Penn Virginia 10-K 2011
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
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 o
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 $905,899,755 as of June 30, 2010 (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 18, 2011, 45,594,907 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, 2011, is 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, 2010
Table of Contents
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.
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 is 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. On June 7, 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.
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
The year 2010 was transformational for us. We transitioned to a “pure play” E&P company, and we began, and are continuing, to refocus our operations to drill in economically attractive natural gas, oil and NGL-rich areas. To this end, we disposed of our Gulf Coast assets and exited this area, invested over $150 million to increase our leaseholds in potentially higher return prospects in the Mid-Continent and the Marcellus Shale and to establish a position in the oil rich Eagle Ford Shale. We have also suspended drilling on our acreage located in east Texas and Mississippi, which is primarily lower return, dry gas and held by production, with the option to resume drilling there when natural gas prices justify renewed investment.
As of December 31, 2010, we had proved natural gas and oil reserves of approximately 942 Bcfe, of which 79% were natural gas and 53% were proved developed. Our operations include both conventional and unconventional developmental drilling opportunities, as well as some exploratory prospects. We believe our emerging presence in several key plays, as discussed below, positions us for meaningful growth over the next several years.
As of December 31, 2010, our proved reserves and primary development plays were located in somewhat longer-lived, lower-risk core basins in Texas, Appalachia, the Mid-Continent and Mississippi, which comprised 48%, 13%, 20% and 19%, respectively, of our total proved reserves. In 2010, we produced 47.2 Bcfe, compared to 51.0 Bcfe in 2009 primarily reflecting the sale of our Gulf Coast properties in the first quarter of the year. Texas, Appalachia, the Mid-Continent, Mississippi and the Gulf Coast comprised 29%, 22%, 32%, 16% and 1% of total production volumes during 2010. In the three years ended December 31, 2010, we drilled 386 gross (244.7 net) wells, of which 92% were successful in producing natural gas, oil and NGLs in commercial quantities. For a more detailed discussion of our reserves and production, see Item 2, “Properties.”
We have grown our reserves and production primarily through development and exploratory drilling, complemented to a lesser extent by making strategic acquisitions. During 2010, we replaced approximately 260% of our 2010 production by adding net proved reserves of approximately 122 Bcfe from extensions, discoveries, additions and purchases of reserves, net of other revisions. In 2010, our capital expenditures were $451.2 million, of which $243.4 million, or 54%, was related to development drilling and $140.5 million, or 31%, was related to leasehold acquisitions. The remaining $67.3 million, or 15%, was related to exploration drilling, pipelines, gathering and facilities.
As of December 31, 2010, we owned 1.2 million net acres of leasehold interests, approximately 26% 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 our existing undeveloped acreage position represents over 10 years of drilling opportunities based on our historical drilling rate.
We intend to pursue the following business strategies:
We have entered into contracts which 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.
We generally sell our natural gas using short-term fixed price physical and spot market contracts. For the year ended December 31, 2010, approximately 59% of our consolidated product revenues resulted from four of our customers, Connect Energy Services, LLC, a subsidiary of PVR, Chesapeake Operating, Inc., Enogex, LLC and Dominion Field Services, Inc.
Commodity Derivative Contracts
We generally utilize costless collar and swap 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 contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. The counterparty to a swap contract is required to make a payment to us if the settlement price for any settlement period is greater than the swap price for such contracts, and we are required to make a payment to the counterparty if the settlement price is less than the swap price for such contract.
We determine the fair values of our oil and gas derivative agreements 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 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 and oil and gas reserves. Our competitive position depends on our geological, geophysical and engineering expertise, our financial resources and our ability to select, acquire and develop properties. 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 recruiting and retaining qualified personnel, including geologists, geophysicists, engineers and other specialists. 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 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 persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” 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, and 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 potentially could 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 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 EPA, the individual states administer some or all of the provisions of the RCRA. While there is currently an exclusion from the 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 the RCRA.
Oil Pollution Act. The Oil Pollution Act of 1990, as amended, or 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 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.
