BAYTEX ENERGY USA, INC. - Annual Report: 2011 (Form 10-K)

   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

Commission file number: 1-13283

  Penn Virginia Corporation

(Exact name of registrant as specified in its charter)

 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:

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  ¨

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  x

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  x    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  x  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)

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

The aggregate market value of common stock held by non-affiliates of the registrant was $599,073,526 as of June 30, 2011 (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, 45,714,191 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, 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

Table of Contents

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 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:

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.

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.

Part I

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 natural gas and oil in various domestic onshore regions of the United States including Texas, Appalachia, the Mid-Continent and Mississippi.

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 completed the process of our transformation into a “pure play” exploration and production (E&P) company. Our Consolidated Financial Statements and Notes present 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 on oil and NGL investment opportunities rather than natural gas. During 2011, we grew our oil and NGL production to 28% (37% for the 4^th quarter of 2011) of our total production, an increase of approximately 59% over 2010, and we invested approximately $390 million in oil 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 oil and NGL-rich areas.

As of December 31, 2011, our proved reserves were approximately 883 Bcfe, of which 49% were proved developed reserves. Our operations currently include primarily unconventional developmental drilling opportunities and exploratory prospects. We believe our emerging presence in the Eagle Ford Shale provides us opportunities for continued oil and NGL-focused investments over the next several years.

Our proved reserves and primary development plays are located in Texas, Appalachia, the Mid-Continent and Mississippi, which comprised 53%, 17%, 11% and 19% of our total proved reserves as 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. For a more detailed discussion of our reserves and production, see Item 2, “Properties.”

In 2011, our capital expenditures were $446.7 million, of which $307.8 million, or 69%, was related to development drilling, $64.1 million, or 14%, was related to exploratory drilling 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.

As 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.

Business Strategy

We intend to pursue the following business strategies:

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

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.

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 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.

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 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. 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 to subject hydraulic fracturing operations to federal regulation 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 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 water quality and public health, and a committee of 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.

Further, in light of the explosion and fire 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, there have been a variety of regulatory initiatives at both the federal and state levels to restrict oil and gas drilling operations in certain locations. For example, Pennsylvania has instituted a moratorium on leasing forest land for gas drilling. 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. 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, the EPA issued proposed rules that would subject 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 currently subject to Maximum Achievable Control Technology, or MACT, standards. We are currently researching the effect these proposed rules could 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. Were we 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 as a major source for MACT applicability.

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.

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 gases per year to collect and report to the EPA data regarding such emissions. The Reporting Rule establishes a new comprehensive scheme, beginning 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’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’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 rules are currently subject to judicial challenge, but the D.C. Circuit has refused to stay their implementation while the challenges are pending.

As of July 1, 2011, the EPA requires 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, the EPA issued its plan to update pollution standards for fossil fuel 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 standards in May 2012 and November 2012, respectively. As of early December 2011, the EPA reportedly has prepared a proposal to regulate 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.

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 enacted to address GHG emissions would impact our business, the modification of existing laws or regulations, or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States in which we operate could 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 oil and gas.

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 requires maintenance 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 153 employees as of December 31, 2011. 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 is http://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.

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 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 and NGLs. Historically, gas and oil prices have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas, crude oil and NGL prices may result from relatively minor changes in the supply of and demand for gas and oil, market demand and other factors that are beyond our control, including:

Some of our projections and estimates are based on assumptions as to the future prices of gas and oil. 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 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 gas and oil 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 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 from such activities at acceptable costs. Currently depressed gas prices may further limit the types of reserves that can be developed at acceptable costs. 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.

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, we anticipate making capital expenditures, excluding acquisitions, of up to approximately $325 million.

If oil prices decrease, 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 the capital we can spend unless we have borrowing capacity under our Revolver, or we can raise additional funds through asset sales or a debt or equity financing.

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 oil and natural gas.

If our revenues were to decrease due to lower oil and 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.

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

The borrowing base under our Revolver is $380 million as of December 31, 2011. Our borrowing base is re-determined twice a year and is scheduled to be redetermined during April 2012. Due primarily to depressed natural gas prices and a decrease in our proved developed reserves, we anticipate that the borrowing base may be materially reduced. As a result, we may be unable to obtain adequate funding under our 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.

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 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:

The prevailing prices of oil and 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 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 affect on our ability to develop and produce oil and 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.

