximately 2.0 Bcfe (333 MBOE). The natural declines in production from our remaining natural gas properties were partially offset by an increase in oil, NGL and natural gas production attributable to our drilling activity in the Eagle Ford Shale. Approximately 48% of total production in 2012 was attributable to oil and NGLs, which represents an increase of approximately 43% over the previous year. During 2012, our Eagle Ford Shale production of 2,334 MBbl represented approximately 36% of our total production. We had approximately 852 MBbls of production from this play during 2011.


32


Product Revenues and Prices
The following tables set forth a summary of our revenues and prices per unit of volume by product and geographic region for the periods presented:
Crude OilYear Ended December 31, Favorable Year Ended December 31, Favorable
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
       ($ per Bbl)  
Texas    

     

Eagle Ford Shale$202,479
 $70,399
 $132,080
 $103.33
 $93.72
 $9.61
East Texas6,862
 11,074
 (4,212) 96.51
 94.25
 2.26
Mid-Continent18,667
 36,145
 (17,478) 90.55
 91.48
 (0.93)
Mississippi1,477
 1,924
 (447) 104.66
 101.80
 2.86
Appalachia87
 40
 47
 91.29
 80.00
 11.29
 $229,572
 $119,582
 $109,990
 $101.95
 $93.19
 $8.76
NGLsYear Ended December 31, Favorable Year Ended December 31, Favorable
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
       ($ per Bbl)  
Texas    

     

Eagle Ford Shale$6,451
 $2,817
 $3,634
 $31.43
 $51.22
 $(19.79)
East Texas10,195
 21,936
 (11,741) 36.32
 49.82
 (13.50)
Mid-Continent14,365
 18,595
 (4,230) 36.16
 45.23
 (9.07)
Mississippi—
 —
 —
 —
 —
 —
Appalachia40
 46
 (6) 51.61
 51.11
 0.50
 $31,051
 $43,394
 $(12,343) $35.13
 $47.83
 $(12.70)
Natural GasYear Ended December 31, Favorable Year Ended December 31, Favorable
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
       ($ per Mcfe)  
Texas    

     

Eagle Ford Shale$2,593
 $1,015
 $1,578
 $2.56
 $3.66
 $(1.10)
East Texas13,607
 37,057
 (23,450) 2.30
 3.95
 (1.65)
Mid-Continent7,920
 35,315
 (27,395) 2.17
 4.28
 (2.11)
Mississippi14,387
 27,047
 (12,660) 2.88
 4.20
 (1.32)
Appalachia11,354
 36,636
 (25,282) 2.42
 4.05
 (1.63)
 $49,861
 $137,070
 $(87,209) $2.46
 $4.10
 $(1.64)
Combined TotalYear Ended December 31, Favorable Year Ended December 31, Favorable
 2012 2011 (Unfavorable) 2012 2011 (Unfavorable)
       ($ per BOE)  
Texas

   

     

Eagle Ford Shale$211,523
 $74,231
 $137,292
 $90.63
 $87.13
 $3.50
East Texas30,664
 70,067
 (39,403) 22.93
 33.00
 (10.07)
Mid-Continent40,952
 90,055
 (49,103) 33.82
 41.31
 (7.49)
Mississippi15,864
 28,971
 (13,107) 18.72
 26.53
 (7.81)
Appalachia11,481
 36,722
 (25,241) 14.64
 24.30
 (9.66)
 $310,484
 $300,046
 $10,438
 $47.67
 $38.67
 $9.00

As illustrated below, higher oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $0.7 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in the Mid-Continent region.


33


The following table provides an analysis of the change in our revenues for 2012 as compared to 2011:
 Revenue Variance Due to
 Volume Price Total
Crude oil$90,274
 $19,716
 $109,990
NGL(1,110) (11,233) (12,343)
Natural gas(53,946) (33,263) (87,209)
 $35,218
 $(24,780) $10,438
Effects of Derivatives
Our oil and gas revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge oil and gas prices. In 2012 and 2011, we received $28.3 million and $23.6 million, respectively, in cash settlements of oil and gas derivatives.
The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented: 
 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Crude oil revenues as reported$229,572
 $119,582
 $109,990
 92 %
Cash settlements on crude oil derivatives, net8,428
 1,404
 7,024
 500 %
Crude oil revenues adjusted for derivatives$238,000
 $120,986
 $117,014
 97 %
        
Crude oil prices per Bbl, as reported$101.95
 $93.19
 $8.76
 9 %
Cash settlements on crude oil per Bbl3.74
 1.09
 2.65
 243 %
Crude oil prices per Bbl adjusted for derivatives$105.69
 $94.28
 $11.41
 12 %
        
Natural gas revenues as reported$49,861
 $137,070
 $(87,209) (64)%
Cash settlements on natural gas derivatives, net19,890
 22,158
 (2,268) (10)%
Natural gas revenues adjusted for derivatives$69,751
 $159,228
 $(89,477) (56)%
        
Natural gas prices per Mcf, as reported$2.46
 $4.10
 $(1.64) (40)%
Cash settlements on natural gas derivatives per Mcf0.98
 0.66
 0.32
 48 %
Natural gas prices per Mcf adjusted for derivatives$3.44
 $4.76
 $(1.32) (28)%
Gain on Sales of Property and Equipment
In the third quarter of 2012 and as further adjusted in the fourth quarter, we recognized a gain of $3.3 million on the sale of certain of our Appalachian assets for proceeds of $95.7 million, net of transaction costs. In 2011, we sold approximately 2,700 net undeveloped acres in Butler and Armstrong counties in Pennsylvania for proceeds of $8.1 million, net of transaction costs, and recognized a gain of $3.3 million. We also recognized a gain of $0.6 million in 2012 attributable to the sale of our remaining undeveloped acreage in those counties. In addition, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well material during both 2012 and 2011.
Other Income
Other income, which includes ancillary gathering, transportation, compression and water disposal fees and other miscellaneous operating income net of marketing and related expenses, was relatively unchanged during 2012 as compared to 2011.

34


Operating Expenses
The following table summarizes certain of our operating expenses per BOE for the periods presented:
 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Lease operating$4.80
 $4.77
 $(0.03) (1)%
Gathering, processing and transportation2.19
 1.95
 (0.24) (12)%
Production and ad valorem taxes1.63
 1.76
 0.13
 7 %
General and administrative excluding share-based compensation and restructuring charges 5.87
 4.97
 (0.90) (18)%
General and administrative7.05
 6.23
 (0.82) (13)%
Depreciation, depletion and amortization31.68
 20.95
 (10.73) (51)%

Lease Operating
Lease operating expense decreased on an absolute basis during 2012 due primarily to the effect of the sale of our higher-cost Appalachian and Arkoma Basin properties. In addition to the effect of property sales, we incurred lower repair and maintenance expenses and lower compression costs during 2012. Cost decreases were partially offset by higher environmental and regulatory compliance, chemical treatment, field contracting and well tending costs attributable to our significantly expanded oil drilling program.

Gathering, Processing and Transportation
Gathering, processing and transportation charges increased slightly during 2012, despite lower overall production volumes, due primarily to higher processing costs associated with NGLs and higher transportation costs in the Appalachian region in 2012 for periods prior to the sale.
Production and Ad Valorem Taxes
Production and ad valorem taxes decreased during 2012 due primarily to Oklahoma severance tax rebates of $2.8 million attributable to horizontal and ultra-deep wells for the period of July 1, 2009 through June 30, 2011. Reductions were also recognized for production taxes on certain Texas wells in 2012 and for a property tax recovery on West Virginia wells in 2011. Production taxes also decreased due to the Appalachian asset sale as well as lower overall natural gas volumes and prices in 2012 as compared to 2011. As a percentage of product revenues, production and ad valorem taxes decreased to 3.4% during 2012 from 4.6% during 2011.
General and Administrative
The following table sets forth the components of general and administrative expenses for the periods presented:
 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Recurring general and administrative expenses$37,547
 $38,547
 $1,000
 3%
Share-based compensation (liability-classified)714
 —
 (714) NM
Share-based compensation (equity-classified)6,347
 7,430
 1,083
 15%
Restructuring expenses1,292
 2,351
 1,059
 45%
 $45,900
 $48,328
 $2,428
 5%
Recurring general and administrative expenses decreased due to reduced headcount and lower support costs following the sale of our Appalachian and Arkoma Basin properties. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, issued in 2012, which are payable in cash in 2015 upon achievement of specified market-based performance metrics. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during 2012 due primarily to a lower number of awards granted. Restructuring expenses for both the 2012 and 2011 periods include termination benefits and office relocation costs. The 2012 charge includes a provision for lease costs associated with the closing of our Canonsburg, Pennsylvania office,

35


partially offset by a favorable adjustment to the lease obligation for our former Tulsa, Oklahoma office due to a change in estimated sub-lease rental income.

Exploration
The following table sets forth the components of exploration expenses for the periods presented:
 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Unproved leasehold amortization$32,634
 $42,076
 $9,442
 22%
Geological and geophysical costs816
 11,202
 10,386
 93%
Dry hole costs—
 18,864
 18,864
 100%
Drilling rig charges—
 4,620
 4,620
 100%
Other, primarily delay rentals642
 2,181
 1,539
 71%
 $34,092
 $78,943
 $44,851
 57%

Unproved leasehold amortization declined during 2012 as costs related to successful Eagle Ford Shale wells were transferred to proved properties. Geological and geophysical costs decreased during 2012 because our efforts in 2012 were concentrated on development drilling in the Eagle Ford Shale whereas in 2011 we conducted exploratory prospect activities in multiple areas. Dry hole costs in 2011 related to several unsuccessful wells in the Mid-Continent region. We recorded rig-related charges in 2011 in connection with the suspension of our exploratory drilling program in the Marcellus Shale.
Depreciation, Depletion and Amortization (DD&A)
The following table sets forth the nature of the DD&A variances for the periods presented:
 DD&A Variance Due to
     Favorable
 Production Rates (Unfavorable)
Year ended December 31, 2012 compared to 2011$26,103
 $(69,905) $(43,802)
The effect of lower overall production volumes on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average DD&A rate increased to $31.68 per BOE for 2012 from $20.95 per BOE for 2011 due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale as well as lower natural gas reserves due to revisions.
Impairments
The following table summarizes the impairments recorded for the periods presented:
 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Oil and gas properties$103,417
 $104,688
 $1,271
 1%
Other - tubular inventory and well materials1,067
 —
 (1,067) NM
 $104,484
 $104,688
 $204
 —%
In 2012, we recognized a $28.4 million impairment of our legacy assets in West Virginia, Kentucky and Virginia triggered by the expected disposition of these properties, and a $75.0 million impairment of our Marcellus Shale assets due primarily to market declines in natural gas prices and the resultant reduction in proved natural gas reserves. In 2012, we also recognized an impairment of certain tubular inventory and well materials triggered primarily by declines in asset quality. In 2011, we recognized an impairment of our Arkoma Basin assets for $71.1 million, which was triggered by the expected disposition of those properties. Also during 2011, we recognized impairments of our horizontal coal bed methane properties in the Appalachian region for $26.6 million and certain dry-gas properties in Mississippi for $6.8 million, in each case due primarily to market declines in natural gas prices.


36


Loss on Firm Transportation Commitment

We have a contractual commitment for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the recently completed sale of our West Virginia, Kentucky and Virginia assets, we no longer have production to satisfy this commitment. Accordingly, we recorded a charge of $17.3 million during the third quarter of 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

Other
During 2011, we recorded a reserve of $0.2 million for litigation attributable to properties that were previously sold. This matter was ultimately settled in January 2012 for the reserved amount. In addition, we wrote down certain gas imbalance assets in 2011 that originated in prior years due to lower settlement rates.

Interest Expense
The following table summarizes the components of our interest expense for the periods presented:
 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Interest on borrowings and related fees$56,079
 $51,384
 $(4,695) (9)%
Accretion of original issue discount1,367
 3,427
 2,060
 60 %
Amortization of debt issuance costs2,695
 3,380
 685
 20 %
Capitalized interest(803) (1,983) (1,180) (60)%
Other, net1
 8
 7
 88 %
 $59,339
 $56,216
 $(3,123) (6)%
The issuance of our 7.25% Senior Notes due 2019, or the 2019 Senior Notes, and borrowings under the Revolver, partially offset by the repurchase of approximately 98% of our outstanding 4.50% Convertible Senior Subordinated Notes due 2012, or the Convertible Notes, with an effective interest rate of 8.5%, resulted in an approximate $107 million higher weighted-average balance of debt outstanding during 2012 compared to 2011. Accordingly, interest expense increased due to a higher average outstanding principal balance despite lower effective interest rates attributable to the 2019 Senior Notes and the Revolver. Capitalized interest was lower during 2012 due to lower carrying values on eligible capital projects.
Loss on Extinguishment of Debt
When we entered into the Revolver in September 2012, we expensed issuance costs of $3.2 million attributable to our previous revolving credit facility. During 2011, we expensed $1.2 million attributable to a change in the composition of the bank syndicate for our previous revolving credit facility. The repurchase in April 2011 of approximately 98% of the outstanding Convertible Notes resulted in a loss on extinguishment of debt of $24.2 million. The loss was comprised of the excess of cash paid for the liability component over the carrying value, plus the write-off of a pro rata share of debt issuance costs and incremental fees paid in cash.
Derivatives
The following table summarizes the components of our derivatives income for the periods presented:
 Year Ended December 31, Favorable  
 2012 2011 (Unfavorable) % Change
Oil and gas derivative unrealized gain (loss)$6,463
 $(9,140) $15,603
 171 %
Oil and gas derivative realized gain28,318
 23,562
 4,756
 20 %
Interest rate swap unrealized loss—
 (2,589) 2,589
 100 %
Interest rate swap realized gain1,406
 3,818
 (2,412) (63)%
 $36,187
 $15,651
 $20,536
 131 %
We received cash settlements of $29.7 million during 2012 and $27.4 million during 2011. The cash settlements in 2012 and 2011 included $1.2 million and $2.9 million attributable to the termination of our interest rate swap agreements during those periods. The increase in the unrealized gain on commodity derivatives was due primarily to oil and natural gas prices declining below our hedged prices.

37


Other
Other income decreased during 2012 due primarily to lower interest income earned on average cash balances.

Income Taxes
The effective tax benefit rate during 2012 was 39.6% compared to 39.9% for 2011. Due to the operating losses incurred, we recognized an income tax benefit during both periods. In addition, the effective tax rates for 2012 and 2011 included a deferred tax asset valuation allowance due primarily to the inability to recognize tax benefits for certain state net operating losses.

38



Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010
The following table sets forth a summary of certain operating and financial performance for the periods presented:
 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Total production: 
  
  
  
Crude oil (MBbl)1,283
 709
 574
 81 %
NGL (MBbl)907
 672
 235
 35 %
Natural gas (MMcf)33,410
 38,919
 (5,509) (14)%
Total production (MBOE)7,759
 7,867
 (108) (1)%
Realized prices, before derivatives: 
  
  
  
Crude oil ($/Bbl)$93.19
 75.56
 17.63
 23 %
NGL ($/Bbl)47.83
 39.69
 8.14
 21 %
Natural gas ($/Mcf)4.10
 4.40
 (0.30) (7)%
Total ($/BOE)$38.67
 $31.95
 $6.72
 21 %
Revenues 
  
  
  
Crude oil$119,582
 $53,532
 $66,050
 123 %
NGL43,394
 26,663
 16,731
 63 %
Natural gas137,070
 171,141
 (34,071) (20)%
Total product revenues300,046
 251,336
 48,710
 19 %
Gain on sale of property and equipment3,570
 648
 2,922
 451 %
Other income2,389
 2,454
 (65) (3)%
Total revenues306,005
 254,438
 51,567
 20 %
Operating expenses 
  
  
  
Lease operating36,988
 35,757
 (1,231) (3)%
Gathering, processing and transportation15,157
 14,180
 (977) (7)%
Production and ad valorem taxes13,690
 13,917
 227
 2 %
General and administrative48,328
 58,383
 10,055
 17 %
Exploration78,943
 49,641
 (29,302) (59)%
Depreciation, depletion and amortization162,534
 134,700
 (27,834) (21)%
Impairments104,688
 45,959
 (58,729) (128)%
Other1,096
 709
 (387) (55)%
Total operating expenses461,424
 353,246
 (108,178) (31)%
Operating loss(155,419) (98,808) (56,611) (57)%
Other income (expense) 
  
  
  
Interest expense(56,216) (53,679) (2,537) (5)%
Loss on extinguishment of debt(25,421) —
 (25,421) NM
Derivatives15,651
 41,906
 (26,255) (63)%
Other335
 2,403
 (2,068) (86)%
Loss from continuing operations before income taxes(221,070) (108,178) (112,892) (104)%
Income tax benefit88,155
 42,851
 45,304
 106 %
Loss from continuing operations(132,915) (65,327) (67,588) (103)%
Income from discontinued operations, net of tax—
 33,448
 (33,448) NM
Gain on sale of discontinued operations, net of tax—
 51,546
 (51,546) NM
Net income (loss)(132,915) 19,667
 (152,582) NM
Less net income attributable to noncontrolling interests—
 (28,090) 28,090
 NM
Net loss attributable to Penn Virginia Corporation$(132,915) $(8,423) $(124,492) NM
NM - Not meaningful       


39


Production
The following tables set forth a summary of our total and daily production volumes by product and geographic region for the periods presented:  
Crude OilYear Ended December 31,��Favorable Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable) % Change
 (MBbl)   (Bbl per day)    
Texas    

 
 

 

 

Eagle Ford Shale751.2
 —
 751.2
 2,058.1
 —
 2,058.1
 NM
East Texas117.5
 113.5
 4.0
 321.9
 311.0
 10.9
 4 %
Mid-Continent395.1
 559.3
 (164.2) 1,082.6
 1,532.3
 (449.7) (29)%
Mississippi18.9
 22.9
 (4.0) 51.7
 62.7
 (11.0) (17)%
Appalachia0.5
 5.1
 (4.6) 1.3
 14.0
 (12.7) (90)%
Gulf Coast (Divested)—
 7.7
 (7.7) —
 21.1
 (21.1) (100)%
 1,283.2
 708.5
 574.7
 3,515.5
 1,941.1
 1,574.5
 81 %
NGLsYear Ended December 31, Favorable Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable) % Change
 (MBbl)   (Bbl per day)    
Texas    

 

 

 

 

Eagle Ford Shale54.9
 —
 54.9
 150.4
 —
 150.4
 NM
East Texas440.3
 389.1
 51.2
 1,206.3
 1,066.0
 140.3
 13 %
Mid-Continent411.1
 274.4
 136.7
 1,126.3
 751.8
 374.5
 50 %
Mississippi—
 —
 —
 —
 —
 —
 — %
Appalachia0.9
 1.4
 (0.5) 2.5
 3.8
 (1.3) (36)%
Gulf Coast (Divested)—
 6.9
 (6.9) —
 18.9
 (18.9) (100)%
 907.2
 671.8
 235.4
 2,485.5
 1,840.5
 645.0
 35 %
Natural GasYear Ended December 31, Favorable Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable) % Change
 (MMcfe)   (MMcfe per day)    
Texas    

 

 

 

 

Eagle Ford Shale277
 —
 277
 0.8
 —
 0.8
 NM
East Texas9,393
 10,510
 (1,117) 25.7
 28.8
 (3.1) (11)%
Mid-Continent8,244
 10,338
 (2,094) 22.6
 28.3
 (5.7) (20)%
Mississippi6,441
 7,505
 (1,064) 17.6
 20.6
 (3.0) (14)%
Appalachia9,055
 10,358
 (1,303) 24.8
 28.4
 (3.6) (13)%
Gulf Coast (Divested)—
 208
 (208) —
 0.6
 (0.6) (100)%
 33,410
 38,919
 (5,509) 91.5
 106.7
 (15.2) (14)%
Combined TotalYear Ended December 31, Favorable Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable) % Change
 (MBOE)   (BOE per day)    
Texas
 

 

 

 

 

 

Eagle Ford Shale852
 —
 852
 2,334
 —
 2,334
 NM
East Texas2,123
 2,254
 (131) 5,816
 6,175
 (359) (6)%
Mid-Continent2,180
 2,557
 (377) 5,973
 7,005
 (1,032) (15)%
Mississippi1,092
 1,274
 (182) 2,993
 3,490
 (497) (14)%
Appalachia1,511
 1,733
 (222) 4,138
 4,747
 (609) (13)%
Gulf Coast (Divested)—
 49
 (49) —
 135
 (135) (100)%
 7,759
 7,867
 (109) 21,254
 21,552
 (298) (1)%
Certain results in the tables above may not calculate due to rounding.      
The decline in production during 2011 compared to 2010 was due primarily to the lack of any significant natural gas drilling since mid-2010 and the subsequent natural production declines as well as the effect of the sale ofselling our high-cost Arkoma Basin natural gas properties. The effect of the sale of the Arkoma Basin properties was approximately 2 Bcfe.2.0 Bcfe (333 MBOE). The natural gas production decline was substantially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 28% of total production on an equivalent basis in 2011 was attributable to oil and NGLs, an increase

40


over the previous year of approximately 59%. The shift in production mix reflects our focus on emerging oil and liquids-rich plays in the Eagle Ford Shale in Texas and the Mid-Continent region. During 2011, our Eagle Ford Shale production of 852 MBbls represented approximately 11% of our total production. We had no production from this play in 2010.

27

Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of volume by product and geographicalgeographic region for the periods presented:

Natural Gas Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable) 
           ($ per Mcfe)    
Texas $38,072  $43,247  $(5,175) $3.94  $4.11  $(0.17)
Appalachia  36,636   45,581   (8,945)  4.05   4.40   (0.35)
Mid-Continent  35,315   47,694   (12,379)  4.28   4.61   (0.33)
Mississippi  27,047   33,351   (6,304)  4.20   4.44   (0.24)
Gulf Coast (Divested)  -   1,268   (1,268)  -   6.10   (6.10)
Total revenues $137,070  $171,141  $(34,071) $4.10  $4.40  $(0.30)

Crude Oil Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable) 
           ($ per Bbl)    
Texas $81,473  $8,844  $72,629  $93.79  $77.92  $15.87 
Appalachia  40   164   (124)  80.00   32.16   47.84 
Mid-Continent  36,145   42,176   (6,031)  91.48   75.41   16.07 
Mississippi  1,924   1,750   174   101.80   76.42   25.38 
Gulf Coast (Divested)  -   598   (598)  -   77.66   (77.66)
Total revenues $119,582  $53,532  $66,050  $93.19  $75.56  $17.63 

NGLs Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable) 
           ($ per Bbl)    
Texas $24,753  $15,150  $9,603  $49.99  $38.94  $11.05 
Appalachia  46   51   (5)  51.11   36.43   14.68 
Mid-Continent  18,595   11,152   7,443   45.23   40.64   4.59 
Gulf Coast (Divested)  -   310   (310)  -   44.93   (44.93)
Total revenues $43,394  $26,663  $16,731  $47.83  $39.69  $8.14 

Combined Total Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2011  2010  (Unfavorable)  2011  2010  (Unfavorable) 
           ($ per Mcfe)    
Texas $144,298  $67,241  $77,057  $8.08  $4.97  $3.11 
Appalachia  36,722   45,796   (9,074)  4.05   4.40   (0.35)
Mid-Continent  90,055   101,022   (10,967)  6.88   6.59   0.29 
Mississippi  28,971   35,101   (6,130)  4.42   4.59   (0.17)
Gulf Coast (Divested)  -   2,176   (2,176)  -   7.38   (7.38)
Total revenues $300,046  $251,336  $48,710  $6.45  $5.32  $1.13 

Crude OilYear Ended December 31, Favorable Year Ended December 31, Favorable
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable)
       ($ per Bbl)  
Texas    

     

Eagle Ford Shale$70,399
 $—
 $70,399
 $93.72
 $—
 93.72
East Texas11,074
 8,844
 2,230
 94.25
 77.92
 16.33
Mid-Continent36,145
 42,176
 (6,031) 91.48
 75.41
 16.07
Mississippi1,924
 1,750
 174
 101.80
 76.42
 25.38
Appalachia40
 164
 (124) 80.00
 32.16
 47.84
Gulf Coast (Divested)—
 598
 (598) —
 77.66
 (77.66)
 $119,582
 $53,532
 $66,050
 $93.19
 $75.56
 $17.63
NGLsYear Ended December 31, Favorable Year Ended December 31, Favorable
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable)
       ($ per Bbl)  
Texas    

     

Eagle Ford Shale$2,817
 $—
 $2,817
 $51.22
 $—
 $51.22
East Texas21,936
 15,150
 6,786
 49.82
 38.94
 10.88
Mid-Continent18,595
 11,152
 7,443
 45.23
 40.64
 4.59
Appalachia—
 51
 (51) —
 36.43
 (36.43)
Mississippi46
 —
 46
 51.11
 —
 51.11
Gulf Coast (Divested)—
 310
 (310) —
 44.93
 (44.93)
 $43,394
 $26,663
 $16,731
 $47.83
 $39.69
 $8.14
Natural GasYear Ended December 31, Favorable Year Ended December 31, Favorable
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable)
       ($ per Mcfe)  
Texas    

     

Eagle Ford Shale$1,015
 $—
 $1,015
 $3.66
 $—
 $3.66
East Texas37,057
 43,247
 (6,190) 3.95
 4.11
 (0.16)
Mid-Continent35,315
 47,694
 (12,379) 4.28
 4.61
 (0.33)
Mississippi27,047
 33,351
 (6,304) 4.20
 4.44
 (0.24)
Appalachia36,636
 45,581
 (8,945) 4.05
 4.40
 (0.35)
Gulf Coast (Divested)—
 1,268
 (1,268) —
 6.10
 (6.10)
 $137,070
 $171,141
 $(34,071) $4.10
 $4.40
 $(0.30)
Combined TotalYear Ended December 31, Favorable Year Ended December 31, Favorable
 2011 2010 (Unfavorable) 2011 2010 (Unfavorable)
       ($ per BOE)  
Texas    

     

Eagle Ford Shale$74,231
 $—
 $74,231
 $87.13
 $—
 $87.13
East Texas70,067
 67,241
 2,826
 33.00
 29.83
 3.17
Mid-Continent90,055
 101,022
 (10,967) 41.31
 39.51
 1.80
Mississippi28,971
 35,101
 (6,130) 26.53
 27.55
 (1.02)
Appalachia36,722
 45,796
 (9,074) 24.30
 26.43
 (2.13)
Gulf Coast (Divested)—
 2,176
 (2,176) —
 44.41
 (44.41)
 $300,046
 $251,336
 $48,710
 $38.67
 $31.95
 $6.72

As illustrated below, oil and NGL production volume coupled with improved oil and NGL pricing were the significant factors for increasing revenues. The increase was partially offset by lower natural gas production volumes and prices.

41


The following table provides an analysis of the change in our revenues for the year ended December 31, 2011 as compared to the year ended December 31, 2010:

  Revenue Variance Due to 
  Volume  Price  Total 
Natural gas $(24,223) $(9,848) $(34,071)
Crude oil  43,420   22,630   66,050 
NGL  9,343   7,388   16,731 
  $28,540  $20,170  $48,710 

2010.

 Revenue Variance Due to
 Volume Price Total
Crude oil$43,420
 $22,630
 $66,050
NGL9,343
 7,388
 16,731
Natural gas(24,223) (9,848) (34,071)
 $28,540
 $20,170
 $48,710

Effects of Derivatives

Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and crude oil prices.

In 2011 and 2010, we received $23.6 million and $33.5 million, respectively, in cash settlements of oil and gas derivatives.

The following table reconciles crude oil and natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Natural gas revenues as reported $137,070  $171,141  $(34,071)  (20)%
Cash settlements on natural gas derivatives, net  22,158   33,914   (11,756)  (35)%
Natural gas revenues adjusted for derivatives $159,228  $205,055  $(45,827)  (22)%
                 
Natural gas prices per Mcf, as reported $4.10  $4.40  $(0.29)  (7)%
Cash settlements on natural gas derivatives per Mcf  0.66   0.87   (0.21)  (24)%
Natural gas prices per Mcf adjusted for derivatives $4.77  $5.27  $(0.50)  (10)%
                 
Crude oil revenues as reported $119,582  $53,532  $66,050   123%
Cash settlements on crude oil derivatives, net  1,404   (434)  1,838   424%
Crude oil revenues adjusted for derivatives $120,986  $53,098  $67,888   128%
                 
Crude oil prices per Bbl, as reported $93.19  $75.56  $17.64   23%
Cash settlements on crude oil derivatives per Bbl  1.09   (0.61)  1.71   279%
Crude oil prices per Bbl adjusted for derivatives $94.29  $74.94  $19.34   26%

 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Crude oil revenues as reported$119,582
 $53,532
 $66,050
 123 %
Cash settlements on crude oil derivatives1,404
 (434) 1,838
 424 %
Crude oil revenues adjusted for derivatives$120,986
 $53,098
 $67,888
 128 %
        
Crude oil prices per Bbl, as reported$93.19
 $75.56
 $17.63
 23 %
Cash settlements on crude oil derivatives per Bbl1.09
 (0.61) 1.70
 279 %
Crude oil prices per Bbl adjusted for derivatives$94.28
 $74.95
 $19.33
 26 %
        
Natural gas revenues as reported$137,070
 $171,141
 $(34,071) (20)%
Cash settlements on natural gas derivatives22,158
 33,914
 (11,756) (35)%
Natural gas revenues adjusted for derivatives$159,228
 $205,055
 $(45,827) (22)%
        
Natural gas prices per Mcf, as reported$4.10
 $4.40
 $(0.30) (7)%
Cash settlements on natural gas derivatives per Mcf0.66
 0.87
 (0.21) (24)%
Natural gas prices per Mcf adjusted for derivatives$4.76
 $5.27
 $(0.51) (10)%
Gain on Sales of Property and Equipment

In December 2011, we sold approximately 2,700 net undeveloped acres in Butler and Armstrong countiesCounties in Pennsylvania for proceeds of $8.1 million, net of transaction costs. Wecosts, and recognized a gain of $3.3 million in connection with this transaction.million. In addition, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well materialmaterials during both 2011 and 2010.


Other Income

Other income, which includes ancillary gathering, transportation, compression and water disposal fees, net of marketing and related expenses, as well as other miscellaneous operating income, decreased marginally during 2011 as compared to 2010.

29


42


Operating Expenses

The following table summarizes certain of our operating expenses per McfeBOE for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Lease operating $0.79  $0.76  $(0.03)  (4)%
Gathering, processing and transportation  0.33   0.30   (0.03)  (8)%
Production and ad valorem taxes  0.29   0.29   0.00   0%
General and administrative excluding share-based compensation and restructuring charges   0.83   0.90   0.07   8%
General and administrative  1.04   1.24   0.20   16%
Depreciation, depletion and amortization  3.49   2.85   (0.64)  (22)%

 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Lease operating$4.77
 $4.55
 $(0.22) (5)%
Gathering, processing and transportation1.95
 1.80
 (0.15) (8)%
Production and ad valorem taxes1.76
 1.77
 0.01
 1 %
General and administrative excluding share-based compensation and restructuring charges4.97
 5.39
 0.42
 8 %
General and administrative6.23
 7.42
 1.19
 16 %
Depreciation, depletion and amortization20.95
 17.12
 (3.83) (22)%
Lease Operating

Lease operating expense increased during 2011 due primarily to higher employee-related and environmental compliance costs as well as higher work-over costs, particularly in the East Texas region. In addition, certain other costs, including water disposal, chemical treatment and general repairs and maintenance were generally higher commensurate with higher oil and NGL volume during 2011. These cost increases were partially offset by lower compression costs attributable to lower natural gas production in 2011 and our ongoing efforts to rationalize certain compression assets in our more mature producing regions in Appalachia and Mississippi.


Gathering, Processing and Transportation

Gathering, processing and transportation charges increased during 2011 due primarily to both higher processing costs and related volumes associated with NGL production. Due to lower overall natural gas volumes, particularly in the Appalachian region, we were unable to recover the cost of all of our unused firm transportation capacity.

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased on an absolute basis due to marginally lower production in 2011 as well as a decrease in the severance tax rate imposed by the State of Oklahoma on certain wells during the second half of 2011. We also recorded a property tax recovery from prior periods of $1.2 million in 2011 attributable to wells located in West Virginia. In 2010, we recorded ad valorem tax settlements of $1.4 million with certain jurisdictions that were also attributable to prior periods. As a percentage of revenue, excluding the recovery and settlements, production and ad valorem taxes decreased to 5.0% in 2011 from 6.1% during 2010.

General and Administrative

The following table sets forth the components of general and administrative expenses for the periods presented:

 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Recurring general and administrative expenses$38,547
 $42,372
 $3,825
 9%
Share-based compensation7,430
 7,811
 381
 5%
Restructuring expenses2,351
 8,200
 5,849
 71%
 $48,328
 $58,383
 $10,055
 17%

Recurring general and administrative expenses decreased due to lower employee headcount and lower support costs from restructuring actions taken during 2011 and 2010. Share-based compensation charges decreased during 2011 due primarily to a smaller number of awards that vested upon grant due to retirement eligibility. Restructuring expenses during 2011 included termination benefits, office and employee relocation and lease costs attributable to the restructuring following the sale of our Arkoma Basin properties. Restructuring expenses during 2010 included termination benefits and office and employee relocation costs as well as a $3.5 million charge related to the assignment of the lease of our former Kingsport, Tennessee office.

30


43


Exploration

The following table sets forth the components of exploration expenses for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Dry hole costs $18,864  $11,282  $(7,582)  (67)%
Geological and geophysical costs  11,202   10,168   (1,034)  (10)%
Unproved leasehold amortization  42,076   24,993   (17,083)  (68)%
Drilling rig charges  4,620   -   (4,620)  NM 
Other, primarily delay rentals  2,181   3,198   1,017   32%
  $78,943  $49,641  $(29,302)  (59)%

 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Dry hole costs$18,864
 $11,282
 $(7,582) (67)%
Geological and geophysical costs11,202
 10,168
 (1,034) (10)%
Unproved leasehold amortization42,076
 24,993
 (17,083) (68)%
Drilling rig charges4,620
 —
 (4,620) NM
Other, primarily delay rentals2,181
 3,198
 1,017
 32 %
 $78,943
 $49,641
 $(29,302) (59)%
The increase in dry hole costs was attributable primarily to four gross (2.7 net) unsuccessful wells in the Mid-Continent region during 2011 as compared to three gross (1.2 net) during 2010 in the same region. Geological and geophysical costs reflected a larger exploration program in 2011. The increase in amortization of unproved leaseholds was due primarily to significant acquisitions during 2010. In addition, we incurred rig-related charges during the 2011 period in connection with the current suspension of our drilling program in the Marcellus Shale.

Depreciation, Depletion and Amortization (DD&A)

The following tables set forth the components of DD&A and the nature of the DD&A variances for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Depletion $157,365  $127,836  $(29,529)  (23)%
Depreciation - Oil and gas operations  2,429   2,536   107   4%
Depreciation - Corporate  2,241   3,884   1,643   42%
Amortization  499   444   (55)  (12)%
  $162,534  $134,700  $(27,834)  (21)%

 DD&A Variance Due to
 Production Rates Total
Year ended December 31, 2011 compared to 2010$1,849
 $(29,683) $(27,834)

The effect of lower overall production volume on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average depletion rate increased to $3.38$20.95 per McfeBOE for 2011 from $2.71$17.12 per McfeBOE for 2010 due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale.


Impairments

The following table summarizes the impairments recorded for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Oil and gas properties $104,688  $43,067  $(61,621)  NM 
Other  -   2,892   2,892   NM 
  $104,688  $45,959  $(58,729)  NM 

 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Oil and gas properties$104,688
 $43,067
 $(61,621) (143)%
Other - tubular inventory and well materials—
 2,892
 2,892
 100 %
 $104,688
 $45,959
 $(58,729) (128)%
During 2011, we recognized an impairment of our Arkoma Basin assets for $71.1 million, which was triggered by the expected disposition of these high-cost gas properties. As described in Note 3, we completed the sale of these properties in August 2011. Also during 2011, we recognized an impairmentimpairments of our horizontal coal bed methane properties in the Appalachian region for $26.6 million and certain dry-gas properties in Mississippi for $7.0$6.8 million, in each case due primarily to market declines in gas prices. During 2010, we incurred impairment charges related to our Mid-Continent coal bed methane properties as a result of market declines in gas prices and to an area in the Anadarko Basin of the Mid-Continent region where we drilled an uneconomic well. In addition, we recorded impairment charges attributable to certain oil and gas inventory assets triggered primarily by declines in asset quality.

31

Other

During 2011, we recorded a reserve of $0.2 million for litigation attributable to properties that were previously sold. This matter was ultimately settled in January 2012 for the reserved amount. In addition, we wrote down certain gas imbalance assets that originated in prior years due to lower settlement rates. During 2010, we recorded a loss on the disposition of our Gulf Coast properties.


44


Interest Expense

The following table summarizes the components of our total interest expense for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Interest on borrowings and related fees $51,384  $43,060  $(8,324)  (19)%
Accretion of original issue discount  3,427   8,109   4,682   58%
Amortization of debt issuance costs  3,380   3,875   495   13%
Capitalized interest  (1,983)  (1,384)  599   43%
Other, net  8   19   11   58%
  $56,216  $53,679  $(2,537)  (5)%

 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Interest on borrowings and related fees$51,384
 $43,060
 $(8,324) (19)%
Accretion of original issue discount3,427
 8,109
 4,682
 58 %
Amortization of debt issuance costs3,380
 3,875
 495
 13 %
Capitalized interest(1,983) (1,384) 599
 (43)%
Other, net8
 19
 11
 58 %
 $56,216
 $53,679
 $(2,537) (5)%
The issuance of the 2019 Senior Notes at 7.25% and borrowings under the Revolver, partially offset by the repurchase of approximately 98% of the outstanding Convertible Notes with an effective interest rate of 8.5%, resulted in an approximate $88 million higher weighted-average balance of debt outstanding during 2011 as compared to 2010. Accordingly, interest expense increased due to thea higher average outstanding principal balance partially offset bydespite lower effective interest rates attributable to the 2019 Senior Notes and the Revolver. Capitalized interest was higherlower during 2011 due to higherlower carrying values on eligible capital projects.


Loss on Extinguishment of Debt

The repurchase in April 2011 of approximately 98% of the outstanding Convertible Notes resulted in a loss on extinguishment of debt of $24.2 million. The loss was comprised of non-cash charges for the excess of cash paid for the liability component over the carrying value, plus the write-off of a pro rata share of debt issuance costs and incremental transaction fees paid in cash. In addition, we recognized a charge of $1.2 million in August 2011 attributable to the Revolver and a change in the composition of the bank syndicate.

syndicate for our previous revolving credit facility.

Derivatives

The following table summarizes the components of our derivatives income for the periods presented:

  Year Ended December 31,  Favorable    
  2011  2010  (Unfavorable)  % Change 
Oil and gas derivative unrealized gain (loss) $(9,140) $3,213  $(12,353)  NM 
Oil and gas derivative realized gain  23,562   33,480   (9,918)  (30)%
Interest rate swap unrealized gain (loss)  (2,589)  5,875   (8,464)  (144)%
Interest rate swap realized gain (loss)  3,818   (662)  4,480   NM 
  $15,651  $41,906  $(26,255)  (63)%

 Year Ended December 31, Favorable  
 2011 2010 (Unfavorable) % Change
Oil and gas derivative unrealized gain (loss)$(9,140) $3,213
 $(12,353) (384)%
Oil and gas derivative realized gain23,562
 33,480
 (9,918) (30)%
Interest rate swap unrealized gain(2,589) 5,875
 (8,464) (144)%
Interest rate swap realized loss3,818
 (662) 4,480
 (677)%
 $15,651
 $41,906
 $(26,255) (63)%
We received cash settlements of $27.4 million during 2011 and $32.8 million during 2010. The amount received duringin 2011 includesincluded $2.9 million attributable to the termination of our interest rate swap.


Other

Other income decreased due primarily to lower interest income earned on average cash balances during 2011 and gains on the sale of non-operating investments recognized during 2010.


Income Taxes

The effective tax benefit rate for continuing operations during 2011 was 39.9% compared to 39.6% for 2010. Due to the operating losses incurred, we recognized an income tax benefit during both periods. In addition, the effective tax rate for 2011 includesincluded a deferred tax asset valuation allowance due primarily to the inability to recognize a tax benefit for certain state net operating losses.

32

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

The following table sets forth a summary of certain operating and financial performance for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Total Production:                
Natural gas (MMcf)  38,919   43,338   (4,419)  (10)%
Crude oil (MBbl)  709   750   (41)  (6)%
NGL (MBbl)  672   527   145   28%
Total production (MMcfe)  47,201   51,000   (3,799)  (7)%
                 
Realized prices, before derivatives:                
Natural gas ($/Mcf) $4.40  $3.91  $0.49   13%
Crude oil ($/Bbl)  75.56   57.68   17.88   31%
NGL ($/Bbl)  39.69   29.86   9.83   33%
Total ($/Mcfe) $5.32  $4.48  $0.84   19%
                 
Revenues                
Natural gas $171,141  $169,666  $1,475   1%
Crude oil  53,532   43,258   10,274   24%
NGL  26,663   15,735   10,928   69%
Total product revenues  251,336   228,659   22,677   10%
Gain on sale of property and equipment  648   2,372   (1,724)  (73)%
Other income  2,454   4,175   (1,721)  (41)%
Total revenues  254,438   235,206   19,232   8%
                 
Operating Expenses                
Lease operating  35,757   44,392   8,635   19%
Gathering, processing and transportation  14,180   11,307   (2,873)  (25)%
Production and ad valorem taxes  13,917   15,044   1,127   7%
General and administrative  58,383   49,690   (8,693)  (17)%
Exploration  49,641   57,754   8,113   14%
Depreciation, depletion and amortization  134,700   154,351   19,651   13%
Impairments  45,959   106,415   60,456   57%
Other  709   1,599   890   56%
Total operating expenses  353,246   440,552   87,306   20%
                 
Operating loss  (98,808)  (205,346)  106,538   52%
Other income (expense)                
Interest expense  (53,679)  (44,231)  (9,448)  (21)%
Derivatives  41,906   31,568   10,338   33%
Other  2,403   1,259   1,144   91%
Loss from continuing operations before income taxes  (108,178)  (216,750)  108,572   (50)%
Income tax benefit  42,851   85,894   (43,043)  (50)%
Loss from continuing operations  (65,327)  (130,856)  65,529   (50)%
Income from discontinued operations, net of tax  33,448   53,488   (20,040)  (37)%
Gain on sale of discontinued operations, net of tax  51,546   -   51,546   NM 
Net income (loss)  19,667   (77,368)  97,035   125%
Less net income attributable to noncontrolling interests  (28,090)  (37,275)  9,185   25%
Net loss attributable to Penn Virginia Corporation $(8,423) $(114,643) $106,220   93%

Production

The following tables set forth a summary of our total and daily production volumes by product and geographical region for the periods presented:

Natural Gas Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable)  % Change 
  (MMcfe)     (MMcfe per day)       
Texas  10,510   9,966   544   28.8   27.3   1.5   5%
Appalachia  10,358   11,453   (1,095)  28.4   31.4   (3.0)  (10)%
Mid-Continent  10,338   9,602   736   28.3   26.3   2.0   8%
Mississippi  7,505   7,694   (189)  20.6   21.1   (0.5)  (2)%
Gulf Coast (Divested)  208   4,623   (4,415)  0.6   12.7   (12.1)  (96)%
Total production  38,919   43,338   (4,419)  106.7   118.8   (12.1)  (10)%

Crude Oil Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable)  % Change 
  (MBbl)     (MBbl per day)       
Texas  113.5   109.9   3.6   0.31   0.30   0.01   3%
Appalachia  5.1   1.8   3.3   0.01   0.00   0.01   183%
Mid-Continent  559.3   476.5   82.8   1.53   1.31   0.22   17%
Mississippi  22.9   21.3   1.6   0.06   0.06   0.00   7%
Gulf Coast (Divested)  7.7   140.9   (133.2)  0.02   0.39   (0.37)  (95)%
Total production  708.5   750.4   (41.9)  1.93   2.06   (0.13)  (6)%

NGLs Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable)  % Change 
  (MBbl)     (MBbl per day)       
Texas  389.1   415.3   (26.2)  1.07   1.14   (0.07)  (6)%
Appalachia  1.4   0.2   1.2   0.00   0.00   0.00   NM 
Mid-Continent  274.4   60.8   213.6   0.75   0.17   0.58   351%
Gulf Coast (Divested)  6.9   50.4   (43.5)  0.02   0.14   (0.12)  (86)%
Total production  671.8   526.7   145.1   1.84   1.45   0.39   28%

Combined Total Year Ended December 31,  Favorable  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable)  % Change 
  (MMcfe)     (MMcfe per day)       
Texas  13,526   13,116   410   37.1   35.9   1.2   3%
Appalachia  10,397   11,465   (1,068)  28.5   31.4   (2.9)  (9)%
Mid-Continent  15,340   12,826   2,514   42.0   35.1   6.9   20%
Mississippi  7,643   7,822   (179)  20.9   21.5   (0.6)  (2)%
Gulf Coast (Divested)  295   5,771   (5,476)  0.8   15.8   (15.0)  (95)%
Total production  47,201   51,000   (3,799)  129.3   139.7   (10.4)  (7)%

The decline in production during 2010 was attributable to the disposition of our Gulf Coast properties in January 2010, the significant reduction in drilling activity in 2009 and natural declines in production rates. We also experienced equipment and service-related delays in new well completions during the first half of 2010 primarily in the Lower Bossier (Haynesville) Shale play in the Texas region. The overall decline in production volume was partially offset by production from new wells in the Granite Wash play in the Mid-Continent region that were brought online during 2010 despite interference attributable to offset wells during stimulation.

NGL production increased to 18% of the total production in 2010 compared to 15% in 2009. In addition, a processing agreement was signed for a major portion of our Granite Wash production which contributed to the increase in 2010 NGL production.

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Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of volume by product and geographical region for the periods presented:

Natural Gas Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable) 
           ($ per Mcfe)    
Texas $43,247  $36,696  $6,551  $4.11  $3.68  $0.43 
Appalachia  45,581   46,773   (1,192)  4.40   4.08   0.32 
Mid-Continent  47,694   34,115   13,579   4.61   3.55   1.06 
Mississippi  33,351   31,509   1,842   4.44   4.10   0.34 
Gulf Coast (Divested)  1,268   20,573   (19,305)  6.10   4.45   1.65 
Total revenues $171,141  $169,666  $1,475  $4.40  $3.91  $0.49 

Crude Oil Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable) 
           ($ per Bbl)    
Texas $8,844  $5,984  $2,860  $77.92  $54.45  $23.47 
Appalachia  164   85   79   32.16   47.22   (15.06)
Mid-Continent  42,176   27,828   14,348   75.41   58.40   17.01 
Mississippi  1,750   1,283   467   76.42   60.23   16.19 
Gulf Coast (Divested)  598   8,078   (7,480)  77.66   57.33   20.33 
Total revenues $53,532  $43,258  $10,274  $75.56  $57.68  $17.88 

NGLs Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable) 
           ($ per Bbl)    
Texas $15,150  $12,479  $2,671  $38.94  $30.05  $8.89 
Appalachia  51   5   46   36.43   25.00   11.43 
Mid-Continent  11,152   1,777   9,375   40.64   29.23   11.41 
Gulf Coast (Divested)  310   1,474   (1,164)  44.93   29.25   15.68 
Total revenues $26,663  $15,735  $10,928  $39.69  $29.86  $9.83 

Combined Total Year Ended December 31,  Favorable  Year Ended December 31,  Favorable 
  2010  2009  (Unfavorable)  2010  2009  (Unfavorable) 
           ($ per Mcfe)    
Texas $67,241  $55,159  $12,082  $4.97  $4.21  $0.76 
Appalachia  45,796   46,863   (1,067)  4.40   4.09   0.31 
Mid-Continent  101,022   63,720   37,302   6.59   4.97   1.62 
Mississippi  35,101   32,792   2,309   4.59   4.19   0.40 
Gulf Coast (Divested)  2,176   30,125   (27,949)  7.38   5.22   2.16 
Total revenues $251,336  $228,659  $22,677  $5.32  $4.48  $0.84 

As illustrated below, revenues were higher in 2010 compared to 2009 as the decline in production volume discussed above was more than offset by improved pricing for all three commodity product types. The following table provides an analysis of the change in our revenues for the year ended December 31, 2010 as compared to the year ended December 31, 2009:

  Revenue Variance Due to 
  Volume  Price  Total 
Natural gas $(17,301) $18,776  $1,475 
Crude oil  (2,393)  12,667   10,274 
NGL  4,323   6,605   10,928 
  $(15,371) $38,048  $22,677 

Effects of Derivatives

In 2010 and 2009, we received $33.5 million and $59.9 million in cash settlements of oil and gas derivatives.

The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:

  Year Ended December 31,  Favorable   
  2010  2009  (Unfavorable)  % Change 
Natural gas revenues as reported $171,141  $169,666  $1,475   1%
Cash settlements on natural gas derivatives  33,914   55,545   (21,631)  (39)%
Natural gas revenues adjusted for derivatives $205,055  $225,211  $(20,156)  (9)%
                 
Natural gas prices per Mcf, as reported $4.40  $3.91  $0.49   12%
Cash settlements on natural gas derivatives per Mcf  0.87   1.28   (0.41)  (32)%
Natural gas prices per Mcf adjusted for derivatives $5.27  $5.19  $0.08   2%
                 
Crude oil revenues as reported $53,532  $43,258  $10,274   24%
Cash settlements on crude oil derivatives  (434)  4,361   (4,795)  (110)%
Crude oil revenues adjusted for derivatives $53,098  $47,619  $5,479   12%
                 
Crude oil prices per Bbl, as reported $75.56  $57.68  $17.88   31%
Cash settlements on crude oil derivatives per Bbl  (0.61)  5.81   (6.43)  (111)%
Crude oil prices per Bbl adjusted for derivatives $74.94  $63.49  $11.45   18%

Gain on Sales of Property and Equipment

In 2010, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well materials. In 2009, we recognized gains on the sale of certain properties and equipment in our Texas region.

Other Income

Other income decreased primarily as a result of lower gathering revenues during 2010 and the effect of a favorable audit settlement during 2009 partially offset by higher compression services revenues.

Operating Expenses

The following table summarizes certain of our operating expenses per Mcfe for the periods presented:

  Year Ended December 31,  Favorable   
  2010  2009  (Unfavorable)  % Change 
Lease operating $0.76  $0.87  $0.11   13%
Gathering, processing and transportation  0.30   0.22   (0.08)  (36)%
Production and ad valorem taxes  0.29   0.29   0.00   0%
General and administrative excluding share-based compensation and restructuring charges  0.90   0.78   (0.12)  (15)%
General and administrative  1.24   0.97   (0.27)  (27)%
Depreciation, depletion and amortization  2.85   3.03   0.18   6%

36

Lease Operating

The most significant decline in lease operating expenses resulted from decreases in charges that are generally correlated with production volume including water disposal, compressor and other equipment rentals, contract labor, chemical and treating and repairs and maintenance costs.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased during 2010 primarily as a result of a settlement with a gathering services provider attributable to disputed charges in several prior periods, as well as a change in the geographic distribution of production from the Gulf Coast to the Mid-Continent region where we typically experience higher processing costs associated with NGLs. These items were offset partially by the effects of lower volume in the current period.

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased on an absolute basis by $1.1 million primarily reflecting ad valorem tax settlements of approximately $1.4 million with certain jurisdictions attributable to prior periods, while production taxes increased commensurately with higher revenues. As a percentage of revenue, production and ad valorem taxes, excluding the settlements, decreased to 6.1% in 2010 from 6.6% during 2009.

General and Administrative

The following table sets forth the components of general and administrative expenses for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Recurring general and administrative expenses $42,372  $40,034  $(2,338)  (6)%
Share-based compensation  7,811   9,127   1,316   14%
Restructuring expenses  8,200   529   (7,671)  NM 
  $58,383  $49,690  $(8,693)  (17)%

Recurring general and administrative expenses increased in 2010 due primarily to higher consulting and professional fees attributable to our divestiture of Penn Virginia GP Holdings, L.P., or PVG. Share-based compensation charges decreased during 2010 due primarily to a smaller population of employees receiving awards. Restructuring expenses during both 2010 and 2009 include costs associated with the organization restructuring announced during November 2009. These costs include termination benefits, office and employee relocation costs as well as a $3.5 million charge related to the assignment of our lease of our former Kingsport, Tennessee office.

Exploration

The following table sets forth the components of exploration expenses for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Dry hole costs $11,282  $1,397  $(9,885)  NM 
Geological and geophysical costs  10,168   912   (9,256)  NM 
Unproved leasehold amortization  24,993   31,618   6,625   21%
Drilling rig charges  -   20,084   20,084   NM 
Other, primarily delay rentals  3,198   3,743   545   15%
  $49,641  $57,754  $8,113   14%

The decrease in exploration expense is attributable primarily to rig standby charges incurred during 2009. These charges were a result of our 2009 drilling program reduction due to unfavorable economic conditions. In addition, the 2009 period reflects the initial impact of a change in accounting estimate to amortize collectively insignificant unproved properties over the average estimated life of the leases rather than amortizing some leases and assessing other leases individually. The decrease was offset partially by dry hole costs in the Mid-Continent region incurred during 2010 and higher geological and geophysical costs attributable to our larger 2010 exploration program.

37

Depreciation, Depletion and Amortization (DD&A)

The following tables set forth the components of DD&A and the nature of the variances for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Depletion $127,836  $147,174  $19,338   13%
Depreciation - Oil and gas operations  2,536   2,756   220   8%
Depreciation - Corporate  3,884   3,922   38   1%
Amortization  444   499   55   11%
  $134,700  $154,351  $19,651   13%

  DD&A Variance Due to  
  Production  Rates  Total  
Year ended December 31, 2010 compared to 2009 $11,499  $8,152  $19,651  

Our average depletion rate decreased by $0.18 per Mcfe, or 6%, to $2.71 per Mcfe in 2010, from $2.89 per Mcfe in 2009. The reduction was a result of discoveries and the impact of impairments in 2010.

Impairments

The following table summarizes the impairments recorded for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Oil and gas properties $43,067  $102,332  $59,265   58%
Other  2,892   4,083   1,191   29%
  $45,959  $106,415  $60,456   57%

During 2010, we incurred impairment charges related to our Mid-Continent coal bed methane properties as a result of market declines in gas prices and to an area in the Anadarko basin of the Mid-Continent region where we drilled an uneconomic well. In addition, we recorded impairment charges attributable to certain oil and gas inventory assets triggered primarily by declines in asset quality. We also incurred impairment charges on properties in North Dakota that were held for sale at the end of 2009. These properties were ultimately sold during 2010. During 2009, we incurred impairment charges in connection with the initial classification of the Gulf Coast properties as assets held for sale at their fair value less costs to sell, as well as impairments attributable to tubular inventory and other oil and gas properties.

Other

During 2010, we recorded a loss of $0.7 million on the disposition of our Gulf Coast properties. The loss reflects final purchase price adjustments associated with the period from the effective date in October 2009 to the closing date in January 2010. The 2009 period reflects a loss on the sales of tubular inventory and well materials.

Interest Expense

The following table summarizes the components of our total interest expense for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Interest on borrowings and related fees $43,060  $33,374  $(9,686)  (29)%
Accretion of original issue discount  8,109   7,523   (586)  (8)%
Amortization of debt issuance costs  3,875   2,679   (1,196)  (45)%
Interest rate swaps  -   3,969   3,969   NM 
Capitalized interest  (1,384)  (2,318)  (934)  (40)%
Other, net  19   (996)  (1,015)  (102)%
  $53,679  $44,231  $(9,448)  (21)%

Interest expense increased due to higher interest rates on outstanding borrowings, primarily the 10.375% Senior Unsecured Notes, or 2016 Senior Notes, issued in June 2009. We realized higher amortization of the original issue discount and issuance costs on the 2016 Senior Notes and Convertible Notes, as well as higher amortization of issuance costs associated with the Revolver. In addition, 2009 included a reclassification of expense from accumulated other comprehensive income, or AOCI, attributable to the discontinuation of hedge accounting related to our interest rate swaps, as well as a reversal of interest cost attributable to the settlement of various state income tax positions.

Derivatives

The following table summarizes the components of our derivatives income for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Oil and gas derivative unrealized gain (loss) $3,213  $(26,690) $29,903   112%
Oil and gas derivative realized gain  33,480   59,908   (26,428)  (44)%
Interest rate swap unrealized gain  5,875   111   5,764   NM 
Interest rate swap realized loss  (662)  (1,761)  1,099   62%
  $41,906  $31,568  $10,338   33%

Cash received for settlements during 2010 was $32.8 million as compared to $58.1 million during 2009.

Other

Other income increased during 2010 due primarily to the gains on the sale of non-operating investments as well as higher interest income on the significantly larger cash balances held following of the disposition of our interests in PVG.

Income Taxes

The effective tax benefit rate for continuing operations was 39.6% for 2010 and 2009. Due to the operating losses incurred, we recognized an income tax benefit during both periods.

Discontinued Operations

The following table presents a summary of results of operations from discontinued operations for the periods presented:

  Year Ended December 31,  Favorable    
  2010  2009  (Unfavorable)  % Change 
Revenues $303,206  $579,931  $(276,725)  48%
                 
Income from discontinued operations before taxes $36,832  $64,130  $(27,298)  43%
Income tax expense1  (3,384)  (10,642)  7,258   68%
Income from discontinued operations, net of taxes $33,448  $53,488  $(20,040)  37%


45

1   Determined by applying the effective tax rate attributable to discontinued operations to the income from discontinued operations less noncontrolling interests that are fully attributable to PVG's operations.

The disclosures for 2010 provided in the table above reflect the results of operations of PVG through the date of disposition of our entire remaining interest in PVG on June 7, 2010.

39


Gain on Sale of Discontinued Operations

The following table summarizes the determination of the gain recognized upon the disposition of PVG: 

Cash proceeds, net of offering costs (8,827,429 units x $15.76 per unit) $139,120 
Carrying value of noncontrolling interests in PVG at date of disposition  382,324 
   521,444 
Less: Carrying value of PVG's assets and liabilities at date of disposition  (434,782)
   86,662 
Less: Income tax expense  (35,116)
Gain on sale of discontinued operations, net of tax $51,546 

Noncontrolling Interests

The decrease in net income attributable to noncontrolling interests during 2010 is directly attributable to the sale of our interests in PVG during June 2010. In September 2009, our ownership interest in PVG declined from 77.0% to 51.4% and in 2010 our ownership interest in PVG declined to zero.

40

Liquidity and Capital Resources

Sources of Liquidity

We are currently meeting our capital expenditures and working capital funding requirements with a combination of operating cash flows and borrowings from our Revolver.

We have no material debt maturities until 2016. Our business strategy for 2012 requirescontemplates capital expenditures in excess of our anticipatedprojected operating cash flows.flows for 2013. Subject to the variability of commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our 20122013 capital program with operating cash flows and borrowings from ourunder the Revolver. We expect to supplement these sources of liquidity with proceeds from the sale of non-core assets or, possibly, by accessing the capital markets. There can be no assurance that such actions would be successful, however, in which case we could reduce our

In September 2012, planned capital expenditures.

In August 2011, we entered into the Revolver, which matures in August 2016.replaced our previous revolving credit facility. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has a borrowing base of $380 million. There is an accordion feature that allows us to increase the commitment by up to the loweran additional aggregate of the borrowing base or $600$300 million upon receiving additional commitments from one or more lenders. The Revolver is governed by a borrowing base calculation, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver is $300 million and will be re-determined based on a semi-annual review of our total proved oil, NGL and natural gas reserves starting in the spring of 2013. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions.

The borrowing base is redetermined semi-annually, and the next redetermination is scheduled to occur during April 2012. The primary assets supporting our borrowing base are our proved developed reserves, approximately 77% of which are natural gas. Due primarily to the significant declineRevolver matures in natural gas prices that has continued into the first quarter of 2012 and despite the increase in our oil reserves, we anticipate a potentially material reduction in our borrowing base from its current level of $380 million. As of the date of this filing, we are unable to determine a meaningful potential range of the reduction, due primarily to the fact that a number of determinative variables are not known at this time; however, we do not anticipate a material reduction to our current Revolver commitment of $300 million. Accordingly, our current business plans anticipate us borrowing amounts under the Revolver that are within the current commitment level of $300 million.

September 2017.


As of February 21, 2012,15, 2013, we had approximately $11 million of cash on hand and $182.6$270.2 million of unused borrowing capacity available to us under ourthe Revolver. The borrowing capacity is determined by reducing the revolving commitment of $300 million by outstanding borrowings of $116.0$28.0 million and outstanding letters of credit of $1.4$1.8 million.


The following table summarizes our borrowing activity under the Revolver and our previous credit facility during the periods presented:

  Borrowings Outstanding    
  Weighted-     Weighted- 
  Average  Maximum  Average Rate 
Three months ended December 31, 2011 $61,696  $99,000   1.9448%
August 2, 2011 through December 31, 20111 $44,974  $99,000   1.9118%

presented

1 There were no amounts outstanding under the previous credit facility from January 1, 2011 through its termination date of August 2, 2011. 

 Borrowings Outstanding  
 
Weighted-
Average
 Maximum 
Weighted-
Average Rate
Three months ended December 31, 2012$16,152
 $107,000
 2.0673%
Year ended December 31, 2012$102,358
 $190,000
 2.1309%

Our revenues are subject to significant volatility as a result of changes in commodity prices. Accordingly, we actively manage the exposure of our operating cash flows to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of derivatives, typically collar, swap and swaption contracts. The level of our hedging activity and duration of the instruments employed depend uponon our cash flow at risk, available hedge prices and our operating strategy. During 2011,2012, our commodity derivatives portfolio provided $22.2$8.4 million of cash inflows related to lower than anticipated prices received for our natural gasoil production and $1.4$19.9 million of cash inflows attributable to lower than anticipated prices received for our crude oilnatural gas production.

In January 2012, we amended the Revolver to enhance our ability to hedge production. Previously, our hedging was limited to the lesser of certain fixed percentages of our reasonably anticipated production from proved developed reserves and total proved reserves. The amendment expands the potential volume subject to hedging to certain percentages of reasonably anticipated production from proved undeveloped reserves as well as proved developed reserves.

For 2012,2013, we have hedged approximately 32% of our estimated natural gas production, at a weighted average floor/swap price and ceiling prices of between $5.43 and $6.05 per MMBtu. In addition, we have hedged approximately 47%58 percent of our estimated crude oil production, for 2012, at weighted average floor/swap and ceiling prices of between $97.08$97.35 and $99.61$100.99 per barrel.

41
In addition, we have hedged approximately 55 percent of our estimated natural gas production for 2013, at a weighted average floor/swap and ceiling prices of $3.76 and $4.19 per MMBtu.





46


Cash Flows

The following table summarizes our statements of cash flows for the periods presented:

  Year Ended December 31,    
  2011  2010  Variance 
Cash flows from operating activities $144,741  $79,839  $64,902 
Cash flows from investing activities            
Capital expenditures -  property and equipment  (445,623)  (405,994)  (39,629)
Proceeds from the sale of PVG units, net  -   139,120   (139,120)
Proceeds from sales of property and equipment and other, net  39,468   26,759   12,709 
Net cash used in investing activities  (406,155)  (240,115)  (166,040)
Cash flows from financing activities            
Dividends paid  (10,316)  (10,271)  (45)
Proceeds from revolving credit facility borrowings, net  99,000   -   99,000 
Proceeds from issuance of Senior Notes due 2019  300,000   -   300,000 
Repurchase of Convertible Notes  (232,963)  -   (232,963)
Debt issuance costs paid  (8,854)  -   (8,854)
Proceeds from sale of PVG units, net  -   199,125   (199,125)
Distributions received from discontinued operations  -   11,218   (11,218)
Other, net  1,148   2,098   (950)
Net cash provided by financing activities  148,015   202,170   (54,155)
Net increase (decrease)  in cash and cash equivalents $(113,399) $41,894  $(155,293)

 Year Ended December 31,  
 2012 2011 Variance
Cash flows from operating activities    

Operating cash flows, net$217,708
 $182,948
 $34,760
Working capital changes, net20,157
 (12,165) 32,322
Commodity derivative settlements received, net:    —
Crude oil8,427
 1,404
 7,023
Natural gas19,890
 22,157
 (2,267)
Interest payments, net of amounts capitalized(54,808) (44,589) (10,219)
Income tax refunds received (payments made), net32,603
 (210) 32,813
Transaction costs paid for extinguishment of debt(20) (2,965) 2,945
Restructuring and exit costs paid(2,499) (1,839) (660)
Net cash provided by operating activities241,458
 144,741
 96,717
Cash flows from investing activities 
  
  
Capital expenditures -  property and equipment(370,907) (445,623) 74,716
Proceeds from sales of assets and other, net96,899
 39,468
 57,431
Net cash used in investing activities(274,008) (406,155) 132,147
Cash flows from financing activities 
  
  
Proceeds from the issuance of preferred stock, net110,337
 —
 110,337
Proceeds from the issuance of common stock, net43,474
 —
 43,474
Proceeds from the issuance of senior notes—
 300,000
 (300,000)
Retirement of convertible notes(4,915) (232,963) 228,048
Proceeds from revolving credit facility borrowings, net(99,000) 99,000
 (198,000)
Debt issuance costs paid(2,032) (8,854) 6,822
Dividends paid(5,176) (10,316) 5,140
Other, net—
 1,148
 (1,148)
Net cash provided by financing activities42,688
 148,015
 (105,327)
Net increase (decrease) in cash and cash equivalents$10,138
 $(113,399) $123,537
Cash Flows From Operating Activities

The following table summarizes the most significant variances in our cash flows from operating activities:

Cash flows from operating activities for the year ended December 31, 2010 $79,839 
Variances due to:    
Lower settlements from commodity derivatives portfolio  (9,918)
Higher interest payments, net of amounts capitalized  (960)
Lower restructuring costs paid  6,826 
Lower tax payments  27,974 
Transaction costs paid in connection with extinguishment of debt  (2,433)
Effect of higher operating margins, net of working capital changes  43,413 
Cash flows from operating activities for the year ended December 31, 2011 $144,741 

Due primarily to the realization of higher net margins on our expanding crude oil and NGL production as well as the receipt of a federal tax refund of approximately $32 million, our cash flows from operating activities improved significantly during 20112012 as compared to 2010.2011. During 2011,2012, we realized lowerhigher settlements from our commodity derivatives portfolio as compared to 20102011 due primarily to higher realizedlower natural gas prices as well as lower overall hedged production volume. Interest payments on our debt wereprices. We paid higher amounts for interest during 20112012 due to higher average outstanding debt balances partially offset by a favorable settlement of $2.9 million upon the termination of ourand higher average interest rate swap. Restructuring costs paid were lower during 2011 as compared to 2010 due primarily to the larger scale of restructuring activities during 2010, which included, among other costs, a $3.5 million payment for the assignment of the lease of a former office. Income tax payments were significantly lower during 2011 as compared to 2010 as the prior year included higher income tax payments primarily attributable to the gain realized on the sale of our interests in PVG.rates. During 2011, we paid incremental transaction costs in connection with the extinguishment of ourthe Convertible Notes, as well as costs attributable to the change in the composition of the bank syndicate in connection with our former credit facility. Restructuring and exit costs paid were higher in 2012 as compared to 2011 due primarily to the Revolver.

larger scale of restructuring activities during 2012, which included, among other costs, ongoing contractual payments for firm transportation capacity in the Appalachian region subsequent to our sale of assets in that region and payments to terminate the lease of our former office in Canonsburg, Pennsylvania.


Cash Flows From Investing Activities


Capital expenditures were higherlower during 20112012 due primarily to significant investment in our focus on Eagle Ford Shale properties, including lease acquisition costsdrilling. During most of approximately $30 million and development and exploratory drilling expenditures of approximately $372 million. Included2012 we operated only two rigs in our capital expenditures forthis area while 2011 was approximately $12 million for proppant chemicals usedincluded up to four rigs operating in our well completion activities. These expenditures occurred near the end ofseveral regions. During 2011, and we are consuming these materials in connection with our 2012 capital projects. Previously, these products were provided by our well completion vendors in connection with their service offerings. Our purchase of these materials directly from product suppliers is expected to result in lower costs of well completions due to favorable pricing. Capital expenditures during 2010 includedacquired significant property acquisitions in the Marcellus Shale and our initial acreage in the Eagle Ford Shale as well as significant exploratory and development drilling expenditures primarily in the Granite Washhad a more extensive capital program in the Mid-Continent region. These expendituresregion in the first half of the year. During 2011, we also acquired approximately $12 million of proppant chemicals that were partially offsetused in our well completion activities in the latter part of 2011 and the first half of 2012.


47


Proceeds from sales of non-core properties and other assets were received during both years by proceeds2012 and 2011. The amounts received fromduring 2012 were attributable primarily to the sale of non-core assets, mostly comprisedour West Virginia, Kentucky and Virginia properties. The amounts received in 2011 were attributable primarily to the sale of our Arkoma Basin assets in 2011properties and our Gulf Coast assets in 2010. In addition, we received proceeds in 2010 from the salea portion of our remaining interestsundeveloped acreage in PVG.

Butler and Armstrong Counties.

The following table sets forth costs related to our capital expenditure programsprogram for the periods presented:

  Year Ended December 31, 
  2011  2010 
Oil and gas:        
Development drilling $307,779  $243,446 
Exploration drilling  64,075   54,340 
Seismic  11,202   10,168 
Lease acquisitions, field projects and other  50,060   140,473 
Pipeline and gathering facilities  12,484   1,407 
   445,600   449,834 
Other - Corporate  1,148   1,337 
Total capital program costs $446,748  $451,171 

 Year Ended December 31,
 2012 2011
Oil and gas: 
  
Development drilling$287,363
 $307,779
Exploration drilling49,462
 64,075
Geological and geophysical (seismic) costs816
 11,202
Lease acquisitions28,380
 50,060
Pipeline, gathering facilities and other18,330
 12,484
 384,351
 445,600
Other - Corporate629
 1,148
Total capital program costs$384,980
 $446,748
The following table reconciles the total costs of our capital expenditures programsexpenditure program with the net cash paid for capital expenditures for additions to property and equipment as reported in our Consolidated Statements of Cash Flows for the periods presented:

  Year Ended December 31, 
  2011  2010 
Total capital program costs $446,748  $451,171 
Less:        
Exploration expenses        
Seismic  (11,202)  (10,168)
Other, primarily delay rentals  (2,183)  (2,379)
Other  (912)  - 
Changes in accrued capitalized costs  (744)  (20,197)
Property received as consideration in sale transaction1  -   (8,204)
Add:        
Capitalized interest  1,983   1,384 
Well materials purchased in advance of drilling  11,833   - 
Other  100   (5,613)
Total cash paid for capital expenditures $445,623  $405,994 

1 Represents property received in Mississippi in connection with the sale of our Gulf Coast properties.

 Year Ended December 31,
 2012 2011
Total capital program costs$384,980
 $446,748
Less: 
  
Exploration expenses 
  
Geological and geophysical (seismic)(816) (11,202)
Other, primarily delay rentals(646) (2,183)
Transfers from tubular inventory and well materials(13,359) (912)
Changes in accrued capitalized costs(4,550) (744)
Add: 
  
Tubular inventory and well materials purchased in advance of drilling4,495
 11,833
Capitalized interest803
 1,983
Other—
 100
Total cash paid for capital expenditures$370,907
 $445,623

Cash Flows From Financing Activities


Cash provided byflows from financing activities during 2011 included the combined offering of preferred and common stock in 2012 which provided $153.8 million of proceeds, net of underwriting fees and issuance ofcosts. These proceeds were used primarily to repay outstanding borrowings under the Revolver. During 2011, we issued $300 million of 2019 Senior Notes, offset substantially by the repurchase of approximately 98% of ourthe Convertible Notes and related transaction costs. DuringWe retired the third quarterremaining Convertible Notes upon their maturity in November 2012. Both years included the payment of 2011, we began borrowing underdebt issuance costs attributable to our Revolver. In addition, we paid dividends totaling $10.3 millioncredit facilities and dividend payments on our common stock.

During April 2010, we sold 11.25 million common units of PVG for proceeds of $199.1 million, net of offering costs, which reduced our limited partner interest in PVG to 22.6%. Because we maintained a controlling financial interest in PVG until the final sale, the proceeds from these transactions are reported as cash flows from financing activities. In addition, we received $11.2 million in distributions from PVG prior to our complete divestiture in 2010 as well as $2.1 million from the exercise of stock options by employees. We also paid dividends totaling $10.3 million on our common stock.



48


Financial Condition

As of February 21, 2012,15, 2013, we had approximately $11 million of cash on hand and $182.6$270.2 million of unused borrowing capacity available to us under ourthe Revolver. The borrowing capacity is determined by reducing the revolving commitment of $300 million by outstanding borrowings of $116.0$28.0 million and outstanding letters of credit of $1.4$1.8 million.

Debt and Credit Facilities

  As of December 31, 
  2011  2010 
Revolving credit facility $99,000  $- 
Senior notes due 2016, net of discount (principal amount of $300,000)  293,561   292,487 
Senior notes due 2019  300,000   - 
Convertible notes due 2012, net of discount (principal amount of $4,915 and $230,000)  4,746   214,049 
   697,307   506,536 
Less: Current portion of long-term debt  (4,746)  - 
  $692,561  $506,536 

and Preferred Stock Financing

 As of December 31,
 2012 2011
Revolving credit facility$—
 $99,000
Senior notes due 2016, net of discount (principal amount of $300,000)294,759
 293,561
Senior notes due 2019300,000
 300,000
Convertible notes due 2012, net of discount (principal amount of $4,915)—
 4,746
 594,759
 697,307
Less: Current portion of long-term debt—
 (4,746)
 $594,759
 $692,561
Revolving Credit Facility.Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities, or Adjusted LIBOR, plus an applicable margin ranging(ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). TheIn each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are being charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined bydepending on our ratio of outstanding borrowings to the available Revolver capacity. As of December 31, 2011,February 15, 2013, the effectiveactual interest rate on the outstanding borrowings under the Revolver was 2.0625%1.75%.

The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries, or the Guarantor Subsidiaries. The obligations under the Revolver are secured by a first priority lien on substantially all of our proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.

2016 Senior Notes.The Senior Notes due 2016, or the 2016 Senior Notes, bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. The 2016 Senior Notes were sold at 97% of par in June 2009, equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Under the Revolver, we are permitted under certain conditions to repurchase up to $100 million of the 2016 Senior Notes until August 2012. Accordingly, we may, from time to time, seek to repurchase the 2016 Senior Notes through open market purchases or privately negotiated transactions. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

2019 Senior Notes. The 2019 Senior Notes, which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable on April 15 and October 15 of each year. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Convertible Notes.

6% Preferred Stock. The Convertible Notes, which matureannual dividend on each share of the 6% Preferred Stock is 6.00% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in November 2012, arearrears, on each of January 15, April 15, July 15 and October 15 of each year, commencing on January 15, 2013. We may, at our option, pay dividends in cash, common stock or a combination thereof.

Each share of the 6% Preferred Stock is convertible, at the option of the holder, into cash up to the principal amount thereof anda number of shares of our common stock if any, in respectequal to the liquidation preference of $10,000 divided by the excess conversion value, based on anprice, which is initially $6.00 per share and is subject to specified anti-dilution adjustments. The initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an1,666.67 shares of our common stock for each share of the 6% Preferred Stock. The initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. The Convertible Notes bear interest at an annual rate of 4.50% payable on May 15 and November 15 of each year.

The Convertible Notes are unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes will rank senior in right of payment to any of our future junior subordinated indebtedness and will structurally rank junior to all existing and future indebtedness of our Guarantor Subsidiaries.

In connection with a tender offer completed in April 2011, the Company repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million reflectingrepresents a premium of $3520 percent relative to the 2012 common stock offering price of $5.00 per $1,000 principal amount.share. The tender offer resulted in6% Preferred Stock is not redeemable by us or the extinguishment of approximately 98%holders at any time. At any time on or after October 15, 2017, we may, at our option, cause all outstanding shares of the outstanding Convertible Notes. The tender offer was funded with6% Preferred Stock to be automatically converted into shares of our common stock at the net proceedsthen-applicable conversion price if the closing sale price of our common stock exceeds 130% of the 2019 Senior Notes. Subsequentthen-applicable conversion price for a specified period prior to conversion. If a holder


49


elects to convert shares of the tender offer, a total6% Preferred Stock upon the occurrence of $4.9 million aggregate principal amountcertain specified fundamental changes, we may be obligated to deliver an additional number of Convertible Notes remain outstanding. The remaining unamortized discount will be amortized through November 2012. 

shares above the applicable conversion rate to compensate the holder for lost option value.


Asset Dispositions

During 2011 and 2010,

As discussed previously, we completed a number of non-core asset dispositions in addition to other debt2012 and capital raising activities in connection with a broader effort2011 to supplement the funding of our capital expenditures program.programs. The following table summarizes the net cash realized from these dispositions during the years ended December 31, 20112012 and 2010:

  Year Ended December 31, 
Asset Description 2011  2010 
PVG common units1 $-  $338,245 
Oil and gas properties    39,368   25,567 
Other    100   1,192 
  $39,468  $365,004 

2011:

1 Of the total received during 2010, $199.1 million has been reported as cash received from financing activities and $139.1 million has been reported as cash received from investing activities.

  Year Ended December 31,
Asset Description 2012 2011
Oil and gas properties   $96,443
 $39,021
Tubular inventory and well materials 96
 347
Other   180
 100
  $96,719
 $39,468
Covenant Compliance

Our


The Revolver requires us to maintain certain financial covenants as follows:

·Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.5 to 1.0 reducing to 4.0 to 1.0 for periods ending after June 30, 2013. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.
·The current ratio, as of the last day of any quarter, may not be less than 1.0 to 1.0. The current ratio is generally defined as current assets to current liabilities. Current assets and current liabilities attributable to derivative instruments are excluded. In addition, current assets include the amount of any unused commitment under the Revolver.

Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.5 to 1.0 for periods through December 31, 2013, 4.25 to 1.0 for periods through June 30, 2014 and 4.0 to 1.0 for periods through maturity in 2017. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.
The current ratio, as of the last day of any quarter, may not be less than 1.0 to 1.0. The current ratio is generally defined as current assets to current liabilities. Current assets and current liabilities attributable to derivative instruments are excluded. In addition, current assets include the amount of any unused commitment under the Revolver.

As of December 31, 20112012 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these financial covenants.

The following table summarizes the actual results of our financial covenant compliance under the Revolver as of and for the period ended December 31, 2011:

2012:
  Required Actual
Description of Covenant Covenant Results
Total debt to EBITDAX < 4.5 to 1 3.12.4 to 1
Current ratio > 1.0 to 1 3.23.4 to 1

In the event that we would be in default of a covenant under the Revolver, we could request a waiver of the covenant from our bank group. Should the banks deny our request to waive the covenant requirement, the outstanding borrowings under the Revolver would become payable on demand and would be reclassified as a component of current liabilities on our Condensed Consolidated Balance Sheets.

In addition, to the financial covenants, the Revolver imposes limitations on dividends as well as limits theour ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries.

Future Capital Needs and Commitments

Subject to commodity prices and the availability of capital, we expect to expand our operations over the next several years by continuing to execute a program focused on development drilling and, to a lesser extent, exploration drilling, supplemented periodically with property and reserve acquisitions.


In 2012,2013, we anticipate making capital expenditures, excluding any additional acquisitions, of up to approximately $325$400 million. The capital expenditures have been andfor 2013 will continue to be funded primarily by operating cash flows and borrowings under the Revolver. We expect to supplement these sources of liquidity with proceeds from the sale of non-core assets or by accessing the capital markets. However, there can be no assurance that such actions would be successful. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, cash flows provided by operating activities and the availability of capital.

We

Based on expenditures to date and forecasted activity for the remainder of 2013, we expect to allocate capital expenditures as follows: Eagle Ford Shale (approximately 88 percent), Mid-Continent region (approximately four percent) and all other areas (approximately eight percent). This allocation includes approximately 85%86 percent for development and

50


exploratory drilling, eight percent for leasehold acquisition and six percent for seismic and other projects. We anticipate that we will allocate substantially all of our capital expenditures to Eagle Ford Shale projectsoil and approximately eight percent to projects, primarily non-operated development drilling, in the Mid-Continent region. The remainder will be allocated primarily to lease acquisitions, pipeline, gathering, seismic and facilities.

NGL projects.


Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2011,2012, the material off-balance sheet arrangements and transactions that we have entered into included operating lease arrangements, drilling commitments, hydraulic fracturing service commitments, firm transportation agreements and letters of credit, all of which are customary in our business. See Contractual Obligations summarized below for more details related to the value of off-balance sheet arrangements. We did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We are, therefore, not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2011:

  Payments Due by Period 
     Less than        More Than 
  Total  1 Year  1-3 Years  3-5 Years  5 Years 
Revolver $99,000  $-  $-  $99,000  $- 
Senior Notes due 20161  293,561   -   -   293,561   - 
Senior Notes due 2019  300,000   -   -   -   300,000 
Convertible Notes2  4,746   4,746   -   -   - 
Interest expense3  312,768   55,138   109,834   93,421   54,375 
Asset retirement obligations4  6,283   -   -   -   6,283 
Derivatives5  10,399   3,549   6,850   -   - 
Rental commitments6  12,188   3,120   4,020   3,085   1,963 
Firm transportation and drilling  89,441   34,075   15,001   9,408   30,957 
Total contractual obligations7 $1,128,386  $100,628  $135,705  $498,475  $393,578 
2012:
 Payments Due by Period
 Total 
Less than
1 Year
 1-3 Years 3-5 Years 
More Than
5 Years
Senior Notes due 2016 1
$300,000
 $—
 $—
 $300,000
 $—
Senior Notes due 2019 1
300,000
 —
 —
 —
 300,000
Interest expense 2
250,313
 52,875
 105,750
 59,063
 32,625
Asset retirement obligations 3
20,170
 —
 —
 —
 20,170
Derivatives 4
1,421
 —
 1,421
 —
 —
Rental commitments 5
8,997
 2,093
 3,423
 2,134
 1,347
Well drilling and completion22,117
 22,117
 —
 —
 —
Firm transportation 6
49,567
 7,366
 9,577
 7,762
 24,862
Total contractual obligations 7
$952,585
 $84,451
 $120,171
 $368,959
 $379,004

1  Upon its maturitytheir maturities in June 2016 and April 2019, the principal amountamounts of $300.0 million each will be due.

2  Upon its maturity in November 2012, the principal amount of $4.9 million will be due.

3  Represents estimated interest payments that will be due under the 2016 Senior Notes and the 2019 Senior Notes,Notes.

3  Represents the Convertible Notes andundiscounted balance payable in periods more than five years in the Revolver. Interest paymentsfuture for which $4.5 million has been recognized on the Revolver were calculated by assuming that the December 31, 2011 outstanding balance of $99.0 million will remain outstanding through the August 2016 maturity date. A constant rate of 2.0625% was assumed. Actual results will differ from these estimates and assumptions.

4  The undiscounted balance was approximately $36.7 millionConsolidated Balance Sheet as of December 31, 2011.

2012.

54  Represents estimated payments that we will make resulting from commodity derivatives.

65  Relates primarily to equipment and building leases.

6 Includes $26.9 million of undiscounted payments attributable to a firm transportation obligation for which $17.1 million has been recognized on the Consolidated Balance Sheet as of December 31, 2012.
7  Total contractual obligations do not include anticipated 20122013 capital expenditures.

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 plugging of abandoned wells. As of December 31, 2011,2012, we have recorded asset retirement obligations of $6.3$4.5 million attributable to these activities. 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 impact on our financial condition or results of operations. Nevertheless,

51


changes in existing environmental laws or regulations or the adoption of new environmental laws or regulations, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of AmericaGAAP 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 estimates requiring judgment of our management.

Oil and Gas 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, NGL and natural gas reserve quantities, including projecting the total quantities in place, future production rates and the amount and 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.

There are several factors which could change our estimates of oil and gas reserves. Significant rises or declines in commodity 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.

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 has found a sufficient quantity of reserves to justify its completion 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 that 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 December 31, 2011,2012, the costs attributable to unproved properties, net of accumulated amortization, were $120.3$60.7 million. Unproved properties whose acquisition costs are insignificant to total oil and gas properties are amortized as a component of exploration expense in the aggregate over the lesser of five years or the average remaining lease term. We assess unproved properties whose acquisition costs are relatively significant, if any, for impairment on a property-by-property basis. As exploration work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work is charged to exploration expense. The timing of any write-downs of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results.

Depreciation, Depletion and Amortization

We determine depreciation and depletion of oil and gas producing properties by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. We compute depreciation and amortization of other property and equipment using the straight-line balance method over the estimated useful life of each asset.


52


Derivative Activities

From time to time, we enter into derivative instruments to mitigate our exposure to natural gas and crude oil price volatility and interest rate fluctuations. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of collars, swaps and swaptions, among others. All derivative instruments are recognized in our Consolidated Financial Statements at fair value.value with the changes recorded currently in earnings. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices and rates. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.

Deferred Tax Valuation Allowance

The Company records

We record a valuation allowance to reduce itsour deferred tax assets to an amount that is more likely than not to be realized after consideration of future taxable income and reasonable tax planning strategies. In the event that the Companywe were to determine that itwe would not be able to realize all or a part of itsour deferred tax assets for which a valuation allowance had not been established, an adjustment to the deferred tax asset will be reflected in income in the period such determination is made. The most significant matter applicable to the realization of the Company’sour deferred tax assets is attributable to net operating losses in certain states. Estimates of future taxable income inherently reflect a significant degree of uncertainty. During the years ended December 31, 2012, 2011 and 2010, and 2009, the Companywe increased the valuation allowance for itsour deferred tax assets due primarily to itsour inability to project sufficient future taxable income in certain states.


Share-Based Compensation
In February 2012, we granted PBRSUs to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of specified market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.
Because the PBRSUs are payable solely in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period based on the fair value derived from a Monte Carlo model and recognized based on the period of time that has elapsed during each of the individual performance periods. The Monte Carlo model is a binomial valuation model that requires significant judgment with respect to certain assumptions, including volatility, dividends and other factors. Due primarily to the sensitivity of certain model assumptions, as well as the inherent variability of modeling market-based performance over future periods, our compensation expense with respect to the PBRSUs can be volatile.

New Accounting Standards

During 2011,2012, no new accounting standards were adopted or were pending adoption that would have a significant impact on our Consolidated Financial Statements andor the Notes to the Consolidated Financial Statements.


53



Item 7A        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 interest rate risk and commodity price risk.

Interest Rate Risk

All of our long-term debt instruments, with the exception of the Revolver, have fixed interest rates. Accordingly, changes in interest rates do not affect the amount of interest we pay on our fixed-rate debt instruments. However, changes in interest rates will affect the fair value of our long-term debt instruments. Our interest rate risk is attributable to our borrowings under the Revolver, which is subject to variable interest rates. As of December 31, 2011,2012, we had no borrowings of $99 million outstanding under the Revolver at an interest rate of 2.0625%. Assuming a constant borrowing level of $99 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in interest expense approximately $1 million on an annual basis.

Revolver.

Commodity Price Risk


We produce and sell natural gas, crude oil, NGLs and NGLs.natural gas. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars, swaps and swaptions) to seek to mitigate the price risks associated with fluctuations in natural gas, crude oil and NGLcommodity prices as they relate to a portion of our anticipated production. The derivative instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our derivative instruments are significantly affected by fluctuations in the prices of natural gas, crude oil and NGLs.

natural gas. We have not typically entered into derivative instruments with respect to NGLs, although we may do so in the future.

As of December 31, 2011,2012, we reported a commodity derivative asset of $19.0$16.5 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of December 31, 2011.

2012.

In 2011,2012, we reported net commodity derivative gains of $14.4$34.8 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil, NGL and NGLnatural gas prices. These fluctuations could be significant in a volatile pricing environment.  See Note 5 to the Condensed Consolidated Financial Statements for a further description of our price risk management activities.


54


The following table sets forth our commodity derivative positions as of December 31, 2011:

     Average          
     Volume Per  Weighted Average Price  Fair Value 
  Instrument  Day  Floor/Swap  Ceiling  Asset  Liability 
Natural Gas:    (in MMBtu)  ($/MMBtu)       
First quarter 2012  Collars   20,000  $6.00  $8.50  $5,394  $- 
First quarter 2012  Swaps   10,000  $5.10       1,880   - 
Second quarter 2012  Swaps   20,000  $5.31       3,935   - 
Third quarter 2012  Swaps   20,000  $5.31       3,706   - 
Fourth quarter 2012  Swaps   10,000  $5.10       1,424   - 
                         
Crude Oil:      (barrels)   ($/barrel)             
First quarter 2012  Collars   1,000  $90.00  $97.00   -   361 
Second quarter 2012  Collars   1,000  $90.00  $97.00   -   447 
Third quarter 2012  Collars   1,000  $90.00  $97.00   -   412 
Fourth quarter 2012  Collars   1,000  $90.00  $97.00   -   350 
First quarter 2013  Collars   1,000  $90.00  $100.00   -   146 
Second quarter 2013  Collars   1,000  $90.00  $100.00   -   80 
Third quarter 2013  Collars   1,000  $90.00  $100.00   -   14 
Fourth quarter 2013  Collars   1,000  $90.00  $100.00   29   - 
First quarter 2012  Swaps   1,400  $101.16       261   - 
Second quarter 2012  Swaps   1,000  $100.61       106   - 
Third quarter 2012  Swaps   500  $100.00       52   - 
Fourth quarter 2012  Swaps   500  $100.00       88   - 
First quarter 2013  Swaption   1,100  $100.00       -   1,049 
Second quarter 2013  Swaption   1,000  $100.00       -   849 
Third quarter 2013  Swaption   900  $100.00       -   674 
Fourth quarter 2013  Swaption   750  $100.00       -   497 
Premiums - Deferred                  -   3,570 
Settlements to be paid in subsequent period                  162   - 

2012:

   Average      
   Volume Per Weighted Average Price Fair Value
 Instrument Day Floor/Swap Ceiling Asset Liability
Crude Oil:  (barrels) ($/barrel)    
First quarter 2013Collars 1,000
 $90.00
 $100.00
 $119
 $—
Second quarter 2013Collars 1,000
 $90.00
 $100.00
 124
 —
Third quarter 2013Collars 1,000
 $90.00
 $100.00
 123
 —
Fourth quarter 2013Collars 1,000
 $90.00
 $100.00
 151
 —
First quarter 2013Swaps 2,250
 $103.51
   2,244
 —
Second quarter 2013Swaps 2,250
 $103.51
   2,040
 —
Third quarter 2013Swaps 1,500
 $102.77
   1,248
 —
Fourth quarter 2013Swaps 1,500
 $102.77
   1,296
 —
First quarter 2014Swaps 2,000
 $100.44
  
 1,360
 —
Second quarter 2014Swaps 2,000
 $100.44
  
 1,446
 —
Third quarter 2014Swaps 1,500
 $100.20
  
 1,128
 —
Fourth quarter 2014Swaps 1,500
 $100.20
  
 1,179
 —
First quarter 2014Swaption 812
 $100.00
  
 —
 356
Second quarter 2014Swaption 812
 $100.00
  
 —
 355
Third quarter 2014Swaption 812
 $100.00
  
 —
 355
Fourth quarter 2014Swaption 812
 $100.00
  
 —
 355
            
Natural Gas:  (in MMBtu)
 ($/MMBtu)  
  
First quarter 2013Collars 10,000
 $3.50
 4.30
 187
 —
Second quarter 2013Collars 10,000
 $3.50
 4.30
 219
 —
Third quarter 2013Collars 10,000
 $3.50
 4.30
 165
 —
Fourth quarter 2013Collars 15,000
 $3.67
 4.37
 216
 —
First quarter 2014Collars 5,000
 $4.00
 4.50
 68
 —
First quarter 2013Swaps 10,000
 $4.01
  
 587
 —
Second quarter 2013Swaps 10,000
 $4.01
  
 504
 —
Third quarter 2013Swaps 10,000
 $4.01
  
 391
 —
Fourth quarter 2013Swaps 5,000
 $4.04
  
 121
 —
Settlements to be received in subsequent period   
  
  
 1,557
 —

The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil prices, natural gas prices, crude oil prices and production volumes remain constant at anticipated levels.  The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.

  Change of $1.00 per MMBtu of Natural Gas 
  or $10.00 per Barrel of Crude Oil 
  ($ in millions) 
    Increase    Decrease 
Effect on the fair value of natural gas derivatives $(6.3) $6.5 
Effect on the fair value of crude oil derivatives $(12.1) $10.7 
         
Effect on 2012 operating income, excluding natural gas derivatives $24.0  $(24.1)
Effect on 2012 operating income, excluding crude oil derivatives $24.8  $(24.7) 

Item 8      Financial Statements and Supplemental Data

 
Change of $10.00 per Barrel of Crude Oil
or $1.00 per MMBtu of Natural Gas
($ in millions)
 Increase
 Decrease
Effect on the fair value of crude oil derivatives$(19.2) $15.3
Effect on the fair value of natural gas derivatives$(5.8) $6.3
    
Effect on 2013 operating income, excluding crude oil derivatives$22.6
 $(22.6)
Effect on 2013 operating income, excluding natural gas derivatives$9.8
 $(9.8)

55


Item 8      Financial Statements and Supplemental Data

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 Page
Report of Independent Registered Public Accounting Firm51
57
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 2010 and 2009201052
58
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010 and 2009 53
59
Consolidated Balance Sheets as of December 31, 20112012 and 2010201154
60
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 2010 and 2009201055
61
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2012, 2011 2010 and 2009201056
62
Notes to the Consolidated Financial Statements: 
1. Nature of Operations57
63
2. Summary of Significant Accounting Policies57
63
3. Acquisitions and Divestitures59
65
4. Accounts Receivable and Major Customers60
67
5. Derivative Instruments60
67
6. Property and Equipment63
70
7. Asset Retirement Obligations63
70
8. Long-Term Debt63
70
9. Income Taxes66
72
10. Additional Balance Sheet Detail68
73
11. Fair Value Measurements68
74
12. Commitments and Contingencies71
76
13. Shareholders’ Equity72
77
14. Share-Based Compensation72
78
15. Restructuring Activities75
82
16. Impairments76
82
17. Interest Expense76
83
18. Earnings per Share77
84
19. Discontinued Operations77
84
Supplemental Quarterly Financial Information (unaudited)79
85
Supplemental Information on Oil and Gas Producing Activities (unaudited)80
86



56


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

Penn Virginia Corporation:

We have audited the accompanying consolidated balance sheets of Penn Virginia Corporation and subsidiaries as of December 31, 20112012 and 2010,2011, and the related consolidated statements of operations, comprehensive income, shareholders’shareholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2011.2012. We also have audited Penn Virginia Corporation’sCorporation's internal control over financial reporting as of December 31, 2011,2012, based on criteria established inInternal Control –- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Penn Virginia Corporation’sCorporation's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’sManagement's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’sCompany's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’scompany's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’scompany's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’scompany's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia Corporation and subsidiaries as of December 31, 20112012 and 2010,2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2011,2012, in conformity with U.S. generally accepted accounting principles. Also in our opinion, Penn Virginia Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011,2012, based on criteria established inInternal Control –- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.




/s/ KPMG LLP

Houston, Texas
February 27, 2012

25, 2013


57


PENN VIRGINIACORPORATIONAND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

  Year Ended December 31, 
  2011  2010  2009 
Revenues            
Natural gas $137,070  $171,141  $169,666 
Crude oil  119,582   53,532   43,258 
Natural gas liquids (NGLs)  43,394   26,663   15,735 
Gain on sales of property and equipment  3,570   648   2,372 
Other  2,389   2,454   4,175 
Total revenues  306,005   254,438   235,206 
Operating expenses            
Lease operating  36,988   35,757   44,392 
Gathering, processing and transportation  15,157   14,180   11,307 
Production and ad valorem taxes  13,690   13,917   15,044 
General and administrative  48,328   58,383   49,690 
Exploration  78,943   49,641   57,754 
Depreciation, depletion and amortization  162,534   134,700   154,351 
Impairments  104,688   45,959   106,415 
Other  1,096   709   1,599 
Total operating expenses  461,424   353,246   440,552 
             
Operating loss  (155,419)  (98,808)  (205,346)
Other income (expense)            
Interest expense  (56,216)  (53,679)  (44,231)
Loss on extinguishment of debt  (25,421)  -   - 
Derivatives  15,651   41,906   31,568 
Other  335   2,403   1,259 
Loss from continuing operations before income taxes  (221,070)  (108,178)  (216,750)
Income tax benefit  88,155   42,851   85,894 
Loss from continuing operations  (132,915)  (65,327)  (130,856)
Income from discontinued operations, net of tax  -   33,448   53,488 
Gain on sale of discontinued operations, net of tax  -   51,546   - 
Net income (loss)  (132,915)  19,667   (77,368)
Less net income attributable to noncontrolling interests in discontinued operations  -   (28,090)  (37,275)
Loss attributable to Penn Virginia Corporation $(132,915) $(8,423) $(114,643)
             
Loss per share attributable to Penn Virginia Corporation - Basic:            
Continuing operations $(2.90) $(1.44) $(2.99)
Discontinued operations  -   0.12   0.37 
Gain on sale of discontinued operations  -   1.13   - 
Net loss $(2.90) $(0.19) $(2.62)
             
Loss per share attributable to Penn Virginia Corporation - Diluted:        
Continuing operations $(2.90) $(1.44) $(2.99)
Discontinued operations  -   0.12   0.37 
Gain on sale of discontinued operations  -   1.13   - 
Net loss $(2.90) $(0.19) $(2.62)
             
Weighted average shares outstanding, basic  45,784   45,553   43,811 
Weighted average shares outstanding, diluted  45,784   45,553   43,811 

 Year Ended December 31,
 2012 2011 2010
Revenues 
  
  
Crude oil$229,572
 $119,582
 $53,532
Natural gas liquids (NGLs)31,051
 43,394
 26,663
Natural gas49,861
 137,070
 171,141
Gain on sales of property and equipment, net4,282
 3,570
 648
Other2,383
 2,389
 2,454
Total revenues317,149
 306,005
 254,438
Operating expenses 
  
  
Lease operating31,266
 36,988
 35,757
Gathering, processing and transportation14,196
 15,157
 14,180
Production and ad valorem taxes10,634
 13,690
 13,917
General and administrative45,900
 48,328
 58,383
Exploration34,092
 78,943
 49,641
Depreciation, depletion and amortization206,336
 162,534
 134,700
Impairments104,484
 104,688
 45,959
Loss on firm transportation commitment17,332
 —
 —
Other—
 1,096
 709
Total operating expenses464,240
 461,424
 353,246
Operating loss(147,091) (155,419) (98,808)
Other income (expense) 
  
  
Interest expense(59,339) (56,216) (53,679)
Loss on extinguishment of debt(3,164) (25,421) —
Derivatives36,187
 15,651
 41,906
Other116
 335
 2,403
Loss from continuing operations before income taxes(173,291) (221,070) (108,178)
Income tax benefit68,702
 88,155
 42,851
Loss from continuing operations(104,589) (132,915) (65,327)
Income from discontinued operations, net of tax—
 —
 33,448
Gain on sale of discontinued operations, net of tax—
 —
 51,546
Net income (loss)(104,589) (132,915) 19,667
Less net income attributable to noncontrolling interests in discontinued operations—
 —
 (28,090)
Loss attributable to Penn Virginia Corporation(104,589) (132,915) (8,423)
Preferred stock dividends(1,687) —
 —
Loss attributable to common shareholders$(106,276) $(132,915) $(8,423)
Loss per share - Basic: 
  
  
Continuing operations$(2.22) $(2.90) $(1.44)
Discontinued operations—
 —
 0.12
Gain on sale of discontinued operations—
 —
 1.13
Net loss$(2.22) $(2.90) $(0.19)
Loss per share - Diluted: 
  
  
Continuing operations$(2.22) $(2.90) $(1.44)
Discontinued operations—
 —
 0.12
Gain on sale of discontinued operations—
 —
 1.13
Net loss$(2.22) $(2.90) $(0.19)
      
Weighted average shares outstanding - basic47,919
 45,784
 45,553
Weighted average shares outstanding - diluted47,919
 45,784
 45,553

See accompanying notes to consolidated financial statements.


58


PENN VIRGINIACORPORATIONAND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

  Year Ended December 31, 
  2011  2010  2009 
Net income (loss) $(132,915) $19,667  $(77,368)
Other comprehensive income (loss):            
Unrealized gains (losses), net of tax of $62 in 2009  -   -   115 
Hedging reclassification adjustments, net of tax of $1,986 in 2009  -   582   3,689 
Total change in hedging derivative financial instruments  -   582   3,804 
Change in pension and postretirement obligations, net of tax of ($79) in 2011, $188 in 2010 and $75 in 2009  (146)  348   140 
   (146)  930   3,944 
Comprehensive income (loss)  (133,061)  20,597   (73,424)
Less amounts attributable to noncontrolling interests:            
Net income  -   (28,090)  (37,275)
Other comprehensive income  -   (582)  (1,048)
Comprehensive loss attributable to Penn Virginia $(133,061) $(8,075) $(111,747)

 Year Ended December 31,
 2012 2011 2010
Net income (loss)$(104,589) $(132,915) $19,667
Other comprehensive income (loss): 
  
  
Hedging reclassification adjustments—
 —
 582
Total change in hedging derivative financial instruments—
 —
 582
Change in pension and postretirement obligations, net of tax of $54 in 2012, ($79) in 2011 and $188 in 2010102
 (146) 348
 102
 (146) 930
Comprehensive income (loss)(104,487) (133,061) 20,597
Less amounts attributable to noncontrolling interests: 
  
  
Net income—
 —
 (28,090)
Other comprehensive income—
 —
 (582)
Comprehensive loss attributable to Penn Virginia$(104,487) $(133,061) $(8,075)
See accompanying notes to consolidated financial statements.


53
59


PENN VIRGINIACORPORATIONAND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

       
  As of December 31, 
  2011  2010 
Assets        
Current assets        
Cash and cash equivalents $7,512  $120,911 
Accounts receivable, net of allowance for doubtful accounts  72,432   72,378 
Derivative assets  18,987   16,818 
Income taxes receivable  31,465   - 
Other current assets  14,950   4,233 
Total current assets  145,346   214,340 
Property and equipment, net (successful efforts method)  1,777,575   1,705,584 
Derivative assets  -   3,889 
Other assets  20,132   20,787 
Total assets $1,943,053  $1,944,600 
         
Liabilities and Shareholders’ Equity        
Current liabilities        
Accounts payable and accrued liabilities $94,504  $99,661 
Derivative liabilities  3,549   388 
Deferred income taxes  3,808   4,318 
Income taxes payable  -   2,627 
Current portion of long-term debt  4,746   - 
Total current liabilities  106,607   106,994 
Other liabilities  15,887   19,958 
Derivative liabilities  6,850   - 
Deferred income taxes  274,839   330,836 
Long-term debt  692,561   506,536 
         
Commitments and contingencies (Note 12)        
         
Shareholders’ equity:        
Preferred stock of $100 par value – 100,000 shares authorized; none issued  -   - 
Common stock of $0.01 par value – 128,000,000 shares authorized; shares issued of 45,714,191 and 45,556,854 as of December 31, 2011 and December 31, 2010, respectively  270   267 
Paid-in capital  690,131   680,981 
Retained earnings  157,242   300,473 
Deferred compensation obligation  3,620   2,743 
Accumulated other comprehensive loss  (1,084)  (938)
Treasury stock – 223,886 and 125,357 shares of common stock, at cost, as of        
December 31, 2011 and December 31, 2010, respectively  (3,870)  (3,250)
Total shareholders’ equity  846,309   980,276 
Total liabilities and shareholders’ equity $1,943,053  $1,944,600 

 As of December 31,
 2012 2011
Assets 
  
Current assets 
  
Cash and cash equivalents$17,650
 $7,512
Accounts receivable, net of allowance for doubtful accounts62,978
 72,432
Derivative assets11,292
 18,987
Income taxes receivable—
 31,465
Other current assets4,595
 14,950
Total current assets96,515
 145,346
Property and equipment, net (successful efforts method)1,723,359
 1,777,575
Derivative assets5,181
 —
Other assets17,934
 20,132
Total assets$1,842,989
 $1,943,053
    
Liabilities and Shareholders’ Equity 
  
Current liabilities 
  
Accounts payable and accrued liabilities$111,655
 $94,504
Derivative liabilities—
 3,549
Deferred income taxes370
 3,808
Current portion of long-term debt—
 4,746
Total current liabilities112,025
 106,607
Other liabilities28,901
 15,887
Derivative liabilities1,421
 6,850
Deferred income taxes210,767
 274,839
Long-term debt594,759
 692,561
    
Commitments and contingencies (Note 12)

 

    
Shareholders’ equity: 
  
Preferred stock of $100 par value – 100,000 shares authorized; shares issued of 11,500 as of December 31, 2012 and none as of December 31, 20111,150
 —
Common stock of $0.01 par value – 128,000,000 shares authorized; shares issued of 55,117,346 and 45,714,191 as of December 31, 2012 and December 31, 2011, respectively364
 270
Paid-in capital849,046
 690,131
Retained earnings45,790
 157,242
Deferred compensation obligation3,111
 3,620
Accumulated other comprehensive loss(982) (1,084)
Treasury stock – 218,320 and 223,886 shares of common stock, at cost, as of December 31, 2012 and December 31, 2011, respectively(3,363) (3,870)
Total shareholders’ equity895,116
 846,309
Total liabilities and shareholders’ equity$1,842,989
 $1,943,053

See accompanying notes to consolidated financial statements.


60


PENN VIRGINIACORPORATIONAND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

  Year Ended December 31, 
  2011  2010  2009 
Cash flows from operating activities            
Net loss $(132,915) $19,667  $(77,368)
Adjustments to reconcile net loss to net cash provided by operating activities from continuing operations:            
Income from discontinued operations  -   (36,832)  (64,130)
Gain on sale of discontinued operations  -   (86,662)  - 
Non-cash portion of loss on extinguishment of debt  22,456   -   - 
Depreciation, depletion and amortization  162,534   134,700   154,351 
Impairments  104,688   45,959   106,415 
Derivative contracts:            
Net gains  (15,651)  (41,906)  (28,033)
Cash settlements  27,380   32,818   58,147 
Deferred income taxes (benefit)  (85,501)  42,528   (83,222)
Loss (gain) on sales of property and equipment, net  (2,474)  61   (1,910)
Dry hole and unproved leasehold expense  60,940   36,275   33,278 
Non-cash interest expense  6,807   11,984   10,202 
Share-based compensation  7,430   7,811   9,127 
Other, net  275   (209)  683 
Changes in operating assets and liabilities:            
Accounts receivable, net  (1,792)  (19,964)  33,266 
Accounts payable and accrued expenses  (6,552)  10,877   (20,066)
Other assets and liabilities  (2,884)  (77,268)  (13,007)
Net cash provided by operating activities from continuing operations  144,741   79,839   117,733 
             
Cash flows from investing activities            
Capital expenditures - property and equipment  (445,623)  (405,994)  (205,676)
Proceeds from the sale of PVG units, net (Note 3)  -   139,120   - 
Proceeds from sales of property and equipment, net  39,368   25,567   15,083 
Other, net  100   1,192   11 
Net cash used in investing activities for continuing operations  (406,155)  (240,115)  (190,582)
             
Cash flows from financing activities            
Dividends paid  (10,316)  (10,271)  (9,836)
Proceeds from revolving credit facility borrowings  114,000   -   87,000 
Repayment of revolving credit facility borrowings  (15,000)  -   (419,000)
Proceeds from issuance of senior notes, net  300,000   -   291,009 
Repurchase of Convertible Notes  (232,963)  -   - 
Repayments of short-term borrowings  -   -   (7,542)
Debt issuance costs paid  (8,854)  -   (14,959)
Proceeds from the issuance of common stock, net  -  -   64,835 
Proceeds from the sale of PVG units, net (Note 3)  -   199,125   118,080 
Distributions received from discontinued operations  -   11,218   42,279 
Other, net  1,148   2,098   - 
Net cash provided by financing activities from continuing operations  148,015   202,170   151,866 
             
Cash flows from discontinued operations            
Net cash provided by operating activities  -   77,759   158,214 
Net cash used in investing activities  -   (18,112)  (80,506)
Net cash used in provided by financing activities  -   (59,647)  (77,708)
Net cash provided by discontinued operations  -   -   - 
Net increase (decrease) in cash and cash equivalents  (113,399)  41,894   79,017 
Cash and cash equivalents - beginning of period  120,911   79,017   - 
Cash and cash equivalents - end of period $7,512  $120,911  $79,017 
             
Supplemental disclosures:            
Cash paid for:            
Interest (net of amounts capitalized) $44,589  $43,531  $34,640 
Income taxes (net of refunds received) $210  $28,184  $9,443 

 Year Ended December 31,
 2012 2011 2010
Cash flows from operating activities 
  
  
Net income (loss)$(104,589) $(132,915) $19,667
Adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations: 
  
  
Income from discontinued operations—
 —
 (36,832)
Gain on sale of discontinued operations—
 —
 (86,662)
Non-cash portion of loss on extinguishment of debt3,144
 22,456
 —
Loss on firm transportation commitment17,332
 —
 —
Depreciation, depletion and amortization206,336
 162,534
 134,700
Impairments104,484
 104,688
 45,959
Derivative contracts: 
  
  
Net gains(36,187) (15,651) (41,906)
Cash settlements29,723
 27,380
 32,818
Deferred income taxes (benefit)(68,676) (85,501) 42,528
(Gain) loss on sales of assets, net(4,282) (2,474) 61
Non-cash exploration expense32,634
 60,940
 36,275
Non-cash interest expense4,062
 6,807
 11,984
Share-based compensation (equity-classified)6,347
 7,430
 7,811
Other, net1,004
 275
 (209)
Changes in operating assets and liabilities: 
  
  
Accounts receivable, net9,907
 (1,792) (19,964)
Income taxes receivable and payable, net31,439
 (2,815) 2,627
Accounts payable and accrued expenses9,710
 (6,552) 10,877
Other assets and liabilities(930) (69) (79,895)
Net cash provided by operating activities from continuing operations241,458
 144,741
 79,839
Cash flows from investing activities 
  
  
Capital expenditures - property and equipment(370,907) (445,623) (405,994)
Proceeds from the sale of PVG units, net (Note 3)—
 —
 139,120
Proceeds from sales of assets, net96,719
 39,368
 25,567
Other, net180
 100
 1,192
Net cash used in investing activities for continuing operations(274,008) (406,155) (240,115)
Cash flows from financing activities 
  
  
Proceeds from the issuance of preferred stock, net110,337
 —
 —
Proceeds from the issuance of common stock, net43,474
 —
 —
Proceeds from the issuance of senior notes—
 300,000
 —
Retirement of convertible notes(4,915) (232,963) —
Proceeds from revolving credit facility borrowings211,000
 114,000
 —
Repayment of revolving credit facility borrowings(310,000) (15,000) —
Debt issuance costs paid(2,032) (8,854) —
Dividends paid(5,176) (10,316) (10,271)
Proceeds from the sale of PVG units, net (Note 3)—
 —
 199,125
Distributions received from discontinued operations—
 —
 11,218
Other, net—
 1,148
 2,098
Net cash provided by financing activities from continuing operations42,688
 148,015
 202,170
Cash flows from discontinued operations 
  
  
Net cash provided by operating activities—
 —
 77,759
Net cash used in investing activities—
 —
 (18,112)
Net cash used in provided by financing activities—
 —
 (59,647)
Net cash provided by discontinued operations—
 —
 —
Net increase (decrease) in cash and cash equivalents10,138
 (113,399) 41,894
Cash and cash equivalents - beginning of period7,512
 120,911
 79,017
Cash and cash equivalents - end of period$17,650
 $7,512
 $120,911
Supplemental disclosures: 
  
  
Cash paid for: 
  
  
Interest (net of amounts capitalized)$54,808
 $44,589
 $43,531
Income taxes (net of refunds received)$(32,603) $210
 $28,184
See accompanying notes to consolidated financial statements.


61


PENN VIRGINIACORPORATIONAND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in thousands)

                 Accumulated     Total       
  Common           Deferred  Other     Penn Virginia     Total 
  Shares  Common  Paid-in  Retained  Compensation  Comprehensive  Treasury  Shareholders'  Noncontrolling  Shareholders' 
  Outstanding  Stock  Capital  Earnings  Obligation  Loss  Stock  Equity  Interests  Equity 
                                         
Balance as of December 31, 2008  41,871  $230  $485,967  $443,646  $2,237  $(4,182) $(2,683) $925,215  $297,227  $1,222,442 
                                         
Net income (loss)  -   -   -   (114,643)  -   -   -   (114,643)  37,275   (77,368)
Change in hedging derivative financial instruments  -   -   -   -   -   2,756   -   2,756   1,048   3,804 
Change in pension and postretirement obligations  -   -   -   -   -   140   -   140   -   140 
Dividends paid ($0.225 per share)  -   -   -   (9,836)  -   -   -   (9,836)  -   (9,836)
Issuance of common stock  3,500   35   64,800   -   -   -   -   64,835   -   64,835 
Common stock issued as compensation  3   -   60   -   -   -   -   60   -   60 
Share-based compensation  -   -   9,062   -   -   -   -   9,062   -   9,062 
Deferred compensation  12   -   11   -   186   -   (258)  (61)  -   (61)
Exercise of stock options  -   -   367   -   -   -   (386)  (19)  -   (19)
Sale of subsidiary units, net of tax (Notes 3, 13 and 19)  -   -   32,739   -   -   -   -   32,739   67,713   100,452 
Unit-based compensation of subsidiaries  -   -   (833)  -   -   -   -   (833)  4,819   3,986 
Distributions to noncontrolling interest holders  -   -   -   -   -   -   -   -   (78,171)  (78,171)
Other  -   -   (1,327)  -   -   -   -   (1,327)  -   (1,327)
Balance as of December 31, 2009  45,386   265   590,846   319,167   2,423   (1,286)  (3,327)  908,088   329,911   1,237,999 
                                         
Net income (loss)  -   -   -   (8,423)  -   -   -   (8,423)  28,090   19,667 
Change in hedging derivative financial instruments  -   -   -   -   -   -   -   -   582   582 
Change in pension and postretirement obligations  -   -   -   -   -   348   -   348   -   348 
Dividends paid ($0.225 per share)  -   -   -   (10,271)  -   -   -   (10,271)  -   (10,271)
Common stock issued as compensation  5   -   92   -   -   -   -   92   -   92 
Share-based compensation  (2)  -   7,157   -   -   -   -   7,157   -   7,157 
Deferred compensation  8   -   562   -   320   -   (309)  573   -   573 
Exercise of stock options  136   1   1,712   -   -   -   386   2,099   -   2,099 
Restricted stock unit vesting  24   1   201   -   -   -   -   202   -   202 
Sale of subsidiary units, net of tax (Notes 3, 13 and 19)  -   -   82,915   -   -   -   -   82,915   70,188   153,103 
Deconsolidation of subsidiaries (Notes 3, 13 and 19)  -   -   -   -   -   -   -   -   (382,325)  (382,325)
Unit-based compensation of subsidiaries  -   -   (1,267)  -   -   -   -   (1,267)  3,120   1,853 
Distributions to noncontrolling interest holders  -   -   -   -   -   -   -   -   (49,566)  (49,566)
Other  -   -   (1,237)  -   -   -   -   (1,237)  -   (1,237)
Balance as of December 31, 2010  45,557   267   680,981   300,473   2,743   (938)  (3,250)  980,276   -   980,276 
                                         
Net loss  -   -   -   (132,915)  -   -   -   (132,915)  -   (132,915)
Change in pension and postretirement obligations  -   -   -   -   -   (146)  -   (146)  -   (146)
Dividends paid ($0.225 per share)  -   -   -   (10,316)  -   -   -   (10,316)  -   (10,316)
Common stock issued as compensation  11   -   93   -   -   -   -   93   -   93 
Share-based compensation  -   -   6,460   -   -   -   -   6,460   -   6,460 
Deferred compensation  -   1   876   -   877   -   (620)  1,134   -   1,134 
Exercise of stock options  95   1   1,225   -   -   -   -   1,226   -   1,226 
Restricted stock unit vesting  51   1   270   -   -   -   -   271   -   271 
Other  -   -   226   -   -   -   -   226   -   226 
Balance as of December 31, 2011  45,714  $270  $690,131  $157,242  $3,620  $(1,084) $(3,870) $846,309  $-  $846,309 

 
Common
Shares
Outstanding
Preferred Stock
Common
Stock
Paid-in
Capital
Retained
Earnings
Deferred
Compensation
Obligation
Accumulated
Other
Comprehensive
Loss
Treasury
Stock
Total
Penn Virginia
Shareholders'
Equity
Noncontrolling
Interests
Total
Shareholders'
Equity
Balance as of December 31, 200945,386
$—
$265
$590,846
$319,167
$2,423
$(1,286)$(3,327)$908,088
$329,911
$1,237,999
Net income (loss)—
—
—
—
(8,423)—
—
—
(8,423)28,090
19,667
Change in hedging derivative financial instruments—
—
—
—
—
—
—
—
—
582
582
Change in pension and postretirement obligations—
—
—
—
—
—
348
—
348
—
348
Dividends paid ($0.225 per share)—
—
—
—
(10,271)—
—
—
(10,271)—
(10,271)
Common stock issued as compensation5
—
—
92
—
—
—
—
92
—
92
Share-based compensation(2)—
—
7,157
—
—
—
—
7,157
—
7,157
Deferred compensation8
—
—
562
—
320
—
(309)573
—
573
Exercise of stock options136
—
1
1,712
—
—
—
386
2,099
—
2,099
Restricted stock unit vesting24
—
1
201
—
—
—
—
202
—
202
Sale of subsidiary units, net of tax (Notes 3, 13 and 19)—
—
—
82,915
—
—
—
—
82,915
70,188
153,103
Deconsolidation of subsidiaries—
—
—
—
—
—
—
—
—
(382,325)(382,325)
Unit-based compensation of subsidiaries—
—
—
(1,267)—
—
—
—
(1,267)3,120
1,853
Distributions to noncontrolling interest holders—
—
—
—
—
—
—
—
—
(49,566)(49,566)
Other—
—
—
(1,237)—
—
—
—
(1,237)—
(1,237)
Balance as of December 31, 201045,557
—
267
680,981
300,473
2,743
(938)(3,250)980,276
—
980,276
Net loss—
—
—
—
(132,915)—
—
—
(132,915)—
(132,915)
Change in pension and postretirement obligations—
—
—
—
—
—
(146)—
(146)—
(146)
Dividends paid ($0.225 per share)—
—
—
—
(10,316)—
—
—
(10,316)—
(10,316)
Common stock issued as compensation11
—
—
93
—
—
—
—
93
—
93
Share-based compensation—
—
—
6,460
—
—
—
—
6,460
—
6,460
Deferred compensation—
—
1
876
—
877
—
(620)1,134
—
1,134
Exercise of stock options95
—
1
1,225
—
—
—
—
1,226
—
1,226
Restricted stock unit vesting51
—
1
270
—
—
—
—
271
—
271
Other—
—
—
226
—
—
—
—
226
—
226
Balance as of December 31, 201145,714
—
270
690,131
157,242
3,620
(1,084)(3,870)846,309
—
846,309
Net loss—
—
—
—
(104,589)—
—
—
(104,589)—
(104,589)
Change in pension and postretirement obligations—
—
—
—
—
—
102
—
102
—
102
Dividends paid ($0.1125 per common share)—
—
—
—
(5,176)—
—
—
(5,176)—
(5,176)
Dividends declared ($146.67 per preferred share)—
—
—
—
(1,687)—
—
—
(1,687)—
(1,687)
Issuance of preferred stock—
1,150
—
109,312
—
—
—
—
110,462
—
110,462
Issuance of common stock9,200
—
92
43,258
—
—
—
—
43,350
—
43,350
Common stock issued as compensation80
—
1
424
—
—
—
—
425
—
425
Share-based compensation—
—
—
5,765
—
—
—
—
5,765
—
5,765
Deferred compensation35
—
—
157
—
(509)—
507
155
—
155
Restricted stock unit vesting88
—
1
(1)—
—
—
—
—
—
—
Balance as of December 31, 201255,117
$1,150
$364
$849,046
$45,790
$3,111
$(982)$(3,363)$895,116
$—
$895,116
See accompanying notes to consolidated financial statements.


56
62


PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(in thousands, except per share amounts)

1.       Nature of Operations


1. Nature of Operations
Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged primarily engaged in the exploration, development and production of oil, natural gas liquids ("NGLs") and oilnatural gas in various domestic onshore regions of the United States including Texas, Appalachia, the Mid-Continent, Mississippi and Mississippi.

2.      Summary of Significant Accounting Policies

to a lesser extent, the Marcellus Shale in Appalachia.


2.Summary of Significant Accounting Policies
Principles of Consolidation

Our Consolidated Financial Statements include the accounts of Penn Virginia and all of its subsidiaries. Intercompany balances and transactions have been eliminated.

Use of Estimates

Preparation of our Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these notes. Actual results could differ from those estimates.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Derivative Instruments

From time to time, we utilize derivative instruments to mitigate our financial exposure to commodity price and interest rates and natural gas and crude oil pricerate volatility. The derivative instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of collars, swaps and swaptions. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.

All derivative instruments are recognized in theour Consolidated Financial Statements at fair value.value. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. Our derivative instruments are not formally designated as hedges. We recognize changes in fair value in earnings currently as a component of the Derivatives caption on theour Consolidated Statements of Operations. We have experienced and could continue to experience significant changes in the amount of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts, which fluctuate with changes in crude oil and natural gas and crude oil 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 has found a sufficient quantity of reserves to justify its completion 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

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pursuing access to necessary facilities and access to such permits and approvals and believe that they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis.


Depreciation, depletion and amortization (“DD&A”) of proved producing properties is computed using the units-of-production method. Oil and naturalNatural gas liquids (“NGLs”) areis converted to a gasliquids equivalent on the basis that one barrel of liquids is equivalent to six thousand cubic feet of natural gas.gas is equivalent to one barrel of liquids. Historically, we have adjusted our depletion rate throughout the year as new data becomes available and in the fourth quarter based on theour year-end reserve report.

Impairment of Long-Lived and Other Assets

We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. If the carrying value of the asset is determined to be impaired, we reduce the asset to its fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and could include estimates of future production, commodity prices based on published forward commodity price curves as of the date of the estimate, operating and development costs, intent to develop properties and a risk-adjusted discount rate.

57

We review oil and gas properties for impairment periodically 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. Performing the impairment evaluations requires use of judgments and estimates since the results are dependent on future events. Such events include estimates of proved and possibleunproved reserves, future commodity prices and the timing of future production and capital expenditures, and intent to develop properties, among others. We have recognized impairments of our properties in 2012, 2011 2010 and 2009,2010, as described in Note 16. We cannot predict whether impairment charges will be required in the future.

The costs of unproved leaseholds, including associated interest costs for the period activities were in progress to bring projects to their intended use, are capitalized pending the results of exploration efforts. Unproved properties whose acquisition costs are insignificant to total oil and gas properties are amortized in the aggregate over the lesser of five years or the average remaining lease term and the amortization is charged to exploration expense. We assess unproved properties whose acquisition costs are relatively significant, if any, for impairment on a property-by-property basis. As exploration work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work is charged to exploration expense. The timing of any write-downs of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results.

Other Property and Equipment

Other property and equipment consists primarily of gathering systems and related support equipment. Property and equipment are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which increase the productive lives of existing assets. Maintenance and repair costs are charged to expense as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized.

We compute depreciation and amortization of property and equipment using the straight-line balance method over the estimated useful life of each asset as follows:

 Useful Life
Gathering systems15-20 years
Other property and equipment3-20 years

Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and natural gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in DD&A expense on our Consolidated Statements of Operations.


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Income Taxes

We recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed periodicallyat each reporting period and is dependent upon the generation of future taxable income and our ability to utilize tax credits and operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent they arise, as a component of interest expense and penalties as a component of income tax expense.

Due to the geographical scope of our operations, we are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain.


Revenue Recognition

We record revenues associated with sales of natural gas, crude oil, condensateNGLs and NGLsnatural gas when title passes to the customer. We recognize natural gas sales revenues from properties in which we have an interest with other producers on the basis of our net revenue interest (“entitlement” method of accounting). Natural gas imbalances occur when we sell more or less than our entitled ownership percentage of natural gas production. We treat any amount received in excess of our share as a liability. If we take less than we are entitled to take, we record the under-delivery 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, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

Share-Based Compensation

We have

Our stock compensation plans that allowpermit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to be granted to keyour employees and officers and nonqualified stock options and deferred common stock units to be granted to directors. We measure the cost of employee services received in exchange for an award of equityequity-classified instruments based on the grant-date fair value of the award.

Compensation cost associated with the liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period.

Recent Accounting Standards

During 2011,2012, no new accounting standards were adopted or were pending adoption that would have a significant impact on our Consolidated Financial Statements andor the Notes to the Consolidated Financial Statements.

Reclassifications

Certain amounts for the 20102011 and 20092010 periods have been reclassified to conform to the current year presentation.

Subsequent Events

Management has evaluated all activities of the Company, through the date upon which theour Consolidated Financial Statements were issued, and concluded that no subsequent events have occurred that would require recognition in theour Consolidated Financial Statements or disclosure in the Notes to the Consolidated Financial Statements.

3.    Acquisitions and Divestitures



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3.Acquisitions and Divestitures
In the following paragraphs, all references to crude oil and natural gas reserves and acreage acquired or sold are unaudited. The factors we used to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risk-adjusted basis, comparable market data, geographic location, quality of resources and potential marketability.

Property Acquisitions

Eagle Ford and Marcellus Shale Property Acquisitions

During

In December 2011, we entered into an agreement with an industry partner to jointly explore a 13,500 acre area of mutual interest (“AMI”) in Lavaca County, Texas. Under the terms of the agreement, we were required to commence drilling on six wells by September 1, 2012, as well as carry our partner for its working interest share of the costs of the first three wells, to earn our entire interest in the acreage. We fulfilled this requirement during the third quarter of 2012 and, as a result, earned an approximately 60 percent interest in this acreage.

In December 2012, this industry partner in the Lavaca County Eagle Ford Shale acreage elected to not participate in the last 17 initial unit wells to be drilled on this acreage. Upon the drilling of each of the initial unit wells, our industry partner will have no participatory rights in any subsequent wells drilled in such unit. We are presently seeking a partner to acquire a 40 percent working interest in this acreage in which our industry partner has elected not to participate.

In addition to the acreage earned in Lavaca County, as discussed above, we acquired approximately 7,3004,100 net acres in the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas in 2012 for approximately $10 million increasing our net Eagle Ford Shale acresacreage position to approximately 32,500 net acres. During 2011 and 2010, we acquired acreage in Gonzales County Texas for approximately $27 million. The acreage acquired in these transactions is in close proximity to our initial 2010 Eagle Ford Shale acquisitions which was approximately 6,800 net acres for $31.1 million.$27 million and $31 million, respectively. We are the operator of all of the combinedour Gonzales County acreage with an average working interest of approximately 81%.

84 percent.


Divestitures
Oil and Gas Properties
In July 2012, we sold substantially all of our legacy natural gas assets in West Virginia, Kentucky and Virginia for approximately $100 million, excluding transaction costs and before customary purchase and sale adjustments. Through December 31, 2012, we received proceeds of $95.7 million, net of transaction costs and customary closing adjustments, and recognized a gain of $3.3 million in connection with the transaction. The assets sold included vertical and horizontal coalbed methane and vertical conventional properties, a gathering system and royalty interests. These assets had net production of approximately 20 million cubic feet of natural gas equivalent per day (3,333 barrels of oil equivalent) and estimated proved reserves of approximately 106 billion cubic feet of natural gas equivalent (17.7 million barrels of oil equivalent), of which 96 percent was proved developed and almost 100 percent was natural gas. An impairment charge of $28.6 million was recognized in the second quarter of 2012 with respect to these assets.

In December 2011, we entered into an agreement with a major oil and gas company to jointly exploresold approximately 13,000 gross acres of the Eagle Ford Shale in Lavaca County, Texas. The agreement establishes an area of mutual interest near our existing acreage in Gonzales County. Depending upon the future participation of other companies, our minimum working interest will be approximately 50%. Under the terms of the agreement, we must drill six wells by September 1, 2012 to earn our interest in the acreage. We will carry our counterparty on its working interest in the first three wells.

During 2010, we acquired a total of approximately 27,0002,700 net undeveloped acres in the Marcellus Shale playButler and Armstrong Counties in Pennsylvania for approximately $69 million.

Divestitures

Oil and Gas Properties

proceeds of $8.1 million, net of transaction costs. We recognized a gain of $3.3 million in connection with this transaction.


In August 2011, we sold a substantial portion of our Arkoma Basin assets for approximately $30$30 million, excluding transaction costs and subject to customary purchase and sale adjustments. Upon the final settlement, we recognized an insignificant loss in connection with the transaction, following an impairment of approximately $71$71 million in the second quarter of 2011. The sale which was effective July 1, 2011, included primarily natural gas and coal bed methane properties comprising approximately 73,000 net acres in Oklahoma and Texas with proved reserves of approximately 37.1 billion cubic feet of natural gas equivalent as well as related inventory and equipment.

In December 2011, we sold approximately 2,700 net undeveloped acres in Butler and Armstrong counties in Pennsylvania for proceeds of $8.1 million, net of transaction costs. We recognized a gain of $3.3 million in connection with this transaction. During 2011, we also received net proceeds of $1.2 million from the sale of various oil and gas assets in New York, Oklahoma, Pennsylvania and Texas. 

equivalent.


In January 2010, we completed the sale of all of our oil and gas propertiesassets in the Gulf Coast region (southern Texas and Louisiana) for cash proceeds of $23.4$23.4 million, net of transaction costs and certain purchase and sale adjustments, and the receipt of certain oil and gas properties located in the Gwinville field in northern Mississippi valued at $8.2 million. $8.2 million.

During 2012, 2011 and 2010, we also received net proceeds of $2.0$1.6 million, $1.2 million and $2.0 million, respectively, from the sale of various non-core oil and gas properties located in North Dakota, West Virginiavarious states both within and Oklahoma.

outside of our present operating regions.


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Penn Virginia GP Holdings, L.P. (“PVG”) Unit Offerings

In Septembera series of transactions that occurred during 2009 and 2010, we sold 10 million common units of PVG (“PVG Common Units”) owned by us for proceeds of $118.1 million, net of offering costs, resulting in a reduction of our limited partner interest in PVG from 77.0% to 51.4%. In April 2010, we completed the sale of an additional 11.25 million PVG Common Units for proceeds of $199.1 million, net of offering costs, which further reduced our limited partner interest to 22.6%. On a combined basis, these transactions resulted in a $137.9 million increase to noncontrolling interests as well as a $115.7 million increase to additional paid-in capital, net of income tax effects.22.6 percent. Because we maintained a controlling financial interest in PVG, the proceeds received from these transactions were reported as cash flows from financing activities on our Consolidated Statements of Cash Flows.

In June 2010, we completed the sale of our remaining PVG Common Units for $139.1$139.1 million, net of offering costs. Immediately prior to the closing, of the June offering, we contributed 100% of theour membership interests in PVG’s general partner to PVG, thereby relinquishing control of PVG. As a result of this divestiture, we recognized a gain of $51.5$51.5 million, net of income tax effects of $35.1$35.1 million, which is reported in the “Gain on sale of discontinued operations, net of tax” caption on our Consolidated Statements of Operations. Because we no longer held any interests in PVG, the proceeds received from this transaction were reported as cash flows from investing activities on our Consolidated Statements of Cash Flows and we deconsolidated PVG from our Consolidated Financial Statements. We have reported PVG’s results of operations and cash flows as discontinued operations for the 2010 and 2009 periods.period. Additional information with respect to discontinued operations is provided in Note 19.


4.       Accounts Receivable and Major Customers

The following table summarizes our accounts receivable by type as of the dates presented:

  As of December 31, 
  2011  2010 
Customers $49,763  $44,783 
Joint interest partners  22,755   23,526 
Other  1,695   4,442 
   74,213   72,751 
Less: Allowance for doubtful accounts  (1,781)  (373)
  $72,432  $72,378 

 As of December 31,
 2012 2011
Customers$43,967
 $49,763
Joint interest partners16,154
 22,755
Other4,523
 1,695
 64,644
 74,213
Less: Allowance for doubtful accounts(1,666) (1,781)
 $62,978
 $72,432
For the yearsyear ended December 31, 2011 and 2010, five2012, four customers accounted for $173.1$182.0 million and $140.2 million,, or approximately 58% and 56%, respectively,59% of our total consolidated product revenues. The revenues generated from these customers during 2012 were $60.1 million, $46.7 million, $41.5 million and $33.8 million or 19%, 15%, 14% and 11% of the consolidated total, respectively. As of December 31, 2012, $21.6 million, or approximately 34% of our consolidated accounts receivable, including joint interest billings, related to these customers. For the year ended December 31, 2011 and 2010, $31.6, three customers accounted for $120.4 million and $31.1 million,, or approximately 44%40% of our consolidated product revenues. The revenues generated from these customers during 2011 were $51.7 million, $34.6 million and 43%$34.1 million, respectively,or approximately 17%, 12% and 11% of the consolidated total, respectively. As of December 31, 2011, $17.2 million, or approximately 24% of our consolidated accounts receivable, including joint interest billings, related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

5.    Derivative Instruments


5.Derivative Instruments
We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas and crude oil price volatility as well as the volatility in interest rates attributable to our debt instruments. The derivative instruments, which are placed with financial institutions that we believe are acceptable credit risks, generally take the form of collars, swaps and swaptions. Our derivative instruments are not formally designated as hedges.

Commodity Derivatives

We utilize collars, swaps and swaptions to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.

The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap 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 swaption contract gives our counterparties the option to enter into a fixed price swap with us at a future date. If the forward commodity price for the term of the swaption is higher than or equal to the swaption strike price on the exercise date, the counterparty will exercise its option to enter into a fixed price swap at the

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swaption strike price for the term of the swaption, at which point the contract functions as a fixed price swap. If the forward commodity price for the term of the swaption is lower than the swaption strike price on the exercise date, the option expires and no fixed price swap is in effect.


We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.


The following table sets forth our commodity derivative positions as of December 31, 2011:

     Average          
     Volume Per  Weighted Average Price  Fair Value 
  Instrument  Day  Floor/Swap  Ceiling  Asset  Liability 
Natural Gas:    (in MMBtu)  ($/MMBtu)       
First quarter 2012  Collars   20,000  $6.00  $8.50   5,394   - 
First quarter 2012  Swaps   10,000  $5.10       1,880   - 
Second quarter 2012  Swaps   20,000  $5.31       3,935   - 
Third quarter 2012  Swaps   20,000  $5.31       3,706   - 
Fourth quarter 2012  Swaps   10,000  $5.10       1,424   - 
                         
Crude Oil:      (barrels)   ($/barrel)         
First quarter 2012  Collars   1,000  $90.00  $97.00   -   361 
Second quarter 2012  Collars   1,000  $90.00  $97.00   -   447 
Third quarter 2012  Collars   1,000  $90.00  $97.00   -   412 
Fourth quarter 2012  Collars   1,000  $90.00  $97.00   -   350 
First quarter 2013  Collars   1,000  $90.00  $100.00   -   146 
Second quarter 2013  Collars   1,000  $90.00  $100.00   -   80 
Third quarter 2013  Collars   1,000  $90.00  $100.00   -   14 
Fourth quarter 2013  Collars   1,000  $90.00  $100.00   29   - 
First quarter 2012  Swaps   1,400  $101.16       261   - 
Second quarter 2012  Swaps   1,000  $100.61       106   - 
Third quarter 2012  Swaps   500  $100.00       52   - 
Fourth quarter 2012  Swaps   500  $100.00       88   - 
First quarter 2013  Swaption   1,100  $100.00       -   1,049 
Second quarter 2013  Swaption   1,000  $100.00       -   849 
Third quarter 2013  Swaption   900  $100.00       -   674 
Fourth quarter 2013  Swaption   750  $100.00       -   497 
Premiums – Deferred1                  -   3,570 
Settlements to be paid in subsequent period                  162   - 

2012:

1  Premiums are attributable to the crude oil collars for 2013 and are included in noncurrent derivative liabilities.

   Average      
   Volume Per Weighted Average Price Fair Value
 Instrument Day Floor/Swap Ceiling Asset Liability
Crude Oil:  (barrels) ($/barrel)    
First quarter 2013Collars 1,000
 $90.00
 $100.00
 $119
 $—
Second quarter 2013Collars 1,000
 $90.00
 $100.00
 124
 —
Third quarter 2013Collars 1,000
 $90.00
 $100.00
 123
 —
Fourth quarter 2013Collars 1,000
 $90.00
 $100.00
 151
 —
First quarter 2013Swaps 2,250
 $103.51
  
 2,244
 —
Second quarter 2013Swaps 2,250
 $103.51
   2,040
 —
Third quarter 2013Swaps 1,500
 $102.77
   1,248
 —
Fourth quarter 2013Swaps 1,500
 $102.77
   1,296
 —
First quarter 2014Swaps 2,000
 $100.44
   1,360
 —
Second quarter 2014Swaps 2,000
 $100.44
   1,446
 —
Third quarter 2014Swaps 1,500
 $100.20
   1,128
 —
Fourth quarter 2014Swaps 1,500
 $100.20
   1,179
 —
First quarter 2014Swaption 812
 $100.00
   —
 356
Second quarter 2014Swaption 812
 $100.00
   —
 355
Third quarter 2014Swaption 812
 $100.00
   —
 355
Fourth quarter 2014Swaption 812
 $100.00
   —
 355
Natural Gas:  (in MMBtu)
 ($/MMBtu)  
  
First quarter 2013Collars 10,000
 $3.50
 $4.30
 187
 —
Second quarter 2013Collars 10,000
 $3.50
 $4.30
 219
 —
Third quarter 2013Collars 10,000
 $3.50
 $4.30
 165
 —
Fourth quarter 2013Collars 15,000
 $3.67
 $4.37
 216
 —
First quarter 2014Collars 5,000
 $4.00
 $4.50
 68
 —
First quarter 2013Swaps 10,000
 $4.01
  
 587
 —
Second quarter 2013Swaps 10,000
 $4.01
  
 504
 —
Third quarter 2013Swaps 10,000
 $4.01
  
 391
 —
Fourth quarter 2013Swaps 5,000
 $4.04
  
 121
 —
Settlements to be received in subsequent period   
  
  
 1,557
 —

Interest Rate Swaps

In February 2012, we entered into an interest rate swap agreement to establish variable interest rates on approximately one-third of the outstanding obligation under our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”). In May 2012, we terminated this agreement and received $1.2 million in cash proceeds.

In December 2009, we entered into an interest rate swap agreement to establish variable rates on approximately one-third of the face amount of the outstanding obligation under the our 10.375% Senior Notes due 2016 (“2016(the “2016 Senior Notes”). DuringIn August 2011, we terminated this agreement and received $2.9$2.9 million in cash proceeds.

The following table sets forth the terms and positions



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As of ourDecember 31, 2012, we had no interest rate swaps as of the periods presented:

  Notional  Swap Interest Rates 1  Fair Value as of December 31, 
Term Amount  Pay  Receive  2011  2010 
 Through June 2013 $100,000   LIBOR + 8.175%   10.375% $-  $2,590 

derivative instruments outstanding.

1 References to LIBOR represent the 3-month rate.

Financial Statement Impact of Derivatives

The impact of our derivatives activities on income is included in the Derivatives caption on our Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Impact by contract type:            
Commodity contracts $14,422  $36,693  $33,218 
Interest rate contracts  1,229   5,213   (1,650)
  $15,651  $41,906  $31,568 
Realized and unrealized impact:            
Cash received (paid) for:            
Commodity contract settlements $23,562  $33,480  $59,908 
Interest rate contract settlements  3,818   (662)  (1,761)
   27,380   32,818   58,147 
Unrealized gains (losses) attributable to:            
Commodity contracts  (9,140)  3,213   (26,690)
Interest rate contracts  (2,589)  5,875   111 
   (11,729)  9,088   (26,579)
  $15,651  $41,906  $31,568 

 Year Ended December 31,
 2012 2011 2010
Impact by contract type: 
  
  
Commodity contracts$34,781
 $14,422
 $36,693
Interest rate contracts1,406
 1,229
 5,213
 $36,187
 $15,651
 $41,906
Realized and unrealized impact: 
  
  
Cash received (paid) for: 
  
  
Commodity contract settlements$28,317
 $23,562
 $33,480
Interest rate contract settlements1,406
 3,818
 (662)
 29,723
 27,380
 32,818
Unrealized gains (losses) attributable to: 
  
  
Commodity contracts6,464
 (9,140) 3,213
Interest rate contracts—
 (2,589) 5,875
 6,464
 (11,729) 9,088
 $36,187
 $15,651
 $41,906
The effects of derivative gains (losses) and cash settlements of our commodity and interest rate derivatives are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations. These items are recorded in the “DerivativeDerivative contracts: Net gains”gains and “DerivativeDerivative contracts: Cash settlements”settlements captions on our Consolidated Statements of Cash Flows.

The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our Consolidated Balance Sheets as of the dates presented:

    Fair Values as of
    December 31, 2011 December 31, 2010 
    Derivative  Derivative Derivative Derivative 
Type Balance Sheet Location Assets  Liabilities Assets Liabilities 
                
 Commodity contracts Derivative assets/liabilities - current $18,987 $3,549 $15,075 $ 388 
 Interest rate contracts Derivative assets/liabilities - current  -  -  1,743  - 
     18,987  3,549  16,818  388 
                
 Commodity contracts Derivative assets/liabilities - noncurrent  -  6,850  3,042  - 
 Interest rate contracts Derivative assets/liabilities - noncurrent  -  -  847  - 
     -  6,850  3,889  - 
    $ 18,987 $10,399 $ 20,707 $ 388 

    Fair Values as of
    December 31, 2012 December 31, 2011
    Derivative Derivative Derivative Derivative
Type Balance Sheet Location Assets Liabilities Assets Liabilities
Commodity contracts Derivative assets/liabilities - current $11,292
 $—
 $18,987
 $3,549
Interest rate contracts Derivative assets/liabilities - current —
 —
 —
 —
    11,292
 —
 18,987
 3,549
           
Commodity contracts Derivative assets/liabilities - noncurrent 5,181
 1,421
 —
 6,850
Interest rate contracts Derivative assets/liabilities - noncurrent —
 —
 —
 —
    5,181
 1,421
 —
 6,850
    $16,473
 $1,421
 $18,987
 $10,399

As of December 31, 2011,2012, we reported a commodity derivative asset of $19.0 million.$16.5 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid norhave not received any cash collateral from our counterparties with respect to our derivative asset positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.



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6.Property and Equipment

The following table summarizes our property and equipment as of the dates presented:

  As of December 31, 
  2011  2010 
Oil and gas properties:        
Proved $2,239,186  $2,021,729 
Unproved  120,288   171,303 
Total oil and gas properties  2,359,474   2,193,032 
Other property and equipment  143,285   133,754 
Total property and equipment  2,502,759   2,326,786 
Accumulated depreciation, depletion and amortization  (725,184)  (621,202)
  $1,777,575  $1,705,584 

 As of December 31,
 2012 2011
Oil and gas properties: 
  
Proved$2,277,811
 $2,239,186
Unproved60,746
 120,288
Total oil and gas properties2,338,557
 2,359,474
Other property and equipment93,648
 143,285
Total property and equipment2,432,205
 2,502,759
Accumulated depreciation, depletion and amortization(708,846) (725,184)
 $1,723,359
 $1,777,575
The following table describes the changes in capitalized exploratory drilling costs that are pending the determination of proved reserves for the periods presented:

  2011  2010  2009 
  Number     Number     Number    
  of Wells  Cost  of Wells  Cost  of Wells  Cost 
Balance at beginning of year  1  $6,180   -  $-   1  $2,482 
Additions pending determination of proved reserves  -   -   1   6,180   -   - 
Reclassification to wells, equipment and facilities based on the determination of proved reserves  -   -   -   -   (1)  (2,482)
Charged to exploration expense  (1)  (6,180)  -   -   -   - 
Balance at end of year  -  $-   1  $6,180   -  $- 

 2012 2011 2010
 
Number
of Wells
 Cost 
Number
of Wells
 Cost 
Number
of Wells
 Cost
Balance at beginning of year—
 $—
 1
 $6,180
 —
 $—
Additions pending determination of proved reserves1
 4,435
 —
 —
 1
 6,180
Reclassification to wells, equipment and facilities based on the determination of proved reserves—
 —
 —
 —
 —
 —
Charged to exploration expense—
 —
 (1) (6,180) —
 —
Balance at end of year1
 $4,435
 —
 $—
 1
 $6,180

7.Asset Retirement Obligations

The following table reconciles our AROs foras of the periodsdates presented, which are included in the Other liabilities caption on our Consolidated Balance Sheets:

  As of December 31, 
  2011  2010 
Balance at beginning of year $7,364  $6,835 
Liabilities incurred  214   126 
Liabilities settled  (183)  (41)
Sale of properties  (1,611)  - 
Accretion expense  499   444 
Balance at end of year $6,283  $7,364 

 As of December 31,
 2012 2011
Balance at beginning of year$6,283
 $7,364
Liabilities incurred57
 214
Liabilities settled(236) (183)
Sale of properties(1,976) (1,611)
Accretion expense385
 499
Balance at end of year$4,513
 $6,283

8.Long-Term Debt

The following table summarizes our long-term debt as of the dates presented:

  As of December 31, 
  2011  2010 
Revolving credit facility $99,000  $- 
Senior notes due 2016, net of discount (principal amount of $300,000)  293,561   292,487 
Senior notes due 2019  300,000   - 
Convertible notes due 2012, net of discount (principal amount of $4,915 and $230,000)  4,746   214,049 
   697,307   506,536 
Less: Current portion of long-term debt  (4,746)  - 
  $692,561  $506,536 

 As of December 31,
 2012 2011
Revolving credit facility$—
 $99,000
Senior notes due 2016, net of discount (principal amount of $300,000)294,759
 293,561
Senior notes due 2019300,000
 300,000
Convertible notes due 2012, net of discount (principal amount of $4,915)—
 4,746
 594,759
 697,307
Less: Current portion of long-term debt—
 (4,746)
 $594,759
 $692,561

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Revolving Credit Facility

In August 2011,September 2012, we entered into a new five-yearthe Revolver, which replaced our previous revolving credit facility (the “Revolver”) maturingthat was entered into in August 2016.2011. The Revolver provides for a $300$300 million revolving commitment includingand an accordion feature that allows us to increase the commitment by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20$20 million sublimit for the issuance of letters of credit. The Revolver hasis governed by a borrowing base calculation, and the availability under the Revolver may not exceed the lesser of $380 million.the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver is $300 million and will be redetermined semi-annually. There is an accordion feature that allows us to increasebased on a semi-annual review of our total proved oil, NGL and natural gas reserves starting in the commitment up to the lowerspring of the borrowing base or $600 million upon receiving additional commitments from one or more lenders.2013. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We havehad letters of credit of $1.4$2.1 million outstanding as of December 31, 2011.2012. As of December 31, 2011,2012, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and such letters of credit, was $199.6 million.

$297.9 million.


In September 2012, we capitalized $2.0 million of debt issuance costs in connection with the Revolver, which will be amortized as a component of interest expense over the five year term. Capitalized debt issuance costs attributable to the previous revolving credit facility of $3.2 million were expensed as a loss on the extinguishment of debt.
Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (the “Adjusted(“Adjusted LIBOR”), plus an applicable margin ranging(ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity.
Commitment fees are charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined bydepending on our ratio of outstanding borrowings to the available Revolver capacity. As of December 31, 2011, the effective interest rate on the borrowings under the Revolver was 2.0625%.

The Revolver includes both current ratio and leverage ratio financial covenants. The current ratio is defined in the Revolver to include, among other things, adjustments for undrawn availability and may not be less than 1.0 to 1.0. The ratio of total net debt to EBITDAX, a non-GAAP financial measure defined in the Revolver, may not exceed 4.5 to 1.0 reducing to 4.0 to 1.0 for periods ending after June 30, 2013.


The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries (“Guarantor(the “Guarantor Subsidiaries”). The obligations under the Revolver are secured by a first priority lien on substantially all of our proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.


The guarantees provided by the parent company and the Guarantor Subsidiaries under the Revolver as well as those provided for the senior indebtedness described below are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company and its non-guarantor subsidiaries have no material independent assets or operations. There are no significant restrictions on the ability of the parent company or any of the Guarantor Subsidiaries to obtain funds through dividends or other means, including advances and intercompany notes, among others.


The Revolver includes both current ratio and leverage ratio financial covenants. The current ratio is defined in the Revolver to include, among other things, adjustments for undrawn availability and may not be less than 1.0 to 1.0. The ratio of total net debt to EBITDAX, a non-GAAP financial measure defined in the Revolver, may not exceed 4.5 to 1.0 through December 31, 2013, 4.25 to 1.0 through June 30, 2014 and then 4.0 to 1.0 through maturity.

2016 Senior Notes

The 2016 Senior Notes were originally sold at 97% of par in June 2009, equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. Beginning in June 2013, we may redeem all or part of the 2016 Senior Notes at a redemption price beginningstarting at 105.188% of the principal amount and reducing to 100% in June 2015 and thereafter. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2019 Senior Notes

The 2019 Senior Notes, due 2019 (“2019 Senior Notes”), which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable on April 15 and October 15 of each year. Beginning in April 2015, we may redeem all or part of the 2019 Senior Notes at a redemption price beginningstarting at 103.625% of the principal amount and reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured

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indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Convertible Notes

The 4.50% Convertible Senior Subordinated Notes due 2012 (“Convertible Notes”) bear interest at an annual rate of 4.50% payable on May 15 and November 15 of each year. The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. The Convertible Notes are unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes rank senior in right of payment to any of our future junior subordinated indebtedness and structurally rank junior to all existing and future indebtedness of our Guarantor Subsidiaries.

The Convertible Notes are represented by a liability component which is included in long-term debt, net of discount, and an equity component representing the convertible feature which is included in additional paid-in capital in shareholders’ equity. The effective interest rate on the liability component of the Convertible Notes for all periods presented was 8.5%.

In connection with a tender offer completed in April 2011, the Company repurchased $225.1$225.1 million aggregate principal amount of the 4.50%Convertible Senior Subordinated Notes due 2012 (the "Convertible Notes") for $233.0$233.0 million, representing a premium of $35$35 per $1,000$1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded with the net proceeds of the 2019 Senior Notes.

As a result of the tender offer, we recognized a pre-tax loss on extinguishment of debt of $25.9$25.9 million during the three months ended June 30, 2011, of which $24.2$24.2 million was charged to earnings and the remaining $1.7$1.7 million was charged directly to shareholders’ equity. The loss charged to earnings was determined as follows:

Cash paid to repurchase principal:    
Allocated to liability component $231,331 
Allocated to equity component  1,632 
  $232,963 
     
Carrying value of liability component tendered:    
Principal amount of Convertible Notes tendered $225,085 
Pro rata share of original issue discount  (13,429)
  $211,656 
     
Loss on extinguishment of debt:    
Excess of liability component over carrying value $19,675 
Write-off of pro rata share of debt issuance costs  2,147 
Non-cash portion of loss on extinguishment  21,822 
Transaction costs and fees paid  2,416 
Pre-tax loss on extinguishment $24,238 

The following table summarizes the carrying amount of these components as of the dates presented:

  As of December 31, 
  2011  2010 
Principal $4,915  $230,000 
Unamortized discount  (169)  (15,951)
Net carrying amount of liability component $4,746  $214,049 
         
Carrying amount of equity component $35,201  $36,850 

The following table summarizes the amounts recognized as components of interest expense attributable to theremaining Convertible Notes for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Contractual interest expense $3,119  $10,350  $10,350 
Accretion on original issue discount  2,353   7,371   6,782 
Amortization of debt issuance costs  403   1,242   1,387 
  $5,875  $18,963  $18,519 

In connection with the original sale of the Convertible Notes, we entered into convertible note hedge transactions (“Note Hedges”) with respect to shares of our common stock with affiliates of certain of the underwriters of the Convertible Notes (collectively, the “Option Counterparties”). The Note Hedges cover, subject to anti-dilution adjustments, the net shares of our common stock that would be deliverable to converting noteholderswere retired upon their maturity in the event of a conversion of the Convertible Notes.

We also entered into separate warrant transactions (“Warrants”), whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 3,982,680 shares of our common stock at an exercise price of $74.25 per share.

In August 2011, we entered into a partial unwind transaction with one of the Option Counterparties in which we received cash proceeds of less than $0.1 million. The transaction resulted in a reduction of the number of options outstanding attributable to the Note Hedges as well as a reduction in the number of outstanding Warrants. The effect of this transaction resulted in an increase to additional paid-in capital.

November 2012.

Debt Maturities

The following table sets forth the aggregate maturities of the principal amounts, excluding discounts, of our long-term debt for the next five years and thereafter:

Year Amounts 
2012 $4,746 
2013  - 
2014  - 
2015  - 
2016  392,561 
Thereafter  300,000 
Total $697,307 

Year Amounts
2013 $—
2014 —
2015 —
2016 300,000
2017 —
Thereafter 300,000
Total $600,000

9.Income Taxes


The following table summarizes our provision for income taxes from continuing operations for the periods presented: 

  Year Ended December 31, 
  2011  2010  2009 
Current income taxes (benefit)            
Federal $1,279  $(109,240) $(2,158)
State  (3,933)  876   (514)
   (2,654)  (108,364)  (2,672)
             
Deferred income taxes (benefit)            
Federal  (80,529)  67,999   (68,488)
State  (4,972)  (2,486)  (14,734)
   (85,501)  65,513   (83,222)
  $(88,155) $(42,851) $(85,894)

 Year Ended December 31,
 2012 2011 2010
Current income taxes (benefit) 
  
  
Federal$—
 $1,279
 $(109,240)
State(26) (3,933) 876
 (26) (2,654) (108,364)
Deferred income taxes (benefit) 
  
  
Federal(60,676) (80,529) 67,999
State(8,000) (4,972) (2,486)
 (68,676) (85,501) 65,513
 $(68,702) $(88,155) $(42,851)
The following table summarizes the intra-period allocation of income taxes for the periods presented: 

  Year Ended December 31, 
  2011  2010  2009 
Continuing operations $(88,155) $(42,851) $(85,894)
Discontinued operations  -   3,384   10,642 
Gain on sale of discontinued operations  -   35,116   - 
  $(88,155) $(4,351) $(75,252)

 Year Ended December 31,
 2012 2011 2010
Continuing operations$(68,702) $(88,155) $(42,851)
Discontinued operations—
 —
 3,384
Gain on sale of discontinued operations—
 —
 35,116
 $(68,702) $(88,155) $(4,351)

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The following table reconciles the difference between the income taxes computed by applying the statutory tax rate to income from continuing operations before income taxes and our reported income tax expense for the periods presented: 

  Year Ended December 31, 
  2011  2010  2009 
 Computed at federal statutory rate $(77,374)  (35.0)% $(37,862)  (35.0)% $(75,863)  (35.0)%
 State income taxes, net of federal income tax benefit  (4,825)  (2.2)%  (1,927)  (1.8)%  (8,020)  (3.7)%
 Other, net  (5,956)  (2.7)%  (3,062)  (2.8)%  (2,011)  (0.9)%
  $(88,155)  (39.9)% $(42,851)  (39.6)% $(85,894)  (39.6)%

 Year Ended December 31,
 2012 2011 2010
Computed at federal statutory rate$(60,652) (35.0)% $(77,374) (35.0)% $(37,862) (35.0)%
State income taxes, net of federal income tax benefit(8,026) (4.6)% (4,825) (2.2)% (1,927) (1.8)%
Other, net(24) — % (5,956) (2.7)% (3,062) (2.8)%
 $(68,702) (39.6)% $(88,155) (39.9)% $(42,851) (39.6)%
The following table summarizes the principal components of our net deferred income tax liability as of the dates presented:

  As of December 31, 
  2011  2010 
Deferred tax liabilities:        
Property and equipment $429,568  $352,431 
Fair value of derivative instruments  3,006   2,215 
Convertible notes  60   6,143 
Total deferred tax liabilities  432,634   360,789 
         
Deferred tax assets:        
Pension and postretirement benefits  3,046   3,951 
Share-based compensation  8,838   7,602 
Net operating loss carryforwards  150,953   27,915 
Other  10,642   5,230 
   173,479   44,698 
Less:  Valuation allowance  (19,492)  (19,063)
Total deferred tax assets  153,987   25,635 
Net deferred tax liability $278,647  $335,154 

As shown in the table above, the Company has recognized $154.0 million of deferred tax assets as of December 31, 2011. Included in this total is a federal net operating loss carryforward of approximately $124 million, which expires in 2031, and state net operating loss carryforwards of approximately $27 million, which expire between 2024 and 2031.

 As of December 31,
 2012 2011
Deferred tax liabilities: 
  
Property and equipment$311,002
 $429,568
Fair value of derivative instruments5,268
 3,006
Convertible notes—
 60
Total deferred tax liabilities316,270
 432,634
    
Deferred tax assets: 
  
Pension and postretirement benefits2,864
 3,046
Share-based compensation10,760
 8,838
Net operating loss ("NOL") carryforwards102,407
 150,953
Other15,788
 10,642
 131,819
 173,479
Less:  Valuation allowance(26,686) (19,492)
Total deferred tax assets105,133
 153,987
Net deferred tax liability$211,137
 $278,647
As of December 31, 20112012, we had federal NOL carryforwards of approximately $203.8 million, which expire starting in 2031, and 2010,state NOL carryforwards of approximately $47.8 million, which expire between 2024 and 2032. As of December 31, 2012 and 2011, valuation allowances of $19.5$41.0 million and $19.1$30.0 million, respectively, had been recorded for deferred tax assets associated with state net operating lossNOL carryforwards that were not more-likely-than-not to be realized.

During 2011, the Company generated a net operating loss for federal income tax purposes. The net operating loss is expected to be carried back and applied against the taxable income of prior years.

As of December 31, 2011, the Companywe classified $31.2$31.2 million of deferred tax assets as a current income tax receivable attributable to the federal net operating lossNOL expected to be utilized in 2012.

The Company hasutilized. In 2012, we received a federal tax refund of approximately $32 million from the carryback of the 2011 federal NOL, and the remainder of the NOL is available for carryforward.

We have no liability for unrecognized tax benefits as of December 31, 20112012 and 2010.2011. There were no interest and penalty charges recognized during the years ended December 31, 2012 , 2011 and 2010. For the year ended December 31, 2009 we recognized $2.1 million in interest and penalties. Tax years from 20082009 forward remain open for examination by the Internal Revenue Service and various state jurisdictions.



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67
10.Additional Balance Sheet Detail

The following table summarizes components of selected balance sheet accounts as of the dates presented:

  As of December 31, 
  2011  2010 
Other current assets:        
Tubular inventory and well materials $14,251  $3,600 
Prepaid expenses  699   633 
  $14,950  $4,233 
Other assets:        
Debt issuance costs $16,993  $14,300 
Long-term investments - Rabbi Trust1  3,088   6,440 
Other  51   47 
  $20,132  $20,787 
Accounts payable and accrued liabilities:        
Trade accounts payable $30,186  $33,831 
Drilling costs  30,948   31,770 
Royalties  15,235   9,308 
Production and franchise taxes  3,495   6,012 
Compensation2, 3  5,186   9,631 
Interest  5,964   2,977 
Other  3,490   6,132 
  $94,504  $99,661 
Other liabilities:        
Asset retirement obligations $6,283  $7,364 
Defined benefit pension obligations2  1,763   1,766 
Postretirement health care benefit obligations2  3,022   2,976 
Deferred compensation1  3,172   6,952 
Other  1,647   900 
  $15,887  $19,958 

 As of December 31,
 2012 2011
Other current assets: 
  
Tubular inventory and well materials$4,033
 $14,251
Prepaid expenses562
 699
 $4,595
 $14,950
Other assets: 
  
Debt issuance costs$13,186
 $16,993
Assets of supplemental employee retirement plan (“SERP”) 1
3,237
 3,088
Other1,511
 51
 $17,934
 $20,132
Accounts payable and accrued liabilities: 
  
Trade accounts payable$37,835
 $30,186
Drilling costs37,703
 30,948
Royalties14,390
 15,235
Production and franchise taxes2,874
 3,495
Compensation - related 2, 3
6,853
 5,186
Interest5,828
 5,964
Preferred stock dividends1,687
 —
Other4,485
 3,490
 $111,655
 $94,504
Other liabilities: 
  
Firm transportation obligation$14,333
 $—
Asset retirement obligations4,513
 6,283
Defined benefit pension obligations 2
1,821
 1,763
Postretirement health care benefit obligations 2
2,634
 3,022
Deferred compensation - SERP obligation and other 1
3,310
 3,172
Other2,290
 1,647
 $28,901
 $15,887
_______________________ 
1 Represents the assets and liabilities of the Company'sour nonqualified supplemental employee retirement savings plan. Assets of the plan are held in a Rabbi Trust. Shares of the Company'sour common stock held by the Rabbi Trust are presented as Treasurytreasury stock carried at cost.

2 Includes the combined unfunded benefit obligations under the Company'sour defined benefit pension and postretirement health care plans of $5.4$5.1 million and $5.4 million as of December 31, 20112012 and 2010.2011. The expense recognized with respect to these plans was $0.4$0.3 million $0.6, $0.4 million and $0.6$0.6 million for the years ended December 31, 2012, 2011 2010 and 2009,2010, respectively.

3 Includes employer matching obligations under the Company'sour defined contribution retirement plan of $0.3$0.2 million and $0.3 million as of December 31, 20112012 and 2010.2011, respectively. The expense recognized with respect to this plan was $1.2$0.9 million $1.7, $1.2 million and $2.3$1.7 million for the years ended December 31, 2012, 2011 2010 and 2009,2010, respectively.


11.Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value ofboth our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive to sellupon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We use a hierarchy that prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:


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Fair value measurements are classified and disclosed in one of the following three categories:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.

Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).


Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of December 31, 2011,2012, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.

The following table summarizes the fair value of our long-term debt with fixed interest rates, which is estimated based on the published market prices for these debt obligations as of the dates presented:

  December 31, 2011  December 31, 2010 
   Fair   Carrying   Fair   Carrying 
   Value   Value   Value   Value 
Senior Notes due 2016 $319,500  $293,561  $335,712  $292,487 
Senior Notes due 2019  280,500   300,000   -   - 
Convertible Notes  4,925   4,746   225,975   214,049 
  $604,925  $598,307  $561,687  $506,536 

 December 31, 2012 December 31, 2011
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
Senior Notes due 2016$316,500
 $294,759
 $319,500
 $293,561
Senior Notes due 2019286,500
 300,000
 280,500
 300,000
Convertible Notes—
 —
 4,925
 4,746
 $603,000
 $594,759
 $604,925
 $598,307
Recurring Fair Value Measurements

Certain financial assets and liabilities are measured at fair value on a recurring basis in our Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented:

  As of December 31, 2011 
  Fair Value  Fair Value Measurement Classification 
Description Measurement  Level 1  Level 2  Level 3 
Assets:                
Commodity derivative assets - current $18,987  $-  $18,987  $- 
Commodity derivative assets - noncurrent  -   -   -   - 
Long-term investments - Rabbi Trust  3,088   3,088   -   - 
                 
Liabilities:                
Commodity derivative liabilities - current  (3,549)  -   (3,549)  - 
Commodity derivative liabilities - noncurrent  (6,850)  -   (6,850)  - 
Deferred compensation - noncurrent  (3,168)  (3,168)  -   - 
Totals $8,508  $(80) $8,588  $- 

  As of December 31, 2010 
  Fair Value  Fair Value Measurement Classification 
Description Measurement  Level 1  Level 2  Level 3 
Assets:                
Commodity derivative assets - current $15,075  $-  $15,075  $- 
Commodity derivative assets - noncurrent  3,042   -   3,042   - 
Interest rate swap assets - current  1,743   -   1,743   - 
Interest rate swap assets - noncurrent  847   -   847   - 
Long-term investments - Rabbi Trust  6,440   6,440   -   - 
                 
Liabilities:                
Commodity derivative liabilities - current  (388)  -   (388)  - 
Deferred compensation - noncurrent  (6,948)  (6,948)  -   - 
Totals $19,811  $(508) $20,319  $- 

  As of December 31, 2012
  Fair Value Fair Value Measurement Classification
Description Measurement Level 1 Level 2 Level 3
Assets:  
  
  
  
Commodity derivative assets - current $11,292
 $—
 $11,292
 $—
Commodity derivative assets - noncurrent 5,181
 —
 5,181
 —
Assets of SERP 3,237
 3,237
 —
 —
         
Liabilities:  
  
  
  
Commodity derivative liabilities - current —
 —
 —
 —
Commodity derivative liabilities - noncurrent (1,421) —
 (1,421) —
Deferred compensation - SERP obligation and other (3,305) (3,305) —
 —
  As of December 31, 2011
  Fair Value Fair Value Measurement Classification
Description Measurement Level 1 Level 2 Level 3
Assets:  
  
  
  
Commodity derivative assets - current $18,987
 $—
 $18,987
 $—
Assets of SERP 3,088
 3,088
 —
 —
Liabilities:  
  
  
  
Commodity derivative liabilities - current (3,549) —
 (3,549) —
Commodity derivative liabilities - noncurrent (6,850) —
 (6,850) —
Deferred compensation - SERP obligation and other (3,168) (3,168) —
 —

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Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the years ended December 31, 2012, 2011 and 2010.

We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

Commodity derivatives:derivatives: We determine the fair values of our oil and gascommodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.

•Interest rate swaps: We determine the fair values of our interest rate swaps using an income approach valuation technique that connects future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a level 2 input.
• Long-term investments – Rabbi Trust: We hold various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.

Interest rate swaps: We determine the fair values of our interest rate swaps using an income approach valuation technique that connects future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a level 2 input.
Assets of SERP: We hold various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.
Deferred compensation:compensation - SERP obligations and other: Certain of our deferred compensation obligations are ultimately to be settled in cash based on the underlying fair value of certain assets, including those held in the Rabbi Trust. The fair values are based on quoted market prices, which are level 1 inputs.


Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements include the fair value of proved properties, tubular inventory and well materials for purposes of impairment testing and the initial determination of AROs. The factors used to determine fair value for purposes of impairment testing include, but are not limited to, estimates of proved and probable reserves, future commodity prices, indicative sales prices for properties, 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. Because these significant fair value inputs are typically not observable, we have categorized the amounts as level 3 inputs.

The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial fair value estimates as level 3 inputs.

In addition to these non-recurring fair value measurements, we utilized fair value measurements in the determination of the loss on the extinguishment of approximately 98% of ourthe Convertible Notes. In connection with that determination, we were required to allocate the cash paid to repurchase the Convertible Notes to its liability and equity components. The allocation to the liability component was based on the fair value of a comparable debt instrument that has no conversion feature. The residual amount of cash paid to repurchase the Convertible Notes was allocated to the equity component.

12.Commitments and Contingencies


12.    Commitments and Contingencies

The following table sets forth our significant commitments as of December 31, 2011,2012, by category, for the next five years and thereafter:

  Minimum     Firm 
  Rental  Drilling  Transportation 
Year Commitments  Commitments  Commitments 
2012 $3,120  $23,820  $10,255 
2013  2,283   59   8,805 
2014  1,737   -   6,137 
2015  1,628   -   5,137 
2016  1,456   -   4,271 
Thereafter  1,963   -   30,957 
Total $12,187  $23,879  $65,562 

Year 
Minimum
Rentals
 Drilling and Completion 
Firm
Transportation
2013 $2,093
 $22,117
 $4,580
2014 1,810
 —
 2,002
2015 1,613
 —
 2,002
2016 1,481
 —
 1,095
2017 653
 —
 1,095
Thereafter 1,347
 —
 11,862
Total $8,997
 $22,117
 $22,636

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Rental Commitments

Operating lease rental expense in the years ended December 31, 2012, 2011 2010 and 20092010 was $11.4$11.0 million $14.8, $11.4 million and $18.0$14.8 million, respectively, related primarily to field equipment, office equipment and office leases.

Drilling and Completion Commitments

We have agreements to purchase oil and gas well drilling and well completion services from third parties with original terms of up to three3 years. As of December 31, 2012, there were no well drilling or well completion agreements with terms that extended beyond June 30, 2013. The well drilling agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their original terms. The amount of penalty is based on the number of days remaining in the contractual term and declines as time passes. As of December 31, 2011,2012, the penalty amount would have been $14.1$2.0 million if we had terminated our agreements on that date.

Firm Transportation Commitments

We have entered into contracts that provide firm transportation capacity rights for specified volumes per day on various pipeline systems with terms that range from one1 to 15 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion.

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, results of operations or cash flows. During 2011, we recorded a $0.2$0.2 million reserve for litigation attributable to certain properties that were previously sold. This litigation was settled in January 2012 for the recorded amount. During 2010, we established a $0.9$0.9 million reserve for a litigation matter pertaining to certain properties that remains outstanding as of December 31, 2011.2012. During 2010, we also established a $0.5$0.5 million reserve for a sales tax audit contingency, which was ultimately resolved during 2011 for $0.3 million.

$0.3 million.

Environmental Compliance

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of December 31, 2011,2012, we have recorded AROs of $6.3$4.5 million attributable to these activities. 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 impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.


13.Shareholders’ Equity

Preferred Stock

In October 2012, we completed a registered offering of 11,500 shares of our 6% Series A Convertible Perpetual Preferred Stock (the “6% Preferred Stock”) that provided $110.3 million of proceeds, net of underwriting fees and issuance costs.

The annual dividend on each share of the 6% Preferred Stock is 6.00% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on each of January 15, April 15, July 15 and October 15 of each year,

77


commencing on January 15, 2013. We may, at our option, pay dividends in cash, common stock or a combination thereof. On December 20, 2012, the Company's board of directors declared a quarterly cash dividend of $146.67 per share, which reflects the pro rata portion of the regular quarterly cash dividend representing the period from the original issue date of October 17, 2012 through January 14, 2013. An obligation for $1.7 million representing this declared dividend is included in the Accounts payable and accrued liabilities caption on our Consolidated Balance Sheets as of December 31, 2012.

Each share of the 6% Preferred Stock is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the conversion price, which is initially $6.00 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 1,666.67 shares of our common stock for each share of the 6% Preferred Stock. The initial conversion price represents a premium of 20 percent relative to the 2012 common stock offering price of $5.00 per share. The 6% Preferred Stock is not redeemable by us or the holders at any time. At any time on or after October 15, 2017, we may, at our option, cause all outstanding shares of the 6% Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-applicable conversion price for a specified period prior to conversion. If a holder elects to convert shares of the 6% Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value.

Common Stock

Concurrent with the 6% Preferred Stock offering, we completed a registered offering of 9.2 million shares of our common stock that provided $43.5 million of proceeds, net of underwriting fees and issuance costs. The proceeds from the combined offerings were used to repay outstanding borrowings under the Revolver and for general corporate purposes.

In May 2010, the shareholders of the Company approved an increase in the authorized number of shares of common stock from 64 million to 128 million shares.

In May 2009, we issued 3,500,000 shares of our common stock in a registered public offering that provided $64.8 million of net proceeds. The net proceeds were used, in addition to the proceeds from the issuance of the Senior Notes due 2016, to repay borrowings under our previous revolving credit facility.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive losses are entirely attributable to our pension and postretirement benefit obligations. The accumulated losses, net of tax, were $1.1$1.0 million $0.9, $1.1 million and $1.3$0.9 million as of December 31, 2012, 2011 2010 and 2009,2010, respectively.


Treasury Stock

We maintain nonqualified deferred compensation supplemental retirement savings plans for certain employees and directors. Participants in the plans may defer and contribute a portion of their compensation to a Rabbi Trust. We include the assets and liabilities of the supplemental retirement savings plans on our Consolidated Balance Sheets. Shares of the Company’sour common stock purchased under the non-qualified deferred compensation plans are held in the Rabbi Trust and are presented as treasury stock carried at cost. A total of 223,886218,320 and 125,357223,886 shares have been recorded as treasury stock as of December 31, 20112012 and 2010,2011, respectively.

Noncontrolling Interests

In connection with the sale of our remaining PVG Common Units (Note 3), we deconsolidated PVG from our Consolidated Financial Statements resulting in the elimination of PVG’s assets and liabilities as well as the related noncontrolling interests from our Consolidated Balance Sheet and Consolidated Statements of Shareholders’ Equity and Comprehensive Income.

Prior to the final sale of our PVG Common Units, we reduced our limited partner interest in PVG during 2010 and 2009 while still maintaining control. In April 2010, we completed the sale of 11.25 million units of PVG owned by us for proceeds of $199.1 million, net of offering costs reducing our limited partner interest in PVG from 51.4% to 22.6%. The transaction resulted in a $70.2 million increase in noncontrolling interests and an $82.9 million increase to additional paid-in capital, net of income tax effects. In September 2009, we sold 10 million units of PVG for proceeds of $118.1 million, net of offering costs reducing our limited partner interest in PVG from 77.0% to 51.4%. The transaction resulted in a $67.7 million increase in noncontrolling interests and a $32.7 million increase to additional paid-in capital, net of income tax effects.


14.Share-Based Compensation

We have

Our stock compensation plans (collectively, the “Stock Compensation Plans”) that allowpermit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to be granted to keyour employees and officers and nonqualified stock options and deferred common stock units to be granted to directors. As of December 31, 2011,2012, there were approximately 2,227,5542,317,176 and 196,31488,119 shares available for issuance to employees and directors, respectively, pursuant to the Stock Compensation Plans.


With the exception of performance-based restricted stock units (“PBRSUs”), all of the awards issued under our Stock Compensation Plans are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable

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to these awards is measured at the grant date and recognized over the applicable vesting period as a non-cash item of expense. Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period and recognized based on the period of time that has elapsed during each of the individual performance periods.
The following table summarizes the share-based compensation expense recognized for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Stock option plans $5,477  $5,828  $6,602 
Common, deferred, restricted and restricted unit plans  1,953   1,983   2,525 
  $7,430  $7,811  $9,127 

 Year Ended December 31,
 2012 2011 2010
Equity-classified awards:     
Stock option awards$4,424
 $5,477
 $5,828
Common, deferred, restricted and restricted unit awards1,923
 1,953
 1,983
 6,347
 $7,430
 $7,811
Liability-classified awards714
 —
 —
 $7,061
 $7,430
 $7,811
Stock Options

The exercise price of all stock options granted under the Stock Compensation Plans is equal to the fair market value of our common stock on the date of the grant. Options may be exercised at any time after vesting and prior to ten years following the date of grant. Options vest upon terms established by the compensation and benefits committee of our board of directors (the “Committee”). Generally, options vest over a three-yearthree-year period, with one-third vesting in each year. In addition, all options will vest upon a change of control of the Company,us, as defined in the Stock Compensation Plans. In the case of employees, if a grantee’s employment terminates (i) for cause, all of the grantee’s options, whether vested or unvested, will be automatically forfeited, (ii) by reason of death, disability or retirement after becoming retirement eligible (age 62 and providing ten10 consecutive years of service) the grantee’s options will automatically vest and (iii) for any other reason, the grantee’s unvested options will be automatically forfeited. In the case of directors, if a grantee’s membership on our board of directors terminates for any reason, the grantee’s unvested options will be automatically forfeited. We have consistentlyhistorically issued new shares to satisfy sharestock option exercises.

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

  2011  2010  2009 
Expected volatility   61.7% to 71.9%    59.5% to 67.6%    51.7% to 64.9% 
Dividend yield   1.25% to 2.25%    0.90% to 1.20%    1.25% to 1.49% 
Expected life   3.5 to 4.6 years    3.5 to 4.6 years    3.5 to 4.6 years 
Risk-free interest rate   0.39% to 2.18%    0.68% to 2.30%    1.23% to 1.84% 

 2012 2011 2010
Expected volatility67.3% to 72.9% 61.7% to 71.9% 59.5% to 67.6%
Dividend yield2.25% to 4.98% 1.25% to 2.25% 0.90% to 1.20%
Expected life3.5 to 4.6 years 3.5 to 4.6 years 3.5 to 4.6 years
Risk-free interest rate0.36% to 0.51% 0.39% to 2.18% 0.68% to 2.30%
The following table summarizes activity for our most recent fiscal year with respect to awardedstock options:

        Weighted-    
        Average    
     Weighted-  Remaining    
  Shares Under  Average  Contractual  Aggregate 
  Options  Exercise Price  Term  Intrinsic Value 
Outstanding at beginning of year  2,144,357  $24.70         
Granted  830,021   16.98         
Exercised  (95,516)  11.89         
Forfeited  (403,788)  23.26         
Outstanding at end of year  2,475,074  $22.84   7.4  $67 
Exercisable at end of year  1,352,273  $26.74   6.4  $12 

 
Shares Under
Options
 
Weighted-
Average
Exercise Price
 
Weighted-
Average
Remaining
Contractual
Term
 
Aggregate
Intrinsic Value
Outstanding at beginning of year2,475,074
 $22.84
    
Granted224,501
 5.59
    
Exercised—
 —
    
Forfeited(412,841) 22.99
    
Outstanding at end of year2,286,734
 $21.14
 6.6 $7
Exercisable at end of year1,711,098
 $23.21
 6.1 $—

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The weighted-average grant-date fair value of options granted during the years ended December 31, 2012, 2011 2010 and 20092010 was $7.30, $10.13$2.54, $7.30 and $5.60$10.13 per option. The total intrinsic value of options exercised during the years ended December 31, 2011 and 2010 was $0.4$0.4 million and $1.2 million.$1.2 million. There were no options exercised during 2009.

2012.


As of December 31, 2011,2012, we had $6.5$2.6 million of unrecognized compensation cost related to unvested stock options. We expect that cost to be recognized over a weighted-average period of 0.90.5 years. The total grant-date fair values of stock options that vested in 2012, 2011 2010 and 20092010 were $3.7$4.7 million $4.6, $3.7 million and $5.7$4.6 million, respectively.

Common Stock

A portion of the compensation paid to certain non-employee members of our board of directors is paid in common stock. Each share of common stock granted as compensation vests immediately upon issuance. In 2012, we granted 79,700 shares of common stock to our non-employee directors at a weighted-average grant date fair value of $5.33 per share.

Deferred Common Stock Units
A portion of the compensation paid to certain non-employee members of our board of directors is paid in deferred common stock units. Each deferred common stock unit represents one share of common stock, vests immediately upon issuance, and is available to the holder upon termination or retirement from our board of directors. Deferred common stock units awarded to directors receive all cash or other dividends we pay on shares of our common stock.
The following table summarizes activity for our most recent fiscal year with respect to awarded deferred common stock units: 
 
Deferred
Common Stock
Units
 
Weighted-Average
Grant Date
Fair Value
Balance at beginning of year208,783
 $17.34
Granted29,295
 5.38
Converted(35,202) 18.95
Balance at end of year202,876
 $15.33
As of December 31, 2012, 2011 and 2010, shareholders’ equity included deferred compensation obligations of $3.1 million, $3.6 million and $2.7 million, respectively, and corresponding amounts for treasury stock.

Restricted Stock

Restricted stock vests upon terms established by the Committee and as specified in the award agreement. In addition, all restricted stock will vest upon a change of control of the Company.us. If a grantee’s employment terminates for any reason other than death or disability, the grantee’s restricted stock will be automatically forfeited unless otherwise determined by the Committee and specified in the award agreement. If a grantee’s employment terminates by reason of death or disability, or if a grantee becomes retirement eligible, the grantee’s restricted stock will automatically vest. Except as specified by the Committee, a grantee shall be entitled to receive any dividends declared on our common stock. Restricted stock vests generally over a three-yearthree-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

The following table summarizes activity for our most recent fiscal year with respect to awarded nonvested restricted stock:

  Nonvested  Weighted-Average 
  Restricted  Grant Date 
  Stock  Fair Value 
Balance at beginning of year  5,957  $42.27 
Vested  (5,957)  42.27 
Balance at end of year  -  $- 


The total grant-date fair values of restricted stock that vested in 2011 and 2010 were $0.3 millionand 2009$0.5 million. There were $0.3 million, $0.5 millionno unvested restricted stock awards outstanding during 2012, and $1.3 million, respectively.

Deferred Common Stock Units

A portion of the compensation paid to non-employee members of our board of directors is paid in deferred commonno restricted stock units. Each deferred common stock unit represents one share of common stock, vests immediately upon issuance, and is available to the holder upon termination or retirement from our board of directors. Deferred common stock units awarded to directors receive all cash or other dividends we pay on shares of our common stock.

The following table summarizes activity for our most recent fiscal year with respect to awarded deferred common stock units:

  Deferred  Weighted-Average 
  Common Stock  Grant Date 
  Units  Fair Value 
Balance at beginning of year  103,256  $26.76 
Granted  105,527   8.31 
Balance at end of year  208,783  $17.34 

As of December 31, 2011, 2010 and 2009, shareholders’ equity included deferred compensation obligations of $3.6 million, $2.7 million and $2.4 million, respectively, and corresponding amounts for treasury stock.

awards vested during 2012.


Restricted Stock Units

A restricted stock unit entitles the grantee to receive a share of common stock upon the vesting of the restricted stock unit or, at the discretion of the Committee, the cash equivalent of the fair market value of a share of common stock. The Committee determines the time period over which restricted stock units granted to employees and directors will vest. In addition, all restricted stock units will vest upon a change of control of the Company.us. If an employee’s employment with us or our affiliates terminates for any reason other than death, disability or retirement after becoming retirement eligible, the grantee’s restricted stock units will be automatically forfeited unless, and to the extent, the Committee provides otherwise. Restricted stock units generally vest over a three-yearthree-year period, with one-third vesting in each year. The Committee, in its discretion, may grant tandem dividend equivalent rights with respect to restricted stock units. A dividend equivalent right is a right to receive an amount in cash equal

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to, and 30 days after, the cash dividends made with respect to a share of common stock during the period such restricted stock unit is outstanding. Payments of dividend equivalent rights associated with restricted stock units that are expected to vest are recorded as dividends; payments associated with restricted stock units that are not expected to vest are recorded as compensation expense.


The following table summarizes activity for our most recent fiscal year with respect to awarded restricted stock units:

     Weighted-Average 
  Restricted Stock  Grant Date 
  Units  Fair Value 
Balance at beginning of year1  72,215  $18.77 
Granted  78,763   17.14 
Vested  (51,152)  18.38 
Balance at end of year1  99,826  $18.10 

 
Restricted Stock
Units
 
Weighted-Average
Grant Date
Fair Value
Balance at beginning of year 1
99,826
 $18.10
Granted108,157
 5.67
Vested(105,773) 13.09
Forfeited(10,239) 9.20
Balance at end of year 1
91,971
 $10.08
________________________
1Excludes 61,344 units at both the beginning of the year and78,864 units at the end of year that have vested due to retirement eligibility, but have not yet been settled or converted to common shares.

As of December 31, 2011,2012, we had $1.4$0.6 million of unrecognized compensation cost attributable to nonvestedunvested restricted stock units. We expect that cost to be recognized over a weighted-average period of 0.8 years. The total grant-date fair values of restricted stock units that vested in 2012, 2011 2010 and 20092010 were $0.9$1.4 million $0.9, $0.9 million and $0.6$0.9 million, respectively.


Performance-Based Restricted Stock Units
In February 2012, we granted PBRSUs to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of specified market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.

If the grantee's employment terminates for any reason prior to the third anniversary of the grant date, then the grantee's PBRSUs will be forfeited and no cash will be payable with respect to any PBRSUs. If the grantee is or becomes retirement eligible, which is defined as reaching age 62 and completing 10 years of consecutive service with us or our affiliate, and his or her employment terminates for any reason other than cause prior to the third anniversary of the grant date, then all of the grantee's PBRSUs will vest and become payable in the amount and at the time the PBRSUs would have otherwise vested and been payable. If the grantee dies or becomes disabled prior to the third anniversary of the grant date, a pro-rated share (based on the number of days employed during the three-year vesting period) of the PBRSUs will vest and the grantee will be paid for such PBRSUs at the target percentage at the end of the end of the original three-year vesting period. In the event of a change in control of us, all of the grantee's PBRSUs will immediately vest and the grantee will be paid for such PBRSUs following the change in control at the target percentage (regardless of our actual market-based performance) and using the value of our common stock on the effective date of the change in control (calculated as the closing price of our common stock on the effective date of the change in control).

The compensation cost of the PBRSUs is based on the fair value derived from a Monte Carlo model. The Monte Carlo model is a binomial valuation model that utilizes certain assumptions, including expected volatility, dividend yield, risk-free interest rates and a measure of total shareholder return. The ranges for the assumptions used in the Monte Carlo model for the PBRSUs granted in 2012 are as follows:
Expected volatility29.3% to 78.0%
Dividend yield0.00% to 5.30%
Risk-free interest rate0.02% to 0.43%


81


The following table summarizes activity for our most recent fiscal year with respect to PBRSUs:
 
Performance-Based Restricted Stock
Units
 
Weighted-Average
Fair Value
Balance at beginning of year—
 $—
Granted216,441
 6.80
Forfeited(15,617) 12.80
Balance at end of year200,824
 $6.67

As of December 31, 2012, $0.7 million, which represents the fair value of the outstanding PBRSUs, is included in the Other liabilities caption on our Consolidated Balance Sheets.

15.Restructuring Activities

During 2012, we completed an organizational restructuring in conjunction with the sale of our legacy natural gas assets in West Virginia, Kentucky and Virginia. We terminated approximately 30 employees and closed our regional office in Canonsburg, Pennsylvania. We recorded a charge in connection with the early termination of the lease of that office. In addition, we have a contractual commitment for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the recently completed sale, we no longer have production to satisfy this commitment. While we intend to sell our unused firm transportation in the future to the extent possible, we recorded a charge of $17.3 million representing the liability for estimated discounted future net cash outflows over the remaining term of the contract. The undiscounted amount payable on an annual basis for the each of the next five years is $2.8 million and a combined amount of $13.0 million will be payable for 2018 through expiration in 2022.

During 2011, we completed an organizational restructuring due primarily to our decision to exit thesale of Arkoma Basin properties and to consolidateconsolidation of certain operations functions toin our Houston, Texas location. This restructuringWe terminated approximately 40 employees and consolidation resulted in the termination of approximately 40 employees, most of whom were based out of our Tulsa, Oklahoma office, as well as certain corporate positions in connection with a reallocation of administrative responsibilities. In addition, we closed our regional office in Tulsa, Oklahoma during the fourth quarter of 2011andOklahoma. Accordingly, we recorded a charge and recognized an obligation in connection with the long-term lease of that office.

In addition to the accrual of these costs, we adjusted the lease obligation associated with the Tulsa office as a result of a change in estimated sub-lease rental income.

During 2009 and 2010, we implemented an organization restructuringincurred special termination benefit costs in connection with our transformation to a pure play development, exploration and production company. The restructuring resulted in the termination of approximately 30 employees and the transfer of certain corporate and division operations functions from our former Kingsport, Tennessee location to our Houston, Texaslocation. We also incurred a charge for the assignment of the lease of that office and Pittsburgh and Radnor, Pennsylvania locations. We incurred special termination benefit costs, relocation costs and other incremental costs associated with staffing and expanding our other office locations.

These restructuring

The following table summarizes our restructuring-related obligations as of and for the years ended December 31:
 2012 2011 2010
Balance at beginning of period$576
 $64
 $529
Employee, office and other costs accrued, net1,284
 2,351
 8,200
Firm transportation charge17,332
 —
 —
Accretion of obligations570
 —
 —
Cash payments, net(2,499) (1,839) (8,665)
Balance at end of period$17,263
 $576
 $64

Restructuring charges are included in the General and administrative expenses caption on our Consolidated Statements of Operations. The initial charge for the firm transportation commitment is presented as a separate caption on our Consolidated Statement of Operations and are comprisedthe accretion of the following forrelated obligation, net of any recoveries from the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Termination benefits $1,463  $2,081  $529 
Employee and office relocation costs  322   1,597   - 
Other incremental costs  -   1,022   - 
Facility lease-related charges  566   3,500   - 
  $2,351  $8,200  $529 

periodic sale of our contractual capacity, is charged as an offset to Other revenue. The following table summarizescurrent portion of these restructuring and exit cost obligations is included in the Accounts payable and accrued expenses caption and the noncurrent portion is included in the Other liabilities caption on our restructuring-relatedConsolidated Balance Sheets. As of December, 2012, $2.7 million of the total obligations are classified as of and forcurrent while the years ended December 31:

  2011  2010  2009 
Balance at beginning of period $64  $529  $- 
Termination benefits accrued  1,463   2,081   529 
Employee, office and other costs accrued  888   6,119   - 
Cash payments  (1,839)  (8,665)  - 
Balance at end of period $576  $64  $529 

remaining $14.5 million are classified as noncurrent.


82


16.Impairments

The following table summarizes impairment charges recorded during the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Oil and gas properties $104,688  $43,067  $102,332 
Other - tubular inventory and well materials  -   2,892   4,083 
  $104,688  $45,959  $106,415 

During

 Year Ended December 31,
 2012 2011 2010
Oil and gas properties$103,417
 $104,688
 $43,067
Other - tubular inventory and well materials1,067
 —
 2,892
 $104,484
 $104,688
 $45,959
The following table summarizes the aggregate fair values of the assets described below, by asset category and the classification of inputs within the fair value measurement hierarchy, at the respective dates of impairment:
 Fair Value      
 Measurement Level 1 Level 2 Level 3
Year ended December 31, 2012:       
Long-lived assets held for use$14,801
 $—
 $—
 $14,801
Long-lived assets sold during the year96,099
 —
 —
 96,099
        
Year ended December 31, 2011:       
Long-lived assets held for use$26,625
 $—
 $—
 $26,625
Long-lived assets sold during the year30,342
 —
 —
 30,342

In 2012, we recognized a $28.4 million impairment of our legacy assets in West Virginia, Kentucky and Virginia triggered by the expected disposition of these properties, and a $75.0 million impairment of our Marcellus Shale assets due primarily to market declines in natural gas prices and the resultant reduction in proved natural gas reserves. In 2012, we also recognized an impairment of certain tubular inventory and well materials triggered primarily by declines in asset quality. In 2011, we recognized an impairment of our Arkoma Basin assets for $71.1$71.1 million, which was triggered by the expected disposition of these high-cost gas properties. As disclosed in Note 3, we completed the sale of these properties in August 2011. Also during 2011, we recognized an impairmentimpairments of our horizontal coal bed methane properties in the Appalachian region for $26.6$26.6 million and certain dry-gas properties in Mississippi for $7.0$6.8 million, in each case due primarily to market declines in gas prices. DuringIn 2010, we incurredrecognized an impairment charges related toof our Mid-Continent coal bed methane properties as a result of market declines in gas prices and to an area in the Anadarko Basin of the Mid-Continent region where we drilled an uneconomic well. In addition, we recorded impairment charges attributable to certain oiltubular inventory and gas inventory assetswell materials triggered primarily by declines in asset quality. During 2009, we incurred impairment charges in connection with the initial classification of our Gulf Coast properties as assets held for sale at their fair value less costs to sell, as well as impairments attributable to tubular inventory and other oil and gas properties.


17.Interest Expense

The following table summarizes the components of interest expense for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Interest on borrowings and related fees $51,384  $43,060  $33,374 
Accretion on original issue discount  3,427   8,109   7,523 
Amortization of debt issuance costs  3,380   3,875   2,679 
Interest rate swaps  -   -   3,969 
Capitalized interest  (1,983)  (1,384)  (2,318)
Other, net  8   19   (996)
  $56,216  $53,679  $44,231 

 Year Ended December 31,
 2012 2011 2010
Interest on borrowings and related fees$56,079
 $51,384
 $43,060
Accretion of original issue discount1,367
 3,427
 8,109
Amortization of debt issuance costs2,695
 3,380
 3,875
Capitalized interest(803) (1,983) (1,384)
Other, net1
 8
 19
 $59,339
 $56,216
 $53,679

83



76
18.Earnings per Share

The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:

  Year Ended December 31, 
  2011  2010  2009 
Loss from continuing operations $(132,915) $(65,327) $(130,856)
Income from discontinued operations, net of tax1  -   33,448   53,488 
Gain on sale of discontinued operations, net of tax  -   51,546   - 
Less net income attributable to noncontrolling interests  -   (28,090)  (37,275)
Loss attributable to common shareholders $(132,915) $(8,423) $(114,643)
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of tax  -   (28)  (116)
  $(132,915) $(8,451) $(114,759)
Weighted-average shares, basic  45,784   45,553   43,811 
Effect of dilutive securities2  -   -   - 
Weighted-average shares, diluted  45,784   45,553   43,811 

 Year Ended December 31,
 2012 2011 2010
Loss from continuing operations$(104,589) $(132,915) $(65,327)
Income from discontinued operations, net of tax 1
—
 —
 33,448
Gain on sale of discontinued operations, net of tax—
 —
 51,546
Less net income attributable to noncontrolling interests—
 —
 (28,090)
Loss attributable to Penn Virginia Corporation(104,589) (132,915) (8,423)
Less: Preferred stock dividends(1,687) —
 —
Loss attributable to common shareholders - Basic(106,276) (132,915) (8,423)
Add: Preferred stock dividends 2
—
 —
 —
Loss attributable to common shareholders - Diluted$(106,276) $(132,915) $(8,423)
      
Weighted-average shares - Basic47,919
 45,784
 45,553
Effect of dilutive securities 3
—
 —
 —
Weighted-average shares - Diluted47,919
 45,784
 45,553
_______________________
1For purposes of determining earnings per share, net income attributable to noncontrolling interests is applied against income from discontinued operations as both are completely attributable to PVG's operations.

2 Preferred stock dividends were excluded for diluted earnings per share as the assumed conversion of the 6% Preferred Stock would have been anti-dilutive.
3For 2012, 2011 2010 and 2009, an amount less than 2010, approximately 19.2 million, 0.1 million approximately and 0.2 million and 0.1 million potentially dilutive securities, including the 6% Preferred Stock, Convertible Notes, stock options, restricted stock and restricted stock units had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.


19.Discontinued Operations

Prior to June 2010, we indirectly owned partner interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded limited partnership formed by us in 2001. Our ownership interests in PVR were held principally through our general and limited partner interests in PVG. During June 2010, we disposed of our remaining ownership interests in PVG and, indirectly, our interests in PVR.

PVR and recognized a gain on the sale of discontinued operations of $51.5 million, net of income taxes of $35.1 million.

Income from discontinued operations represents the results of operations of PVG, which include the results of operations of PVR. Previously, the results of operations of PVG and PVR were presented as our coal and natural resource management and natural gas midstream segments.

The disclosures for the 2010 period provided in the table below reflect the results of operations of PVG through the date of the disposition of our entire remaining interest in PVG onin June 7, 2010.

  Year Ended December 31, 
  2011  2010  2009 
Revenues $-  $303,206  $579,931 
             
Income from discontinued operations before taxes $-  $36,832  $64,130 
Income tax expense1  -   (3,384)  (10,642)
Income from discontinued operations, net of taxes $-  $33,448  $53,488 

 Year Ended December 31,
 2012 2011 2010
Revenues$—
 $—
 $303,206
      
Income from discontinued operations before taxes$—
 $—
 $36,832
Income tax expense 1
—
 —
 (3,384)
Income from discontinued operations, net of taxes$—
 $—
 $33,448
________________________
1Determined by applying the effective tax rate attributable to discontinued operations to the income from discontinued operations less noncontrolling interests that are fully attributable to PVG's operations.

The following table summarizes the determination of the gain recognized in 2010 upon the disposition of PVG:

Cash proceeds, net of offering costs (8,827,429 units x $15.76 per unit) $139,120 
Carrying value of noncontrolling interests in PVG at date of disposition  382,324 
   521,444 
Less: Carrying value of PVG's assets and liabilities at date of disposition  (434,782)
   86,662 
Income tax expense  (35,116)
Gain on sale of discontinued operations, net of tax $51,546 

During 2011, we terminated certain agreements under which PVR provided marketing and gas gathering and processing services to us. We continue to sell gas to PVR for resale at PVR’s Crossroads plant in East Texas. In connection with the disposition in 2010, we and PVG entered into transition service agreements attributable primarily to corporate and information technology functions. We billed PVG for transition services in the amount of $0.7$0.7 million, net of amounts charged to us by PVG, for the year ended December 31, 2010. This amount is included in the General and administrative caption on our Consolidated Statements of Operations as a reduction to expenses.


84


Supplemental Quarterly Financial Information (Unaudited)

  First  Second  Third  Fourth 
  Quarter  Quarter  Quarter  Quarter 
2011                
Revenues $68,583  $73,618  $83,353  $80,451 
Operating loss1 $(28,529) $(80,713) $(9,031) $(37,146)
Loss attributable to Penn Virginia Corp. $(26,340) $(71,918) $(6,718) $(27,939)
Loss per share - Basic2: $(0.58) $(1.57) $(0.15) $(0.61)
Loss per share - Diluted2: $(0.58) $(1.57) $(0.15) $(0.61)
Weighted-average shares outstanding:                
Basic  45,687   45,768   45,817   45,864 
Diluted  45,687   45,768   45,817   45,864 
                 
2010                
Revenues $67,878  $53,288  $68,953  $64,319 
Operating income (loss)3 $92  $(20,878) $(53,053) $(24,969)
Net loss from continuing operations $10,766  $(21,097) $(30,159) $(24,837)
Income (loss) from discontinued operations, net of tax $12,174  $21,308  $-  $(34)
Gain on sale of discontinued operations, net of tax $-  $49,612  $-  $1,934 
Income (loss) attributable to Penn Virginia Corp. $13,594  $31,079  $(30,159) $(22,937)
Earnings (loss) per share - Basic2:                
Continuing operations $0.24  $(0.46) $(0.66) $(0.54)
Discontinued operations $0.06  $0.06  $-  $- 
Gain on sale of discontinued operations $-  $1.08  $-  $0.04 
Net income (loss) $0.30  $0.68  $(0.66) $(0.50)
Earnings (loss) per share - Diluted2:                
Continuing operations $0.24  $(0.46) $(0.66) $(0.54)
Discontinued operations $0.06  $0.06  $-  $- 
Gain on sale of discontinued operations $-  $1.08  $-  $0.04 
Net income (loss) $0.30  $0.68  $(0.66) $(0.50)
Weighted-average shares outstanding:                
Basic  45,465   45,539   45,591   45,615 
Diluted  45,761   45,790   45,591   45,615 

 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
2012 
  
  
  
Revenues$84,411
 $76,845
 $77,699
 $78,194
Operating loss 1
$(3,422) $(38,043) $(24,485) $(81,141)
Loss attributable to Penn Virginia Corp.$(11,899) $(5,638) $(32,611) $(54,441)
Loss per share - Basic 2
$(0.26) $(0.12) $(0.71) $(1.05)
Loss per share - Diluted 2
$(0.26) $(0.12) $(0.71) $(1.05)
Weighted-average shares outstanding: 
  
  
  
Basic45,945
 46,030
 46,050
 53,607
Diluted45,945
 46,030
 46,050
 53,607
        
2011 
  
  
  
Revenues$68,583
 $73,618
 $83,353
 $80,451
Operating loss 3
$(28,529) $(80,713) $(9,031) $(37,146)
Loss attributable to Penn Virginia Corp.$(26,340) $(71,918) $(6,718) $(27,939)
Loss per share - Basic 2
$(0.58) $(1.57) $(0.15) $(0.61)
Loss per share - Diluted 2
$(0.58) $(1.57) $(0.15) $(0.61)
Weighted-average shares outstanding: 
  
  
  
Basic45,687
 45,768
 45,817
 45,864
Diluted45,687
 45,768
 45,817
 45,864
________________________
1   Includes impairmentimpairments of oil and gas properties of $71$28.6 million, $0.7 million and $34$75.2 million during the quarters ended June 30, 20112012, September 30, 2012 and December 31, 2011,2012, respectively.

2   The sum of the quarters may not equal the total of the respective year's earnings per common share due to changes in weighted-average shares outstanding throughout the year.

3Includes an impairmentimpairments of $1.1$71.1 million for oil and gas properties held for sale$33.6 million during the quarterquarters ended June 30, 2010. Includes impairments of oil and gas assets of $35.1 million and $9.7 million for the quarters ended September 30, 20102011 and December 31, 2010,2011, respectively.

79



85


Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following supplemental information regarding the oil and gas producing activities is presented in accordance with the requirements of the current oil and gas accounting standards.

Capitalized Costs Relating to Oil and Gas Producing Activities

  As of December 31, 
  2011  2010  2009 
Proved properties $277,987  $293,486  $353,386 
Unproved properties  120,288   171,303   73,067 
Wells, equipment and facilities  2,081,103   1,840,154   1,527,749 
Support equipment  6,645   6,254   5,938 
   2,486,023   2,311,197   1,960,140 
Accumulated depreciation and depletion  (710,948)  (609,380)  (487,106)
Net capitalized costs $1,775,075  $1,701,817  $1,473,034 

 As of December 31,
 2012 2011 2010
Proved properties$240,217
 $277,987
 $293,486
Unproved properties60,746
 120,288
 171,303
Wells, equipment and facilities2,107,061
 2,081,103
 1,840,154
Support equipment6,815
 6,645
 6,254
 2,414,839
 2,486,023
 2,311,197
Accumulated depreciation and depletion(693,123) (710,948) (609,380)
Net capitalized costs$1,721,716
 $1,775,075
 $1,701,817
ARO assets of $0.2$0.1 million $0.1, $0.2 million and $0.4$0.1 million were added to the cost basis of proved properties during the years ended December 31, 2012, 2011 2010 and 2009,2010, respectively.


Costs Incurred in Certain Oil and Gas Activities

  Year Ended December 31, 
  2011  2010  2009 
Proved property acquisition costs $-  $5,671  $- 
Unproved property acquisition costs  47,877   133,185   14,996 
Exploration costs  77,460   66,886   7,179 
Development costs and other  320,263   244,092   149,625 
Total costs incurred $445,600  $449,834  $171,800 

 Year Ended December 31,
 2012 2011 2010
Proved property acquisition costs$—
 $—
 $5,671
Unproved property acquisition costs27,775
 47,877
 133,185
Exploration costs50,883
 77,460
 66,886
Development costs and other305,693
 320,263
 244,092
Total costs incurred$384,351
 $445,600
 $449,834
Results of Operations for Oil and Gas Producing Activities

The following table includes results solely from the production and sale of oil and gas and non-cash charges for property impairments. It excludes corporate-related general and administrative expenses and gains or losses on property dispositions. Income tax expense (benefit) is calculated by applying statutory tax rates to revenues after deducting costs and giving effect to oil and gas-related permanent differences and tax credits.

  Year Ended December 31, 
  2011  2010  2009 
Revenues $300,046  $251,336  $228,659 
Production expenses  65,835   63,854   72,255 
Exploration expenses  78,943   49,641   57,754 
Depreciation and depletion expense  160,293   130,816   150,429 
Impairment of oil and gas properties  104,688   45,959   106,415 
   (109,713)  (38,934)  (158,194)
Income tax expense (benefit)  (42,788)  (15,184)  (61,221)
Results of operations $(66,925) $(23,750) $(96,973)

 Year Ended December 31,
 2012 2011 2010
Revenues$310,484
 $300,046
 $251,336
Production expenses56,096
 65,835
 63,854
Exploration expenses34,092
 78,943
 49,641
Depreciation and depletion expense204,849
 160,293
 130,816
Impairment of oil and gas properties104,484
 104,688
 45,959
 (89,037) (109,713) (38,934)
Income tax expense (benefit)(34,724) (42,788) (15,184)
Results of operations$(54,313) $(66,925) $(23,750)
A combined total of depletion and accretion expense related to AROs of $0.7$0.5 million, $0.7 million and $0.7 million was recognized in DD&A expense during each of the years ended December 31, 2012, 2011 2010 and 2009.

2010, respectively.


86


Oil and Gas Reserves

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, NGLs and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices for these commodities may all differ from those assumed. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available.

Our Manager of Engineering is primarily responsible for overseeing the preparation of the Company’s reserve estimate by our independent third party engineers, Wright & Company, Inc. TheOur Manager of Engineering has over 2627 years of industry experience in the estimation and evaluation of reserve information, holds a B.S. degree in Petroleum Engineering from Texas A&M University and is licensed by the stateState of Texas as a Professional Engineer. The Company’sOur internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

The technical person primarily responsible for review of our reserve estimates at Wright & Company, Inc., meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Wright & Company, Inc. is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.


The table on the following tablepage sets forth the Company’sour net quantities of proved reserves, including changes therein and proved developed and proved undeveloped reserves for the periods presented. This information includes our royalty and net working interest share of the reserves in oil and gas properties. All reserves are located in the United States. Net proved oil, NGL and natural gas reserves for the three years ended December 31, 20112012 were estimated by Wright & Company, Inc., utilizing data compiled by us.

  Natural  Oil and  Total 
  Gas  Condensate  Equivalents 
Proved Developed and Undeveloped Reserves (MMcf)  (MBbl)  (MMcfe) 
December 31, 2008  754,132   26,974   915,975 
Revisions of previous estimates1  (110,349)  (8,442)  (160,995)
Extensions, discoveries and other additions2  180,448   9,203   235,666 
Production  (43,337)  (1,277)  (51,000)
Purchase of reserves  -   -   - 
Sale of reserves in place  (4,229)  (71)  (4,659)
December 31, 2009  776,665   26,387   934,987 
Revisions of previous estimates3  (71,421)  5,202   (40,210)
Extensions, discoveries and other additions4  90,439   4,069   114,851 
Production  (38,919)  (1,380)  (47,201)
Purchase of reserves  3,288   9   3,342 
Sale of reserves in place  (15,070)  (1,490)  (24,014)
December 31, 2010  744,982   32,797   941,755 
Revisions of previous estimates5  (61,165)  (5,414)  (93,649)
Extensions, discoveries and other additions6  56,345   10,399   118,746 
Production  (33,410)  (2,190)  (46,553)
Purchase of reserves  1   20   124 
Sale of reserves in place  (36,840)  (42)  (37,092)
December 31, 2011  669,913   35,570   883,331 
             
Proved Developed Reserves:            
December 31, 2009  388,382   8,357   438,524 
December 31, 2010  412,644   14,813   501,521 
December 31, 2011  330,552   16,470   429,370 
             
Proved Undeveloped Reserves:            
December 31, 2009  388,283   18,030   496,463 
December 31, 2010  332,338   17,984   440,234 
December 31, 2011  339,361   19,100   453,961 


87


 Oil NGLs 
Natural
Gas
 
Total
Equivalents
Proved Developed and Undeveloped Reserves(MBbl) (MBbl) (MMcf) (MBOE)
December 31, 200911,517
 14,870
 776,665
 155,831
Revisions of previous estimates 1
(2,410) 7,611
 (71,421) (6,702)
Extensions, discoveries and other additions 2
513
 3,556
 90,439
 19,142
Production(710) (671) (38,919) (7,867)
Purchase of reserves9
 —
 3,288
 557
Sale of reserves in place(837) (653) (15,070) (4,002)
December 31, 20108,082
 24,713
 744,982
 156,959
Revisions of previous estimates 3
(2,367) (3,047) (61,165) (15,608)
Extensions, discoveries and other additions 4
9,669
 732
 56,345
 19,792
Production(1,283) (907) (33,410) (7,758)
Purchase of reserves20
 —
 1
 20
Sale of reserves in place(42) —
 (36,840) (6,182)
December 31, 201114,079
 21,491
 669,913
 147,223
Revisions of previous estimates 5
(439) (2,495) (154,372) (28,662)
Extensions, discoveries and other additions 6
13,444
 2,578
 13,405
 18,255
Production(2,252) (884) (20,261) (6,513)
Purchase of reserves39
 1
 6
 41
Sale of reserves in place(20) —
 (101,172) (16,882)
December 31, 201224,851
 20,691
 407,519
 113,462
Proved Developed Reserves: 
    
  
December 31, 20104,035
 10,778
 412,644
 83,587
December 31, 20117,075
 9,395
 330,552
 71,562
December 31, 201210,472
 8,266
 169,449
 46,980
Proved Undeveloped Reserves: 
    
  
December 31, 20104,047
 13,935
 332,338
 73,372
December 31, 20117,004
 12,096
 339,361
 75,661
December 31, 201214,379
 12,425
 238,070
 66,482
1
We had downward revisions of 161 Bcfe which were primarily the result of the following: 1) downward revisions of 63.1 Bcfe due to price, 2) a downward revision of 27.1 Bcfe in Appalachia for the removal of proved undeveloped reserves, which resulted from wells that no longer met the reasonable certainty threshold, 3) downward revisions of 20.1 Bcfe for NGLs that we received in East Texas as a result of lower plant yields and 4) various downward revisions amounting to 50.7 Bcfe across our assets as a result of well performance and the application of the revised oil and gas reserve calculation methodology required by the SEC in 2009.
2We added 235.7 Bcfe due to the drilling of 13 wells on locations that were not classified as proved undeveloped locations in our 2008 year-end reserve report and the addition of 105 new proved undeveloped locations, primarily in the Gulf Coast and Mid-Continent regions, as a result of our 2009 drilling activities.

3We had downward revisions of 40.2 Bcfe6.7 MMBOE primarily as a result of the following: 1) downward revisions of 45 Bcfe7.5 MMBOE due to the removal of 200 proved undeveloped locations that would not be developed within five years, 2) upward revisions of 34 Bcfe5.7 MMBOE as a result of processing the gas in the Mid-Continent Granite Wash for NGLs, 3) upward revisions of 12 Bcfe2.0 MMBOE due to higher prices and 4) various downward revisions for 39 Bcfe6.5 MMBOE across our assets as a result of well performance, lease expirations and interest changes.
42
We added 114.9 Bcfe19.1 MMBOE due to the drilling of 16 wells on locations not classified as proved undeveloped locations in our 20092010 year-end reserve report and the addition of 51 new proved undeveloped locations, primarily in East Texas, as a result of our 20102011 drilling activities.activities .
53
We had downward revisions of 93.6 Bcfe15.6 MMBOE primarily as a result of the following: 1) downward revisions of 72 Bcfe12.0 MMBOE due to well performance issues, interest changes and economic limits attributable to operating conditions particularly in the Granite Wash, Cotton Valley and Selma Chalk, 2) downward revisions of 10 Bcfe1.7 MMBOE due to lower condensate yield in the Granite Wash, 3) downward revisions  of 9 Bcfe1.5 MMBOE attributable to the elimination of proved undeveloped locations particularly in the Haynesville Shale in East Texas, 4) downward revisions of 5 Bcfe0.8 MMBOE due to lower natural gas prices and 5) upward revisions of 3 Bcfe0.5 MMBOE due to higher gas processing yields in the Haynesville Shale and Granite Wash.Wash .

64
We added 118.7 Bcfe19.8 MMBOE due primarily to an increase of 54 Bcfe9.0 MMBOE due to the drilling of three Marcellus Shale wells and two Granite Wash wells as well as the addition of 25 proved undeveloped locations in the Marcellus Shale and Selma Chalk. We also drilled 28 Eagle Ford Shale wells and added 26 proved undeveloped locations which resulted in an increase of 65 Bcfe.10.8 MMBOE .
5
We had downward revisions of 28.7 MMBOE primarily as a result of the following: 1) downward revisions of 5.0 MMBOE due to well performance issues, interest changes and economic limits due to operating conditions, including lease operating expense and basis differentials, primarily in the Selma Chalk, the Granite Wash, the Cotton Valley, and the Haynesville and Marcellus Shales, 2) downward revisions of 15.0 MMBOE due to lower natural gas prices which significantly reduced the number of proved undeveloped locations in the Marcellus Shale and Selma Chalk and 3) downward revisions of 8.7 MMBOE due to the removal of 38 proved undeveloped locations that would not be developed within five years primarily in the Selma Chalk, the Cotton Valley and the Haynesville Shale.

6
We added 18.3 MMBOE due primarily to the drilling of 18 wells and the addition of 48 proved undeveloped locations in the Eagle Ford Shale.



88


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves. Future cash inflows were computed by applying the average prices of oil and gas during the 12-month12-month period prior to the period end determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period and estimated costs as of that fiscal year end to the estimated future production of proved reserves. Natural gas prices were escalated only where existing contracts contained fixed and determinable escalation clauses. Contractually provided natural gas prices in excess of estimated market clearing prices were used in computing the future cash inflows only if we expect to continue to receive higher prices under legally enforceable contract terms. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

  Year Ended December 31, 
  2011  2010  2009 
Future cash inflows $5,032,915  $4,833,030  $4,178,449 
Future production costs  (1,374,658)  (1,388,857)  (1,300,235)
Future development costs  (1,091,100)  (879,193)  (888,493)
Future net cash  flows before income tax  2,567,157   2,564,980   1,989,721 
Future income tax expense  (665,751)  (687,928)  (491,832)
Future net cash flows  1,901,406   1,877,052   1,497,889 
10% annual discount for estimated timing of cash flows  (1,246,910)  (1,235,633)  (973,118)
Standardized measure of discounted future net cash flows $654,496  $641,419  $524,771 

 Year Ended December 31,
 2012 2011 2010
Future cash inflows$4,365,357
 $5,032,915
 $4,833,030
Future production costs(1,206,478) (1,374,658) (1,388,857)
Future development costs(1,118,859) (1,091,100) (879,193)
Future net cash  flows before income tax2,040,020
 2,567,157
 2,564,980
Future income tax expense(548,132) (665,751) (687,928)
Future net cash flows1,491,888
 1,901,406
 1,877,052
10% annual discount for estimated timing of cash flows(994,014) (1,246,910) (1,235,633)
Standardized measure of discounted future net cash flows$497,874
 $654,496
 $641,419

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves 

  Year Ended December 31, 
  2011  2010  2009 
Sales of oil and gas, net of production costs $(234,211) $(180,568) $(157,891)
Net changes in prices and production costs  (25,398)  180,316   (314,209)
Extensions, discoveries and other additions  361,284   59,729   138,482 
Development costs incurred during the period  44,741   153,563   65,043 
Revisions of previous quantity estimates  (113,188)  (50,471)  (158,844)
Purchases of reserves-in-place  308   2,239   - 
Sale of reserves-in-place  (37,474)  (47,740)  - 
Accretion of discount  87,815   68,817   90,796 
Net change in income taxes  16,818   (73,332)  15,168 
Other changes  (87,618)  4,095   116,825 
Net increase (decrease)  13,077   116,648   (204,630)
Beginning of year  641,419   524,771   729,401 
End of year $654,496  $641,419  $524,771 

 Year Ended December 31,
 2012 2011 2010
Sales of oil and gas, net of production costs$(254,388) $(234,211) $(180,568)
Net changes in prices and production costs(207,045) (25,398) 180,316
Extensions, discoveries and other additions355,495
 361,284
 59,729
Development costs incurred during the period119,706
 44,741
 153,563
Revisions of previous quantity estimates(196,152) (113,188) (50,471)
Purchases of reserves-in-place1,156
 308
 2,239
Sale of reserves-in-place(116,151) (37,474) (47,740)
Accretion of discount87,441
 87,815
 68,817
Net change in income taxes25,312
 16,818
 (73,332)
Other changes28,004
 (87,618) 4,095
Net increase (decrease)(156,622) 13,077
 116,648
Beginning of year654,496
 641,419
 524,771
End of year$497,874
 $654,496
 $641,419

The standardized measure of discounted future net cash flows is not intended, and should not be interpreted, to represent the fair value of our oil and gas reserves. An estimate of the fair value would also consider, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and cost, and a discount factor more representative of economic conditions and risks inherent in reserve estimates. Accordingly, the changes in standardized measure reflected above do not necessarily represent the economic reality of such transactions. See “Costs Incurred in Certain Oil and Gas Activities” earlier in this Note and our Consolidated Statements of Cash Flows.

Item 9Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.




89


Item 9A9Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.

Item 9A
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 December 31, 2011.2012. 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 December 31, 2011,2012, such disclosure controls and procedures were effective.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

Our management, including our Chief Executive Officer and our Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over our financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2011.2012. This evaluation was completed based on the framework established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Our management has concluded that, as of December 31, 2011,2012, our internal control over financial reporting was effective.

(c) Attestation Report of the Registered Public Accounting Firm

KPMG LLP, an independent registered public accounting firm, has issued an attestation report on the internal control over financial reporting as of December 31, 2011,2012, which is included in Item 8 of this Annual Report on Form 10-K.

(d) Changes in Internal Control Over Financial Reporting

No changes were made in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


Item 9B
Other Information


There was no information that was required to be disclosed by us on a Current Report on Form 8-K during the fourth quarter of 20112012 which we did not disclose.


90


Part III


Item 10
Directors, Executive Officers and Corporate Governance


In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.


Item 11
Executive Compensation

In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.


Item 12Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters


In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.


Item 13Certain Relationships and Related Transactions, and Director Independence


In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.


Item 14
Principal Accountant Fees and Services

In accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 


91


Part IV


Item 15
Exhibit and Financial Statement Schedules

The following documents are filed as exhibits to this Annual Report on Form 10-K: 

(1)Financial Statements — The financial statements filed herewith are listed in the Index to Consolidated Financial Statements on page 5056 of this Annual Report on Form 10-K.
  
(2.1)Purchase and Sale Agreement, dated July 28, 2011, by and 16, 2012,among Penn Virginia MC Energy L.L.C., Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and Unit Petroleum Company, as amended by Amendment and Supplement to Purchase and Sale Agreement dated August 31, 2011EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on September 7, 2011)July 18, 2012).
(2.1.1)

Amendment and Supplement to Purchase and Sale Agreement, dated July 31, 2012,among Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on August 2, 2012).
  
(3.1)Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999).
  
(3.1.1)

Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999).
  
(3.1.2)

Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3 to Registrant’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).
  
(3.1.3)

Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on June 12, 2007).
  
(3.1.4)

Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on May 10, 2010).
  
(3.1.5)

Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on October 17, 2012).
(3.2)Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on February 18, 2011)20, 2013).
  
(4.1)Subordinated Indenture dated December 5, 2007 among Penn Virginia Corporation, as Issuer, the Subsidiary Guarantors named therein, and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on December 5, 2007).
(4.1.1)First Supplemental Indenture relating to the 4.50% Convertible Senior Subordinated Notes due 2012, dated December 5, 2007 between Penn Virginia Corporation, as Issuer, and Wells Fargo Bank, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on December 5, 2007).
(4.1.2)Form of Note for 4.50% Convertible Senior Subordinated Notes due 2012 (incorporated by reference to Exhibit A to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on December 5, 2007).
(4.2)Senior Indenture dated June 15, 2009 among Penn Virginia Corporation, as Issuer, the Subsidiary Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on June 16, 2009).
  
(4.2.1)(4.1.1)First Supplemental Indenture relating to the 10.375% Senior Notes due 2016, dated June 15, 2009, among Penn Virginia Corporation, as Issuer, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K/A filed on June 18, 2009).
  
(4.2.2)(4.1.2)Second Supplemental Indenture relating to the 10.375% Senior Notes due 2016, dated April 4, 2011, among Penn Virginia Corporation, as Issuer, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on April 5, 2011).
  
(4.2.3)(4.1.3)Form of Note for 10.375% Senior Notes due 2016 (incorporated by reference to Annex A to Exhibit 4.1 to Registrant’s Current Report on Form 8-K/A filed on June 18, 2009).
  
(4.2.4)(4.1.4)Third Supplemental Indenture relating to the 7.25% Senior Notes due 2019, dated April 13, 2011, among Penn Virginia Corporation, as Issuer, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 14, 2011).
  
(4.2.5)(4.1.5)Form of Note for 7.25% Senior Notes due 2019 (incorporated by reference to Annex A to Exhibit 4.3 to Registrant’s Current Report on Form 8-K filed on April 14, 2011).
  
(10.1)(4.2)Amended and Restated CreditDeposit Agreement, dated as of August 2, 2011October 17, 2012, among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent,American Stock Transfer & Trust Company, LLC and the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agentholders from time to time of the depositary shares described therein (incorporated by reference to Exhibit 10.14.1 to Registrant’sRegistrant's Current Report on Form 8-K filed on August 4, 2011)October 17, 2012).
(10.1.2)First Amendment
(4.2.1)Form of depositary receipt representing the Depositary Shares (incorporated by reference to Amended and Restated Exhibit A to Exhibit 4.1 to Registrant's Current Report on Form 8-K filed on October 17, 2012).
(10.1)Credit Agreement dated January 11,as of September 28, 2012 among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the lenders party thereto and JPMorgan ChaseWells Fargo Bank, N.A.,National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on January 17,October 2, 2012).

92


(10.2)Contribution Agreement dated June 7, 2010 by and among Penn Virginia Resource GP Corp., Penn Virginia GP Holdings, L.P. and PVG GP, LLC (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on June 7, 2010).
(10.4)Penn Virginia Corporation Supplemental Employee Retirement Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on October 29, 2007).*
  
(10.4.1)(10.2.1)Amendment 2009-1 to the Penn Virginia Corporation Supplemental Employee Retirement Plan.Plan (incorporated by reference to Exhibit 10.4.1 to Registrant's Annual report on Form 10-K for the year ended December 31, 2011).*
  
(10.5)(10.3)Penn Virginia Corporation Amended and Restated Non-Employee Directors Deferred Compensation Plan (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on October 29, 2007).*
  
(10.5.1)(10.3.1)Amendment One to the Penn Virginia Corporation Amended and Restated Non-Employee Directors Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on May 6, 2011).*
  
(10.6)(10.4)Penn Virginia Corporation Fifth Amended and Restated 1995 Directors’ Compensation Plan (incorporated by reference to Exhibit 10.29 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). *
  
(10.6.1)(10.4.1)Form of Agreement for Deferred Common Stock Unit Grants under the Penn Virginia Corporation Fifth Amended and Restated 1995 Directors’ Compensation Plan (incorporated by reference to Exhibit 10.30 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).*
  
(10.7)(10.5)Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on August 2, 2010).*
  
(10.7.1)(10.5.1)Amendment No. 1 to the Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on May 6, 2011).*
  
(10.7.2)(10.5.2)Form of Agreement for Stock Option Grants under the Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.6 to Registrant’s Current Report on Form 8-K filed on October 29, 2007).*
  
(10.7.3)(10.5.3)Form of Agreement for Restricted Stock Awards under the Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.33 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).*
  
(10.7.4)(10.5.4)Form of Agreement for Restricted Stock Unit Awards under the Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on February 23, 2009).*
  
(10.8)(10.5.5)Executive ChangeForm of Control Severance Agreement dated October 17, 2008 betweenfor Performance Based Restricted Stock Unit Awards under the Penn Virginia Corporation Seventh Amended and Nancy M. SnyderRestated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.310.1 to Registrant’s Current Report on Form 8-K filed on October 22, 2008)February 23, 2012).*
  
(10.9)(10.6)Amended and Restated Executive Change of Control Severance Agreement dated October 17, 2008December 20, 2012 between Penn Virginia Corporation and H. Baird Whitehead (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed on October 22, 2008).*
(10.10)Executive Change of Control Severance Agreement dated December 8, 2010 between Penn Virginia Corporation and Steven A. Hartman (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on December 10, 2010)21, 2012).*
  
(10.11)(10.7)Amended and Restated Executive Change of Control Severance Agreement dated October 26, 2011 between Penn Virginia Corporation and John A. Brooks. *
(10.12)Executive Change of Control Severance Agreement dated October 17, 2008 between Penn Virginia Corporation and Michael E. Stamper. *

(10.13)Amended and Restated Change of Location Severance Agreement dated March 30, 2010December 20, 2012 between Penn Virginia Corporation and Nancy M. Snyder (incorporated by reference to Exhibit 10.110.2 to Registrant’s Current Report on Form 8-K filed on March 31, 2010)December 21, 2012).*
  
(10.14)(10.8)Amended and Restated Executive Change of Control Severance Agreement dated December 20, 2012 between Penn Virginia Corporation and Steven A. Hartman (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed on December 21, 2012).*
(10.9)Executive Change of Control Severance Agreement dated January 29, 2013 between Penn Virginia Corporation and John A. Brooks (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on February 1, 2013). *
(10.10)Amended and Restated Change of Location Severance Agreement dated December 20, 2012 between Penn Virginia Corporation and Nancy M. Snyder (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed on December 21, 2012).*
(10.11)Penn Virginia Corporation 2011 Annual Incentive Cash Bonus and Long-Term Equity Compensation Guidelines (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K/A filed on February 7, 2013).*
(10.12)Confidential Severance Agreement and Release dated August 31, 2012 between Penn Virginia Corporation and Michael E. Stamper (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on March 1, 2011)September 5, 2012).*
  
(12.1)Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.


93


(14.1)Penn Virginia Corporation Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 to Registrant’s Current Report on Form 8-K filed on July 27, 2009).
(21.1)Subsidiaries of Penn Virginia Corporation.
  
(23.1)Consent of KPMG LLP.
  
(23.2)Consent of Wright & Company, Inc.
  
(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.
  
(99.1)Report of Wright & Company, Inc. dated January 20, 201218, 2013 concerning evaluation of oil and gas reserves.
  
(101.INS)XBRL Instance Document
  
(101.SCH)XBRL Taxonomy Extension Schema Document
  
(101.CAL)XBRL Taxonomy Extension Calculation Linkbase Document
  
(101.DEF)XBRL Taxonomy Extension Definition Linkbase Document
  
(101.LAB)XBRL Taxonomy Extension Label Linkbase Document
  
(101.PRE)XBRL Taxonomy Extension Presentation Linkbase Document
_________________________

*Management contract or compensatory plan or arrangement.




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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


 PENN VIRGINIA CORPORATION
  
February 27, 2012 By:/s/ StevenSTEVEN A. HartmanHARTMAN
  Steven A. Hartman 
  Senior Vice President and Chief Financial Officer
   
February 27, 2012 25, 2013By: /s/ JoanJOAN C. SonnenSONNEN
  Joan C. Sonnen 
  Vice President and Controller


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

/s/ EDWARD B. CLOUES, II Chairman of the Board and Director February 27, 201225, 2013
Edward B. Cloues, II     
     
/s/John JOHN U. ClarkeCLARKE Director February 27, 201225, 2013
John U. Clarke 
/s/ ROBERT GARRETTDirectorFebruary 27, 2012
Robert Garrett    
     
/s/ STEVEN W. KRABLIN Director February 27, 201225, 2013
Steven W. Krablin     
     
/s/ MARSHA R. PERELMAN Director February 27, 201225, 2013
Marsha R. Perelman     
     
/s/ PHILIPPE VAN MARCKE DE LUMMEN Director February 27, 201225, 2013
Philippe van Marcke de Lummen     
     
/s/ H. Baird WhiteheadBAIRD WHITEHEAD Director and President and Chief Executive Officer February 27, 201225, 2013
H. Baird Whitehead     
     
/s/ GARY K. WRIGHT Director February 27, 201225, 2013
Gary K. Wright     

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