Safe Drinking Water Act. The Safe Drinking Water Act, or SDWA, and the Underground Injection Control Program promulgated under the SDWA, establishes the requirements for salt water disposal well activities and prohibits 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 Granite Wash, Eagle Ford Shale, Haynesville Shale and the Marcellus Shale formations. The U.S. Congress is currently considering legislation to amend the SDWA to subject hydraulic fracturing operations to 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 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, delaying 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 of 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, the Governor of Pennsylvania has instituted a moratorium on leasing forest land for gas drilling. Additionally, the New York State Department of Environmental Conservation has ceased issuing exploration and production drilling permits, pending completion of an environmental impact statement regarding hydraulic fracturing. We use hydraulic fracturing extensively and any increased federal, state or local regulation of hydraulic fracturing, including legislation and regulation in Pennsylvania, could reduce the volumes of oil and natural gas that we can economically recover.
Clean Air Act. Our operations are subject to the Clean Air Act, or 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 ("TCEQ") 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, EPA has committed, pursuant to the terms of a federal Consent Decree, to evaluate the need for new or revised New Source Performance Standards for Crude Oil and Natural Gas Production facilities, along with National Emission Standards for Hazardous Air Pollutants and Residual Risk Standards for Oil and Natural Gas Production and Natural Gas Transmission and Storage facilities. If the EPA chooses to issue new standards it must finalize them by November 30, 2011.
Greenhouse Gas Emissions. There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing effect of greenhouse gas, or GHG, emissions. On September 22, 2009, the EPA issued a "Mandatory Reporting of Greenhouse Gases" final rule, or Reporting Rule, which was subsequently amended on July 20, 2010. 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 facilities, natural gas processing, transmission, distribution and storage facilities. In addition, on December 15, 2009, the EPA published a Final Rule, also known as the EPA's Endangerment Finding, finding that current and projected concentrations of six key GHGs in the atmosphere threaten the environment and public health and the welfare of current and future generations. Following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle GHG emission standards under the Clean Air Act on April 1, 2010 that will require reduction in emissions of GHGs from motor vehicles beginning in 2011, the effect of which could reduce demand for motor fuels refined from crude oil. Also, on May 13, 2010, the EPA issued a prepublication version of a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act's Prevention of Significant Deterioration ("PSD") and Title V programs. This final rule "tailors" the PSD and Title V programs to apply to certain stationary sources of GHG emissions, to be phased in through a multistep process, with the largest sources being subject to permitting first. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet "best available control technology" standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. In November 2010, the EPA issued guidance on GHG best available control technology that will assist the various agencies in making these determinations.
The U.S. Congress is currently considering a number of legislative proposals to restrict GHG emissions and more than 20 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 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 202 employees as of December 31, 2010. We consider our current employee relations to be favorable.
Common Abbreviations and Definitions
The following are abbreviations and definitions commonly used in the oil and gas industries that are used in this Annual Report on Form 10-K.
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 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 Securities and Exchange Commission. 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 and crude oil. Historically, natural gas and crude oil prices have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas and crude oil prices may result from relatively minor changes in the supply of and demand for oil and gas, 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 natural gas and crude 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 financial position and results of operations (including reduced cash flows and borrowing capacity and possible asset impairment), the quantities of natural gas and crude 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. The currently depressed oil and 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 remain limited or unavailable due to the deterioration of the global economy, including financial and credit markets. 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, exploit and produce oil and natural gas reserves. In 2011, we anticipate making capital expenditures, excluding acquisitions, of approximately $320 million.
If oil and gas prices decrease 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 the Revolver, or we can raise additional funds through 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 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.
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 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. 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 results of operations, cash flows or financial condition. 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 2010, 59% of our total consolidated product revenues resulted from four of our customers. Any nonpayment or nonperformance by our customers would reduce our cash flows.
Our business involves many operating risks 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. 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.
In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. 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. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our business, results of operations or financial condition.
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, 2010, approximately 47% 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 2010, other companies operated approximately 27% 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.
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.
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. 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.”