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’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of revenues. In 2011, 58% of our total consolidated product revenues resulted from five of our customers. Any nonpayment or nonperformance by our customers would reduce our cash flows.

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:

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 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:

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. 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 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 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 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 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 oil 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, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and 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 oil and gas prices and other factors, many of which are beyond our control.

At December 31, 2011, approximately 51% 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.

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 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 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 oil and 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. 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 and NGL 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, other companies operated approximately 23% 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’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 oil and 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 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.

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 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—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. 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 have adopted, and other states are considering 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 or prohibited, it 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 oil and natural gas, we periodically enter into oil and gas 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 oil and natural gas prices, such transactions may limit our potential gains if oil 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 oil 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:

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.

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 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 domestic production activities 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.

We have received no written SEC staff comments regarding our periodic or current reports under the Exchange Act which were issued 180 days or more preceding the end of our 2011 fiscal year that remain unresolved.

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

Facilities

We are headquartered in Radnor, Pennsylvania, with regional offices in Pittsburgh, Pennsylvania and Houston, Texas. We also have district operations facilities at various locations in Texas, Oklahoma, Mississippi, Pennsylvania and West Virginia. All of our office facilities are leased with the exception of our district operations facilities in Scottsville, Texas and Ravencliff, West Virginia. 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 to 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.

Preparation of Reserves Estimates

Our policies and practices regarding the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves 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 26 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 state of Texas as a Professional Engineer. The Company’s 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.”

Summary of Oil and Gas Reserves

Proved Reserves

The following tables present certain information regarding our proved reserves as of December 31, 2011, 2010 and 2009. 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 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, 2011 with any federal authority or agency with respect to our estimate of oil and gas reserves.

¹ Natural gas and oil prices were based on average (beginning of month basis) sales prices per Mcf and Bbl with the representative price of natural gas adjusted for basis premium and energy content to arrive at the appropriate net price.

All of our reserves are located in the continental United Sates. 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:

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:

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:

As of December 31, 2011, our proved undeveloped reserves increased to 454 Bcfe from 440 Bcfe as of December 31, 2010. We experienced performance-related revisions of approximately 38 Bcfe, including downward revisions of 20 Bcfe 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 prices and locations that are not expected to be developed during a five-year period. During 2011, we had proved undeveloped reserve 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 NGLs in the Eagle Ford Shale in Texas. We had a decrease of 9 Bcfe due to the sale of substantially all of our properties, including proved undeveloped locations, in the Arkoma Basin. Finally, we converted approximately 15 Bcfe, primarily in the Granite Wash, to proved developed reserves.

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

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:

¹ We sold a substantial portion of our Arkoma Basin properties in August 2011, which represented estimated annual production of approximately 4 Bcfe.

² We 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:

Drilling Activities

Wells Drilled

The following table sets forth the gross and net exploratory and development wells that we drilled during the years ended December 31, 2011, 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.

The following table sets forth the regions in which we drilled our wells for the periods presented:

Present Activities

As of December 31, 2011, we had seven gross (5.8 net) wells in progress, all of which were located in the Eagle Ford Shale play in South Texas. As of February 21, 2011, six of these wells were successfully completed and placed on production and the remaining well is waiting on completion. Our two (1.3) net wells under evaluation are located in the Marcellus Shale in Pennsylvania.

Delivery Commitments

We generally sell our 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, we did not have any material commitments to provide a fixed and determinable quantity of our natural gas, crude oil or NGL production beyond the current month.

Productive Wells

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

Of the total wells presented in the table above, we are the operator of 1,503 gross (1,465 gas and 38 oil) and 1,358.7 net (1,328.1 gas and 30.6 oil) wells. In addition to the above working interest wells, we own royalty interests in 2,884 gross wells.

Acreage

The following table sets forth our developed and undeveloped acreage as of December 31, 2011 (in thousands):

Our acreage is located in Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States. The primary terms of our leases generally range from three to five years and we do not have any concessions. As of December 31, 2011, 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:

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 position in Appalachia in which we hold a 25% interest; we have no remaining capitalized costs related to this lease. 

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.

Part II

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 2011 and 2010 were as follows:

Equity Holders

As of February 10, 2012, there were 453 record holders and approximately 6,330 beneficial owners (held in street name) of our common stock.

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, there were nine companies in the Standard & Poor’s 600 Oil & Gas Exploration & Production Index: Approach Resources Inc., Contango Oil & Gas Company, GeoResources Inc., Gulfport Energy Corporation, Penn Virginia Corporation, Petroleum Development Corporation, Petroquest Energy Inc., Stone Energy Corporation and Swift Energy Company. The graph assumes $100 is invested on January 1, 2007 in us and each index at December 31, 2006 closing prices.

The following selected historical financial information was derived from our Consolidated Financial Statements as of and for the years ended December 31, 2011, 2010, 2009, 2008 and 2007. 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.”

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 2011, 2010, 2009, 2008 and 2007 included impairment charges of $104.7 million, $46.0 million, $106.4 million, $20.0 million and $2.6 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.

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 natural gas and oil in various domestic onshore regions. We have a geographically diverse asset base with areas of operations in Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States. As of December 31, 2011, we had proved natural gas and oil reserves of approximately 883 Bcfe. Our operations include primarily the drilling of unconventional development wells and exploring for new exploitable resources.

We are currently primarily focused on the Eagle Ford Shale in South Texas. During 2011, we brought on line approximately 30 gross wells in this play. In 2011, we also pursued selected drilling opportunities in the horizontal Granite Wash play in our 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:

¹ As reduced by outstanding borrowings and letters of credit.

Key Developments

During 2011, the following general business developments and corporate actions had an impact on our results of operations and financial position: (i) drilling results in the Eagle Ford Shale, Granite Wash and Marcellus Shale plays, (ii) acquiring properties in the Eagle Ford Shale play, (iii) selling our Arkoma Basin assets and related restructuring activities, (iv) entering into a new five-year revolving credit facility, or the Revolver, and (v) offering and selling $300 million of our 7.25% Senior Notes due 2019, or 2019 Senior Notes, together with the tender offer to repurchase our 4.50% Convertible Senior Subordinated Notes due 2012, or the Convertible Notes.

Drilling Results and Future Development Plans

During 2011, we drilled a total of 39.9 net wells, including 26.7 net wells in the Eagle Ford Shale, 8.9 net wells in the Mid-Continent region, primarily in the Granite Wash, and 4.3 net wells in the Marcellus Shale.

We currently have three rigs drilling in the Eagle Ford Shale. We have drilled a total of 39 wells since we began operations in this play during the second half of 2010. Of the total wells drilled, 35 (29.2 net) wells are producing, one is waiting on completion and three are in progress as of February 22, 2012. The producing wells have had an average peak gross production rate of approximately 1,000 BOEPD per well. Eagle Ford Shale production was approximately 9,800 (6,280 net) BOEPD at the end of January 2012, with oil comprising approximately 89 percent, NGLs comprising approximately six percent and natural gas comprising approximately five percent. We expect to continue drilling in this play for the remainder of 2012 and beyond. We have allocated approximately 85% of our capital expenditures during 2012 for activities in the Eagle Ford Shale.

In the Mid-Continent region, we successfully drilled and completed 6.2 net development wells in the Granite Wash during 2011. We plan to continue our Granite Wash development program, primarily as a non-operator. Our exploratory program 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.

In 2011, we drilled five gross (4.3 net) and completed three horizontal test wells 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 net Eagle Ford Shale acres 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. We are the operator of the combined Gonzales County acreage with an average working interest of approximately 81%.

In December 2011, we entered into an agreement with a major oil and gas company to jointly explore 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 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, 2012 to earn our entire interest 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 portion of our Arkoma Basin assets for approximately $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 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 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 exit 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.

Completion of a New Credit Facility

In August 2011, we entered into the Revolver which provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. At December 31, 2011, the Revolver had a borrowing base of $380 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 of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The permitted leverage ratio (net debt divided by EBITDAX, as defined in the Revolver) is 4.5 through periods ending on or before June 30, 2013, after which it will be 4.0.

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 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 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. 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 and debt issuance costs. We used $237.1 million of the proceeds to repurchase approximately 98% of the Convertible Notes plus accrued interest, and we have a total of $4.9 million (principal amount) of Convertible Notes currently outstanding. We used the remainder of the proceeds to provide working capital for general corporate purposes, including capital expenditures.

Results of Operations

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:

Production

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

The decline in total production during 2011 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 of our Arkoma Basin properties. The effect of the sale of the Arkoma Basin properties was approximately 2 Bcfe. 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 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 represented approximately 11% of our total production. We had no production from this play in 2010.

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: