SECURITIES AND EXCHANGE COMMISSION

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.   ý 

The aggregate market value of common stock held by non-affiliates of the registrant was $1,152,221,812$310,407,928 as of June 30, 20142015 (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 20, 2015, 71,581,690March 4, 2016, 86,353,944 shares of common stock of the registrant were outstanding.

 DOCUMENTS INCORPORATED BY REFERENCE

 

 

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

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

Penn Virginia Corporation is an independent oil and gas company engaged in the onshore exploration, development and production of crude oil, NGLs and natural gasgas. Our current operations consist primarily of operating our producing wells in various onshore regions of the United States, primarily the Eagle Ford Shale field, or Eagle Ford, in South Texas. We also have less significant operations in Oklahoma, primarily in the Granite Wash. We were incorporated in the Commonwealth of Virginia in 1882. Our common stock is publicly traded on the OTC Pink under the symbol “PVAH” subsequent to our delisting from the NYSE on January 12, 2016. Our common stock was previously traded on the NYSE under the symbol “PVA.” Our headquarters and corporate office is located in Radnor, Pennsylvania, and our operations are conducted primarily from our office in Houston, Texas. We also have districtan operations facilities at various locationsoffice near our Eagle Ford assets in Texas and Oklahoma.South Texas.

We operate in and report our financial results and disclosures as one segment, which is the exploration, development and production of crude oil, NGLs and natural gas. Each of our operating regions has similar economic characteristics and meets the criteria for aggregation as one reporting segment. Prior to June 2010, we were also engaged in the coal and natural resource management and natural gas midstream businesses. We completely disposed of our interests in those businesses in 2010 and have reported them as discontinued operations where applicable.

We own a highly contiguous position of approximately 102,000100,000 net acres in the core liquids richliquids-rich area or “volatile oil window” of the Eagle Ford, which we believe contains a substantial number of drilling locations and an approximatea more than 15-year drilling inventory. In 2014,2015, we spent approximately $785over $300 million, or 99 percent,substantially all, of our capital expenditures on our Eagle Ford operations and itthose operations accounted for 5.97.0 MMBOE, or 7488 percent, of our 7.9 MMBOE total production. We also have operations in the Haynesville Shale and Cotton Valley in East Texas and the Granite Wash in Oklahoma.

We produce predominantly crude oil and NGLs. In 2014,2015, our total production was comprised of 7380 percent crude oil and NGLs and 2720 percent natural gas, and crudegas. Crude oil and NGLs accounted for 8990 percent of our product revenues. We generally sell our crude oil, NGL and natural gas products using short-term floating price physical and spot market contracts. Our crude oil sales are generally committed at the wellhead and are priced based on the NYMEX quoted price for WTI crude oil plus any differential for LLS less deductions for transportation and quality. Our NGLs are sold to interstate and midstream pipelines with pricing based on the Mont Belvieu, Texas or Conway, Kansas indices less deductions for transportation and fractionation and a marketing fee. Our natural gas production is also sold to interstate and midstream pipelines with pricing based on the NYMEX quoted price for Henry Hub natural gas adjusted for any basis differential or as a percentage of certain regional reference prices.

As of December 31, 2014,2015, our proved reserves were approximately 11544 MMBOE, of which 4075 percent were proved developed reserves and 7784 percent were oil and NGLs. We drilled 84and completed 61 gross (51.6(38.6 net) wells, all in the Eagle Ford, in 2014.2015. As of December 31, 2014,2015, we had 738432 gross (478.8(254.7 net) productive wells, approximately 9086 percent of which we operate, and owned approximately 224,000166,000 gross (158,600(120,000 net) acres of leasehold and royalty interests, approximately 4554 percent of which were undeveloped. For a more detailed discussion of our production, reserves, drilling activities, wells and acreage, see Item 2, “Properties.”

Since 2010, we have disposeddivested essentially all of an aggregate of approximately $232 million of primarilyour natural gasgas-focused assets located in East Texas, Mississippi, Appalachia and the Arkoma Basin and the Gulf Coast regions of South Texas and Louisiana.Basin. In addition, in 2014, we sold our natural gas gathering and gas lift infrastructure assets in South Texas andas well as the rights to construct an oil gathering system in South Texas forTexas. We received aggregate proceeds of approximately $243 million.$535 million from these transactions. These proceeds were invested primarily in our Eagle Ford operations.

For additional financial and other information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Developments”Operations” and our Consolidated Financial Statements and Notes thereto included in Item 8, “Financial Statements and Supplementary Data.”

In the ordinary course of operating our business, we enter into a number of key contracts for services that are critical with respect to our ability to develop, produce and bring our production to market. The following is a summary of our most significant contractual arrangements.

Our operations are subject to extensive federal, state and local laws that govern oil and gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties as well as the issuance of injunctions limiting or prohibiting our activities for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of December 31, 2014,2015, we have recorded asset retirement obligations of $5.9$2.6 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general.

In addition, the United States Environmental Protection Agency, or the EPA, has designated energy extraction as one of six national enforcement initiatives, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas extraction and production activities. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition, results of operations andor cash flows. Nevertheless, changes in existing environmental laws or regulations or the adoption of new environmental laws or regulations, including any significant limitation on the use of hydraulic fracturing, could have the potential to adversely affect our financial condition, results of operations and cash flows.

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

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,The EPA has proposed new wastewater pretreatment standards that would prohibit onshore unconventional oil and gas extraction facilities from the hydraulic fracturing process can no longer be sentsending wastewater 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 ownedpublicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste may result in increased costs. The EPA is also developing a proposed rule to amend the Effluent Limitations Guidelines and Standards for the oil and gas industry, an effort expected to require analogous pretreatment standards on the federal level. The EPA’s proposed rule is scheduled for publication in early 2015.costs

Additionally, in 2015, several environmental groups filed suit in the District of Columbia federal district court against the EPA seeking a response to plaintiffs’ October 2012 petition to the EPA to bring the oil and gas industry within the scope of the Toxic Release Inventory, (“TRI”)or TRI, reporting requirements under the Emergency Planning and Community Right-to-Know Act, (“EPCRA”).or the EPCRA. The TRI provisions of the EPCRA require covered facilities to report, on an annual basis, releases into the environment of specifically-listed chemicals. We currently disclose all hydraulic fracturing additives we use on www.FracFocus.org,As a website created byresult, the Ground Water Protection CouncilEPA issued a response letter agreeing to create TRI requirements for natural gas processing plants, but declining to create TRI requirements for the other request areas, which included crude petroleum and Interstate Oilnatural gas, natural gas liquids, drilling oil and Gas Compact Commission.gas wells, oil and gas field exploration services, and oil and gas field services.

In addition to chemical disclosure rules, some states have implemented permitting, well construction or water withdrawal regulations that may increase the costs of hydraulic fracturing operations. Pennsylvania and West Virginia have issued setback regulations for wells. Colorado recently enacted new setback restrictions as well as requirements to conduct sampling on water wells before and after drilling. In addition, states such asFor example, Texas and Pennsylvania have water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source.

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 gas, including from the developing shale plays, or could make it more difficult to

Additionally, on April 17,In 2012 the EPA issued new rules subjecting allcertain 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. These rules restrict volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non wildcat and non delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. “Other” wells, however, must use reduced emission completions, also known as “green completions,” with or without combustion devices.conducted. These regulations also establish specific requirements regarding emissions from production related wet seal and reciprocating compressors, pneumatic controllers, and storage vessels. In September 2013 and December 2014,2015, the EPA published updates toproposed expanding the 2012 performanceNSPS to create additional methane standards which, among other things, set the compliance deadline for tanks based upon when they were put into use. new compressor stations, natural gas processing plants, and well sites. The proposed NSPS would limit natural gas emissions during well completions, impose new leak detection, and ongoing survey, repair, and recordkeeping requirements.

The EPA received numerous requestshas also released new draft control guidance for reconsiderationreducing volatile organic compound emissions from existing oil and gas sources in certain ozone non-attainment areas. The EPA acknowledged that some of its recommendations mirror the requirements found in the proposed NSPS for new sources and that, if adopted by states, these recommendations would apply to both new and existing sources of volatile organic compounds in ozone non-attainment areas. If the rules are adopted as proposed and the guidance remains unchanged, they would impose new compliance costs on our operations.

Collectively, these rules and court challenges to the rules were also filed. The EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests. Theseproposed rules, as well as any future laws and their implementing regulations, may require a number of modifications to our operations, including the installation ofoperations. We may, for example, be required to install new equipment to control emissions from our well sites or compressors at initial startup or by the applicable compliance deadline. We may also be required to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. We are currently researching the effect these new rules will have on our business, but generally expect them to add to the cost and expense of our operations.

In addition, in 2009, the EPA issued a final rule known as the EPA’s Endangerment Finding, findingwhich found 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 were subject to judicial challenge, but on June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit rejected challenges to the tailoring rule and other EPA rules relating to the regulation of GHGs under the CAA.

Starting July 1, 2011, the EPA required 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. On March 27, 2012, the EPA issued its proposed NSPS for carbon dioxide emissions standard from new and modified power plants and held public hearings on the rule in May 2012 and accepted written comments until June 25, 2012. In its June 2013 Climate Action Plan, the Obama Administration announced its intent to issue regulations under Section 111(b) and Section 111(d) of the CAA to set NSPS for both new and existing power plants by June 2015. In January 2014, the EPA formally published re-proposed GHG NSPS for new and modified electric generating units (“EGUs”). The Climate Action Plan also directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and natural gas agency. More recently, it has been reported thatindustry.

The U.S. Supreme Court, in a decision issued on June 23, 2014, addressed whether the EPA’s regulation of GHG emissions from new motor vehicles properly triggered GHG permitting requirements for stationary sources under the Clean Air Act. Through its Prevention of Significant Deterioration (“PSD”) and Title V Greenhouse Gas Tailoring Rule, the EPA sought to require large industrial facilities, including coal-fired power plants, to obtain permits to emit, and to use best available control technology to curb, GHG emissions. The decision reversed, in part, and affirmed, in part, a 2012 D.C. Circuit decision that upheld the EPA’s GHG-related regulations. Specifically, the court held that the EPA exceeded its statutory authority when it interpreted the Clean Air Act to require Prevention of Significant Deterioration and Title V permitting for stationary sources based on their potential GHG emissions. However, the Court also held that the EPA’s determination that a source already subject to the PSD program due to its emission of conventional pollutants may be required to limit its GHG emissions by employing the “best available control technology” was permissible.

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.

We had a total of 164112 employees as of December 31, 2014.2015. We consider our current employee relations to be favorable. We and our employees are not subject to any collective bargaining agreements.

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, results of operations and cash flows. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows could suffer and the trading price of our common stock could decline.

Prices for crude oil, NGLs and demand for oil andnatural gas market demand and otherare dependent on many factors that are beyond our control, including:

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 operating activities. We have historically succeeded in substantially replacing reserves primarily through explorationmust make substantial capital expenditures to find, acquire, develop and development and, to a lesser extent, acquisitions. We have conducted such activities on our existingproduce oil and gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves and production from such activities at acceptable costs. Lowerreserves. Because of significantly low commodity prices, also decrease our cash flows from operating activities and may cause us to reduce capital expenditures.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or gas reserves will be found. The costs of drilling, completing and operating wells are often substantial and 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 crude oil, NGLs and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs and equipment can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.

The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas 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 effect 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, results of operations and cash flows. 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 subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of revenues. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly affect our overall credit risk. Recently, many of our customers’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payments or perform on their obligations to us. In 2014,2015, approximately 5064 percent of our total consolidated product revenues resulted from three of our customers. Any nonpayment or nonperformance by our customers would reduce our cash flows.

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

Our business and prospects for future success, including the successful implementation of our strategies and handling of issues integral to our future success, depend to a significant extent upon the continued service and performance of our management team. The loss of any member of our management team, and our inability to attract, motivate and retain substitute management personnel with comparable experience and skills, could materially and adversely affect our business, financial condition, results of operations and cash flows.

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

Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion operations. The ability of third-party service providers to perform such drilling and completion operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, natural gas liquids and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations could delay drilling or completion, reduce production from the property or cause other damage to operations, each of which could adversely affect our business, financial condition, results of operations and cash flows.

Leases on oil and natural gas properties typically have a term after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. While we seek to actively manage our leasehold inventory through drilling wells to hold the leasehold acreage that we believe is material to our operations, our drilling plans for these areas are subject to change.change and subject to the availability of capital.

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 crude oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and, therefore, changes often occur as these variables evolve and commodity prices fluctuate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the estimated quantities and present value of our reserves.

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

At December 31, 2014,2015, approximately 6025 percent of our estimated proved reserves were proved undeveloped.undeveloped, compared to 60 percent at December 31, 2014. 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 timesometime 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.

The reserve estimation standards provide that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These standards may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not develop those reserves within the required five-year time frame or cannot demonstrate that we could do so. We removed approximately 20.7experienced negative revisions of 45.6 MMBOE of proved undeveloped reserves in 2014 as a result of the five-year limitation. 2015 due to fewer locations, lower EURs and lower prices compared to year-end 2014.

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

Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment. Lower crude oil, NGL and natural gas prices may have the impact of shortening the economic lives onof certain fields because it becomes uneconomic to produce all recoverable reserves onwithin 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 sufficientsignificant enough to causeresult in impairment losses on certain properties that would result in a further non-cash charge todecrease 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 and other factors.

During the past several years, we have been required to impair certain of our oil and gas properties and related assets. If crude oil, NGL and natural gas prices decline or we drill uneconomic wells, it is reasonably possible that we will have to record a significantWe recorded an impairment charge of approximately $1.4 billion during 2015. We could experience additional impairments 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.

In 2014,2015, other companies operated approximately 1015 percent of our net production. Our success in properties operated by others will depend upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’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.

Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. In the event we do complete an acquisition, its success will depend on a number of factors, many of which are beyond our control. These factors include the purchase price, future crude oil, NGL and natural gas prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties and future abandonment and possible future environmental or other liabilities. There are numerous uncertainties inherent in estimating quantities of proved oil and 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 also compete for people, including experienced geologists, geophysicists, engineers and other professionals. Our limited size has placed us at a disadvantage with respect to attracting and retaining management and other professionals with the technical abilities necessary to successfully operate our business.

Our current business is focused primarily in the Eagle Ford in South Texas. Due to the concentrated nature of our business activities, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have aare more diversified. In particular, we may be disproportionately exposed to the impact of delays or interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil or natural gas produced from wells in the Eagle FordFord.

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, results of operations and cash flows. See Item 1, “Business —– Government Regulation and Environmental Matters.”

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 problems with well stimulation and completion activities, such as hydraulic fracturing, our ability to explore for and produce oil or natural gas 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 or that we will purchase insurance against all possible losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. For example, the EPA implemented rules requiring annual reporting of GHG emissions from specified large GHG emission sources in the United States for emissions occurring after January 1, 2010. In a December 2014 proposed rule,October 2015 the EPA proposed to addreleased a final rule adding reporting of GHG reporting requirements applicable to petroleumemissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas systems, including various equipment and systems associated with hydraulic fracturing operations. transmission pipelines.

Moreover, the Obama administration has announced in its Climate Action Plan that it intends to adopt additional regulations to reduce emissions of GHGs in the coming years, likely including further restrictions on emissions of methane from oil and gas operations. More specifically, it has been reported that the EPA will issue a proposed ruleissued its final Clean Power Plan rules in the summer ofAugust 2015 that would cutestablish carbon pollution standards for power plants, and has proposed New Source Performance Standards, or NSPS, to reduce methane emissions from the oil and gas production by up to 45 percent by 2025 from the levels recorded in 2012.industry. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. See Item 1, “Business – Government Regulation and Environmental Matters.”

In addition, 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, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our financial condition, results of operations and cash flows. For a fulsomemore complete discussion of environmental laws and regulations intended to address climate change and their impact on our business and operations, please see “Business-Environmental Regulation-Climate“Business – Environmental Regulation – Climate Change.”

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 gas production. We use this completion technique on all of our wells. The EPA is studying the potential environmental impacts of hydraulic fracturing and its potential impact on drinking water resources. AThe EPA released a draft report in June 2015, which stated that EPA had not found evidence of widespread, systemic impacts on drinking water resources from hydraulic fracturing operations. This report has not yet been finalized, and the EPA’s ultimate conclusions may be impacted by recent comments from the EPA’s Science Advisory Board regarding the sufficiency of the study was expected to be released todata underlying some of the public in 2014, but has yet to be issued.EPA’s conclusions. In May 2014, the EPA issued an advance notice of proposed rulemaking relating to the collection of information on various chemicals and mixtures used in hydraulic fracturing. The EPA is also developing a proposed rule to amend the Effluent Limitations Guidelines and Standards for the oil and gas industry. The proposal is expected to address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. The proposed rule is scheduled for publication in early 2015. The EPA has issued final rules under the CAA that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants, (“NESHAP”)or NESHAP, programs. The EPA has proposed additional NSPS regulations of volatile organic compound and methane emissions from the oil and gas industry, and has released draft guidance that could potentially extend such requirements to existing oil and gas sources in ozone non-attainment areas.

In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. In addition, some states and local governments have enacted legislation or adopted regulations, and the U.S. Congress and other states are considering enacting legislation or adopting regulations, that could impose more stringent permitting, disclosure, monitoring, well construction and water use 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. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. While we do not believe that compliance with such requirements will have a material adverse effect on our operations, these requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations, any of which could be significant.

If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Various federal and state statutes prohibit certain actions that harm endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act, CERCLA and the OPA. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling, construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, may seek criminal penalties.

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

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

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.

President Obama’s budget proposal for fiscal year 2015 recommendedPotential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties,properties; (ii) the elimination of current deductions for intangible drilling and development costs,costs; (iii) the elimination of the deduction for United Statescertain U. S. production activities for oil and gas production, and(iv) 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 and state 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 havenegatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a material adverse effectper barrel equivalent of crude oil. This fee would be collected on us.domestically produced and imported petroleum products. The fee would be phased in evenly over five years beginning October 1, 2016. The adoption of this, or similar proposals, would result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

The oil and gas industry is dependent on digital technologies to conduct certain exploration, development and production activities. Software programs are used for, among other things, reserve estimates, seismic interpretation, modeling and compliance reporting. In addition, the use of mobile communication is widespread. Increasingly, we must protect our business against potential cyber incidents including attacks.

Facilities

Title to Oil and Gas Properties

Summary of Oil and Gas Reserves

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The proved undeveloped reserves included in our reserve estimates relate to wells that are forecasted to be drilled within the next five years.three years, assuming availability of capital. The following tables set forth the changes in our proved undeveloped reserves during the year ended December 31, 20142015 and the total proved undeveloped reserves as of December 31, 20142015 by region:

The proved reserve estimates were prepared by Wright & Company,DeGolyer and MacNaughton, Inc., our independent third party 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 our Notes to the Consolidated Financial Statements and the report of Wright & Company,DeGolyer and MacNaughton, Inc., prepared for us and dated January 9, 2015,February 3, 2016, 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, 20142015 with any federal authority or agency with respect to our estimate of oil and gas reserves.

Our policies and practices regarding the recording of reserves are structured to objectively and accurately estimate our oil and gas reserve quantities and present values in compliance with the SEC’s regulations and GAAP. Our Vice President, Operations & Engineering is primarily responsible for overseeing the preparation of the reserve estimate by Wright & Company,DeGolyer and MacNaughton, Inc. Our Vice President, Operations & Engineering has over 2930 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. Our internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

Our properties in the Eagle Ford in South Texas, which contain primarily oil reserves, representrepresented approximately 8292 percent of our total equivalent proved reserve quantities and approximately 93 percent of our total crude oil and NGL reserves as of December 31, 2014. This is the only field that comprises 15% or more of our total proved reserves as of that date.2015.

Drilling and Other Exploratory and Development Activities

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

Delivery Commitments

We generally sell our oil, NGL and natural gas 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, 2014, we did notWe have any material commitments to provide minimum deliveries of crude oil of 15,000 BOPD in our South Texas region for a fixedperiod of ten years under a gathering agreement with Republic Midstream, LLC, or Republic. This commitment is for a 10 year term beginning once the system has been constructed and determinable quantityis operational, currently expected in the first half of 2016. Although, our production and reserves are currently sufficient to fulfill the delivery commitment under the agreement, future oil production may not be sufficient to meet the minimum volume requirements. If we do not purchase volumes in the market or make other arrangements to satisfy the commitments, we would be required to make deficiency payments that total $1.75 per undelivered Bbl.

Productive Wells

Acreage

Market Information

OurOn January 13, 2016, our common stock isbegan trading on the OTC Pink under the symbol “PVAH.” Prior to being suspended from trading on January 12, 2016, our common stock was traded on the NYSE under the symbol “PVA.”

Dividends

Securities Authorized for Issuance Under Equity Compensation Plans

Issuer Purchases of Equity Securities

We did not repurchase any shares of our common stock in the fourth quarter of 2014.2015.

A portion of the compensation paid tofor certain non-employee members of our board of directors ishas been paid in deferred common stock units.units in recent years through the third quarter of 2015. Each deferred common stock unit represents one share of common stock, vests immediately upon issuance, and is available to the holder upon retirement from our board of directors. Deferred common stock units that have not been converted into common stock are presented for financial reporting purposes as treasury stock carried at cost.