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 new 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 CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed 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 finalize these regulations. The financial reform legislation 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 financial reform legislation 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 us, our financial condition and our results of operations.
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 2010 fiscal year that remain unresolved.
Title to Properties
The following map shows the general locations of our oil and gas production and exploration and related infrastructure investments as of December 31, 2010:
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.
We are headquartered in Radnor, Pennsylvania, with regional offices in Tulsa, Oklahoma; Pittsburgh, Pennsylvania; and Houston, Texas. We also have regional operations facilities at various locations in Mississippi, Oklahoma, Pennsylvania, Texas and West Virginia. All of our office facilities are leased with the exception of our operations facility in West Virginia. We believe that our facilities are adequate for our current needs.
Oil and Gas Properties
Prior to completing an acquisition of producing oil and gas assets, we obtain or 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 remedy or 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 current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties.
The following table presents certain information regarding our proved reserves as of December 31, 2010, 2009 and 2008. 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, 2010 with any federal authority or agency with respect to our estimate of oil and gas reserves.
Reserve engineering is a subjective 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 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 may all differ from those assumed in these estimates. Therefore, the standardized measure amounts shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth in the foregoing tables includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in commodity prices.
Our policies and practices regarding internal controls over 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 Company’s reserve estimate by our independent third party engineers, Wright & Company, Inc. The Manager of Engineering has over 24 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.”
Production and Reserves by Region
The following tables set forth by region the estimated quantities of proved reserves, as well as the average daily production and total production for the periods presented:
1 We completed the sale of our Gulf Coast properties in a transaction that closed on January 29, 2010.
The following table sets forth our developed and undeveloped acreage as of December 31, 2010. The acreage is located primarily in Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States.
The following table sets forth the gross and net numbers of exploratory and development wells that we drilled during the years ended December 31, 2010, 2009 and 2008. The number of wells drilled refers to the number of wells reaching total depth at any time during the respective year. Net wells equal the number of gross wells multiplied by our working interest in each of the gross wells. Productive wells represent either wells that were producing oil or gas or were capable of commercial production.
The following table sets forth the number of productive oil and gas wells in which we had a working interest as of December 31, 2010.
In addition to the above working interest wells, we own royalty interests in 2,911 gross wells.
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.
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 2010 and 2009 were as follows:
As of February 11, 2011, there were 464 record holders and approximately 6,200 beneficial owners (held in street name) of our common stock.
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. There are seven companies in the Standard & Poor’s 600 Oil & Gas Exploration & Production Index: Contango Oil & Gas Company, 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, 2006 in us and each index at December 31, 2005 closing prices.
The following selected historical financial information was derived from our Consolidated Financial Statements as of and for the years ended December 31, 2010, 2009, 2008, 2007 and 2006. The selected financial data should be read in conjunction with our Consolidated Financial Statements and the accompanying Notes and Supplementary Data in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 8, “Financial Statements and Supplementary Data.”
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 Supplementary 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 primarily in the exploration, development and production of natural gas and oil in various domestic onshore regions. We have a geographically diverse asset base with core areas of operations in Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States. As of December 31, 2010, we had proved natural gas and oil reserves of approximately 942 Bcfe. Our operations include both conventional and unconventional development drilling opportunities, as well as some exploratory prospects.
The primary development play type that we focused on in 2010 was the horizontal Granite Wash play in Mid-Continent. We have expanded development drilling with our recent acquisition of properties in the Eagle Ford Shale play in Texas, and we intend to focus on drilling exploratory wells in the Marcellus Shale play in Appalachia to determine whether our leasehold acreage position will support a development program.
The following table sets forth certain summary operating and financial statistics for the periods presented:
During 2010, the following general business developments and corporate actions had an impact upon the financial reporting of our results of operations and financial position as well as the overall presentation of financial information: (i) the complete divestiture of our interests in PVG, (ii) significant leasehold acquisitions of properties in the Eagle Ford and Marcellus Shale plays, (iii) execution of a fracturing services agreement for well completion activities, (iv) the completion of our organization restructuring that was announced in the fourth quarter of 2009 and (v) disposition of our Gulf Coast properties.
Divestiture and Deconsolidation of PVG
Prior to June 2010, we indirectly owned partner interests in Penn Virginia Resource Partners, L.P., or PVR, which is engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in PVR were held primarily through our general and limited partner interests in PVG. In June 2010, we completed the sale of our remaining limited partner interests in PVG in a secondary public offering for proceeds of approximately $139 million, net of offering costs. In a related transaction, we disposed of 100% of the membership interest in PVG’s general partner, thereby relinquishing control of PVG. As a result of these transactions, we recognized a gain of $51.5 million, net of taxes, during the three months ended June 30, 2010 and have deconsolidated PVG from our Consolidated Financial Statements. The results of operations attributable to PVG through the date of these transactions and prior periods have been presented as discontinued operations in our Consolidated Financial Statements. Since September 2009, we sold an aggregate of approximately 30.1 million common units of PVG for approximately $450 million in net pre-tax proceeds. Additional information is provided in the Liquidity and Capital Resources discussion that follows.
In August 2010, we acquired approximately 6,800 net acres in the Eagle Ford Shale play in Texas for approximately $31.1 million. The acreage includes over 40 potential horizontal well locations. We are the operator with a working interest of approximately 75% and a net revenue interest of approximately 57%. We recently announced a second Eagle Ford Shale acquisition of approximately 4,100 net acres with approximately 40 horizontal well locations for $14.5 million. We will operate the wells drilled on the acquired acreage and we expect our existing partner in the Eagle Ford Shale to purchase up to a one-sixth working interest. The acquisition brings our net Eagle Ford Shale acreage to approximately 10,200 net acres assuming our partner purchases a one-sixth working interest.
During 2010, we acquired a total of approximately 27,000 net acres in the Marcellus Shale play in Pennsylvania for approximately $69 million bringing our holdings in the area to approximately 56,000 net acres as of December 31, 2010.
Fracturing Services Agreement
In May 2010, we entered into a one-year agreement commencing in July 2010 with C&J Energy Services, Inc. to provide high pressure hydraulic fracturing services in our Texas and Mid-Continent regions. The supply of such services and related equipment was constrained in those regions, which led to delays in well completions during the first half of the year. As a result of the agreement, we have secured access to equipment and services necessary to complete the backlog of wells drilled, as well as wells to be drilled through the first half of 2011. The agreement was subsequently amended to provide for equipment and services into the South Texas region in support of our expansion into the Eagle Ford Shale play. The agreement will automatically renew in 2011 on similar terms unless the Company chooses to terminate after the initial term is complete.
In November 2009, we implemented an organization restructuring that resulted in the transfer of certain corporate and oil and gas accounting and administrative functions from our Kingsport, Tennessee office location to our Houston, Texas and Radnor, Pennsylvania locations. In addition, the restructuring resulted in the relocation of our eastern region oil and gas divisional office from Kingsport to Pittsburgh, Pennsylvania. During 2010, we expanded the program to restructure key operational and management positions to complete our transformation to a pure play E&P company. Approximately 30 employees were terminated in connection with the restructuring, which was substantially completed during the second quarter of 2010. In 2010, we incurred $4.7 million in costs including termination benefits, relocation costs and other incremental costs associated with expanding our other office locations. In addition, we incurred a charge of $3.5 million in connection with the assignment of a lease for our former Kingsport, Tennessee office facility to PVR. We anticipate an additional $0.4 million in costs, primarily related to employee relocation, to be incurred during 2011 attributable to the restructuring program.
Disposition of Gulf Coast Properties
In January 2010, we completed the sale of our Gulf Coast properties in exchange for cash proceeds of $23.4 million, net of transaction costs and purchase and sale adjustments, plus the receipt of certain oil and gas properties in the Selma Chalk play in our Mississippi region.
Results of Operations
Year Ended December 31, 2010 Compared With Year Ended December 31, 2009
The following table sets forth a summary of certain operating and financial performance for the periods presented: