UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________
 FORM 10-K
________________________________________________________
 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2014
 Commission file number: 1-13283
 _________________________________________________________ 
PENN VIRGINIA CORPORATION
(Exact name of registrant as specified in its charter)
Virginia
 
23-1184320
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification Number)
Four Radnor Corporate Center, Suite 200
100 Matsonford Road
Radnor, Pennsylvania 19087
(Address of principal executive offices)
Registrant’s telephone number, including area code: (610) 687-8900
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
 
Name of exchange on which registered
Common Stock, $0.01 Par Value
 
New York Stock Exchange
__________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes  ý    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  ý
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  ý    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  ý  No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ý 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer
ý
 
Accelerated filer
o
 
Non-accelerated filer
o
 
Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
The aggregate market value of common stock held by non-affiliates of the registrant was $1,152,221,812 as of June 30, 2014 (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, 71,581,690 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 7, 2015, are incorporated by reference in Part III of this Form 10-K.
 




PENN VIRGINIA CORPORATION AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K
 For the Fiscal Year Ended December 31, 2014
 Table of Contents
 
Page
Forward-Looking Statements
Glossary of Certain Industry Terminology
Part I
Item
 
 
1.
Business
1A.
Risk Factors
1B.
Unresolved Staff Comments
2.
Properties
3.
Legal Proceedings
4.
Mine Safety Disclosures
Part II
 
 
 
5.
Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
6.
Selected Financial Data
7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations:
 
 
Overview and Executive Summary
 
Key Developments
 
Results of Operations
 
Financial Condition
 
Off-Balance Sheet Arrangements
 
Contractual Obligations
 
Critical Accounting Estimates
7A.
Quantitative and Qualitative Disclosures About Market Risk
8.
Financial Statements and Supplementary Data
9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
9A.
Controls and Procedures
9B.
Other Information
Part III
 
 
 
10.
Directors, Executive Officers and Corporate Governance
11.
Executive Compensation
12.
Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
13.
Certain Relationships and Related Transactions, and Director Independence
14.
Principal Accountant Fees and Services
Part IV
 
 
 
15.
Exhibits and Financial Statement Schedules
 
 
Signatures




Forward-Looking Statements
 
Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: 
the volatility of commodity prices for oil, natural gas liquids and natural gas;
our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;
our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;
any impairments, write-downs or write-offs of our reserves or assets;
the projected demand for and supply of oil, natural gas liquids and natural gas;
reductions in the borrowing base under our revolving credit facility;
our ability to contract for drilling rigs, supplies and services at reasonable costs;
our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices;
the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves;
drilling and operating risks;
our ability to compete effectively against other oil and gas companies;
our ability to successfully monetize select assets and repay our debt;
leasehold terms expiring before production can be established;
environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;
the timing of receipt of necessary regulatory permits;
the effect of commodity and financial derivative arrangements;
our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms;
the occurrence of unusual weather or operating conditions, including force majeure events;
our ability to retain or attract senior management and key technical employees;
counterparty risk related to the ability of these parties to meet their future obligations;
compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;
physical, electronic and cybersecurity breaches;
uncertainties relating to general domestic and international economic and political conditions; and
other factors set forth in our periodic filings with the Securities and Exchange Commission, including the risks set forth in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2014.
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. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. 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, except as may be required by applicable law.

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Glossary of Certain Industry Terminology
 
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.
AMI. Area of mutual interest.
Bbl. A standard barrel of 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent with one barrel of crude oil, condensate or natural gas liquids converted to six thousand cubic feet of natural gas based on the estimated relative energy content.
BOE. One barrel of oil equivalent with six thousand cubic feet of natural gas converted to one barrel of crude oil based on the estimated relative energy content.
BOEPD. Barrels of oil equivalent per day.
Borrowing base. The value assigned to a collection of borrower’s assets used by lenders to determine an initial and/or continuing amount for loans. In the case of oil and gas exploration and development companies, the borrowing base is generally based on proved developed reserves.
Completion. A process of treating a drilled well, including hydraulic fracturing among other stimulation processes, followed by the installation of permanent equipment for the production of oil or gas.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface temperature and pressure.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient commercial quantities to justify completion of the well.
Drilling carry. A working interest that will be carried through the drilling and completion of a well.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.
EUR. Estimated ultimate reserves, the sum of reserves remaining as of a given date and cumulative production as of that date.
GAAP. Accounting principles generally accepted in the Unites States of America.
Gas lift. A method of artificial lift that uses an external source of high-pressure gas for supplementing formation gas for lifting the well fluids.
Gross acre or well. An acre or well in which a working interest is owned.
HBP. Held by production is a provision in an oil and gas or mineral lease that perpetuates the leaseholder’s right to operate the property as long as the property produces a minimum paying quantity of oil or gas.
Henry Hub. The Erath, Louisiana settlement point price for natural gas.
IP. Initial production, a measurement of a well’s production at the outset.
LLS. Light Louisiana Sweet is a crude oil pricing index reference.
LIBOR. London Interbank Offered Rate.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One million barrels of oil or other liquid hydrocarbons.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units, a measure of energy content.
MMcf. One million cubic feet of natural gas.
Net acre or well. The number of gross acres or wells multiplied by the owned working interest in such gross acres or wells.
NGL. Natural gas liquid.
NYMEX. New York Mercantile Exchange.

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NYSE. New York Stock Exchange.
Operator. The entity responsible for the exploration and/or production of a lease or well.
Play. A geological formation with potential oil and gas reserves.
Preferential rights. The rights that nonselling participating parties have in a lease, well or unit to proportionately acquire the interest that a participating party proposes to sell to a third party.
Productive wells. Wells that are not dry holes.
Possible reserves. Those additional reserves that are less certain to be recovered than probable reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
Proved reserves. Those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved developed reserves. Proved reserves that can be expected to be recovered: (a) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (b) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled.
PV10. Present value of estimated future oil and gas revenues, net of estimated direct expenses, discounted at an annual discount rate of 10%.
Reservoir. A porous and permeable underground formation containing a natural accumulation of hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.
SEC. United States Securities and Exchange Commission.
Standardized measure. The present value, discounted at 10% per year, of estimated future cash inflows from the production of proved reserves, computed by applying prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves (except for consideration of future price changes to the extent provided by contractual arrangements in existence at year-end), reduced by estimated future development and production costs, computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year (including the settlement of asset retirement obligations), based on year-end costs and assuming continuation of existing economic conditions, further reduced by estimated future income tax expenses, computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the proved oil and gas reserves, less the tax basis of the properties involved and giving effect to the tax deductions and tax credits and allowances relating to the proved oil and gas reserves.
Revenue interest. An economic interest in production of hydrocarbons from a specified property.
Royalty interest. An interest in the production of a well entitling the owner to a share of production generally free of the costs of exploration, development and production.
Unconventional. Generally refers to hydrocarbon reservoirs that lack discrete boundaries that typically define conventional reservoirs. They are typically referred to as shales, tight sands or coal beds.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.
WTI. West Texas Intermediate, a crude oil pricing index reference.
Working interest. A cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease.



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Part I
Item 1
Business
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 exploration, development and production of crude oil, NGLs and natural gas in various onshore regions of the United States, primarily the Eagle Ford Shale, or Eagle Ford, in South Texas. We were incorporated in the Commonwealth of Virginia in 1882. Our common stock is publicly 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 district operations facilities at various locations in Texas and Oklahoma.
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 102,000 net acres in the core liquids rich area or “volatile oil window” of the Eagle Ford, which we believe contains a substantial number of drilling locations and an approximate 15-year drilling inventory. In 2014, we spent approximately $785 million, or 99 percent, of our capital expenditures on our Eagle Ford operations and it accounted for 5.9 MMBOE, or 74 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, our total production was comprised of 73 percent crude oil and NGLs and 27 percent natural gas, and crude oil and NGLs accounted for 89 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, our proved reserves were approximately 115 MMBOE, of which 40 percent were proved developed reserves and 77 percent were oil and NGLs. We drilled 84 gross (51.6 net) wells, all in the Eagle Ford, in 2014. As of December 31, 2014, we had 738 gross (478.8 net) productive wells, approximately 90 percent of which we operate, and owned approximately 224,000 gross (158,600 net) acres of leasehold and royalty interests, approximately 45 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 disposed of an aggregate of approximately $232 million of primarily natural gas assets located in Mississippi, Appalachia, the Arkoma Basin and the Gulf Coast regions of South Texas and Louisiana. In addition, in 2014, we sold our natural gas gathering and gas lift assets in South Texas and the rights to construct an oil gathering system in South Texas for proceeds of approximately $243 million.
For additional financial and other information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Key Developments” and our Consolidated Financial Statements and Notes thereto included in Item 8, “Financial Statements and Supplementary Data.”
Business Strategy
Our goal is to enhance long-term shareholder value. In 2015, we plan to focus on conserving an adequate level of liquidity, which we believe is approximately $150 million, operating with acceptable leverage and growing our business in a disciplined manner. We have taken, or intend to take, the following actions to accomplish our goal:
Maintain disciplined flexible capital spending. Crude oil prices have declined more than 45 percent since October 2014. As a result, we have reduced the number of rigs we are operating from eight in December 2014 to three currently. We plan to increase, or decrease, the number of rigs we operate depending upon the commodity price environment. In furtherance of this plan, we have entered into drilling and completion contracts with shorter terms, which afford us greater flexibility.

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Focus on high return projects. We intend to invest principally in our highest return development projects - those that we believe have significant resource potential discoverable at a low cost. We plan to continue to improve drilling and completion efficiencies and costs, including by using multi-well pad drilling, decreasing the number of frac stages per well by increasing the distance between stages, decreasing the amount of proppant per stage and renegotiating service sector costs.
Protect cash flow with hedges. In 2014, we were able to execute additional hedge contracts for an average of 9,500 BOPD at a weighted-average price of $89.47 per Bbl for 2015 and 4,000 BOPD at a price of $88.12 per Bbl for 2016. The addition of these contracts has increased our total hedged crude oil production to 13,000 BOPD at a weighted-average price of $90.48 per Bbl for the first half of 2015 and 11,000 BOPD at a weighted-average price of $89.86 per Bbl for the second half of 2015, or approximately 80 to 90 percent of our total estimated crude oil production for 2015.
At this time, we also plan to retain our substantial natural gas properties in the Haynesville Shale and Cotton Valley in East Texas, which are largely HBP and which provide us with an option to increase our natural gas production should prices increase.
Key Contractual Arrangements
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.
Drilling and Completion. We have agreements with vendors to provide oil and gas well drilling and well completion services. Generally, these agreements are on a month-to-month basis, but certain agreements extend for terms up to one year. Certain of these agreements include early termination provisions that require us to pay penalties if we terminate the agreements prior to the end of their original terms. We also purchase a substantial volume of well materials, including tubular products.
Natural gas contracts. In 2014, we entered into an agreement that will provide gathering, compression and transportation services for a portion of our natural gas production in the South Texas region until 2029. We have also entered into contracts that provide firm transportation capacity rights for specified volumes of natural gas on various other 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.
Oil transportation contracts. In 2014, we also entered into agreements to provide us gathering and intermediate pipeline transportation services for a substantial portion of our South Texas crude oil and condensate production. The gathering agreement has a 25-year term and the intermediation transportation agreement has a 10-year term, both of which will commence upon completion of construction of the gathering system, which is expected in the third quarter of 2015.
Major Customers
We sell a significant portion of our oil and gas production to a relatively small number of customers. For the year ended December 31, 2014, approximately 50 percent of our consolidated product revenues were attributable to three customers: Sunoco Refining and Marketing, Inc.; Phillips 66 Company; and Gulfmark Energy Inc.
Seasonality
Our sales volumes of oil and gas are dependent upon the number of producing wells and, therefore, are not seasonal by nature. We do not believe that the pricing of our oil and NGL production is subject to any meaningful seasonal effects. Historically, the pricing of natural gas is seasonal, typically with higher pricing in the winter months.
Competition
The oil and gas industry is very competitive, and we compete with a substantial number of other companies, many of which 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. Some of our competitors not only engage in the acquisition, exploration, development and production of oil and gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. In addition, the oil and gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers. Competition is particularly intense in the acquisition of prospective oil and gas properties. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. We also compete with other oil and gas companies to secure drilling rigs and other equipment necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Such equipment and labor may be in short supply from time to time. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. In addition, many of our larger competitors may have a competitive advantage when responding to commodity price volatility and overall industry cycles.

5



Government Regulation and Environmental Matters
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, we have recorded asset retirement obligations of $5.9 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. 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 and 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.
CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, is also known as the “Superfund” law. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on parties that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible parties” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease properties that have been used for the exploration and production of oil and gas for a number of years. Many of these properties have been operated by third parties whose treatment or release of hydrocarbons or other wastes was not under our control. These properties, and any wastes that may have been released on them, may be subject to CERCLA, and we could potentially be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination.
RCRA. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and clean up of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of RCRA. While there is currently an exclusion from RCRA for drilling fluids, produced waters and most of the other wastes associated with the exploration and production of oil or gas, it is possible that some of these wastes could be classified as hazardous waste in the future, and therefore be subject to RCRA.
Oil Pollution Act. The Oil Pollution Act of 1990, or the OPA, contains numerous restrictions relating to the prevention of and response to oil spills into waters of the United States. The term “waters of the United States” has been interpreted broadly to include inland water bodies, including wetlands and intermittent streams. The OPA subjects owners of facilities to strict, joint and several liability for all containment and clean up costs, and certain other damages arising from a spill.
Clean Water Act. The Federal Water Pollution Control Act, or the Clean Water Act, governs the discharge of certain pollutants into waters of the United States. The discharge of pollutants into regulated waters without a permit issued by the EPA or the state is prohibited. The Clean Water Act also requires the preparation and implementation of Spill Prevention, Control and Countermeasure Plans in connection with on-site storage of significant quantities of oil. Notably, in Pennsylvania, wastewater from the hydraulic fracturing process can no longer be sent to publicly owned treatment works directly. New wastewater discharges must be treated at a centralized waste treatment facility and comply with certain Total Dissolved Solids standards prior to being discharged to publicly owned treatment works. This restriction of disposal options for hydraulic fracturing waste may result in increased costs. The EPA is 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.
Safe Drinking Water Act. The Safe Drinking Water Act, or the SDWA, and the Underground Injection Control Program promulgated under the SDWA, establish the requirements for salt water disposal well activities and prohibit the migration of fluid containing contaminants into underground sources of drinking water. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells in which we act as operator. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional

6



plays like the Eagle Ford, Granite Wash, Haynesville Shale and the Marcellus Shale formations. The Fracturing Responsibility and Awareness of Chemicals Act that was introduced in both the 111th and 112th Congresses would subject hydraulic fracturing operations to federal regulation under the SDWA and require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing. Such costs and burdens could delay the development of unconventional gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Additionally, the EPA has commenced a comprehensive research study to investigate the potential adverse impacts of hydraulic fracturing on drinking water and ground water. The EPA last released a progress report on its study on December 21, 2012. A draft of the study was expected to be released to the public in 2014, but has yet to be issued.
Chemical Disclosures Related to Hydraulic Fracturing. Certain states in which we operate have adopted regulations requiring the disclosure of chemicals used in the hydraulic fracturing process. For instance, Oklahoma, Pennsylvania and Texas have implemented chemical disclosure requirements for hydraulic fracturing operations. 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. 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”) reporting requirements under the Emergency Planning and Community Right-to-Know Act (“EPCRA”). The TRI provisions of 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, a website created by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission.
Prohibitions and Other Regulatory Limitations on Hydraulic Fracturing. There have been a variety of regulatory initiatives at the state level to restrict oil and gas drilling operations in certain locations. For example, Pennsylvania has instituted a moratorium on leasing state forest land for gas drilling, and municipalities in New York have banned or limited hydraulic fracturing within their borders. In December 2014, the administration of Gov. Andrew Cuomo announced that it will ban high volume hydraulic fracturing (“HVHF”) in New York in 2015 on the grounds that there is insufficient information to assess the risks to public health associated with HVHF and whether any such risks can be adequately managed. In November 2014, voters in the City of Denton, Texas, approved a local ordinance banning fracking. This has resulted in two separate lawsuits, one filed by the Texas Oil & Gas Association and the other by the State Land Commissioner, challenging the local ban. Like the similar suits in other states, the claims in these cases focus on the issue of whether state law - through regulation by the Texas Railroad Commission and other state agencies - preempts the local ordinance.
A recent decision by the Pennsylvania Supreme Court addressing preemption may empower local governments to limit and/or regulate hydraulic fracturing, which could complicate and delay hydraulic fracturing activity. In February 2012, Pennsylvania passed Act 13, which, among other things, provided for new well fees assessed and collected on unconventional wells, substantial revisions to environmental protections for both surface and subsurface activities, and prevented local zoning rules from imposing burdens on oil and gas activities beyond those required by the state. However, in December 2013, the court struck down portions of Act 13, including deeming the statewide preemption of local zoning rules and the setback requirement waiver provisions unconstitutional. On remand, the lower court held that several other provisions of Act 13 could not be severed from those ruled as unconstitutional. As a result of these decisions, whether a state-wide approach to regulating oil and gas drilling and hydraulic fracturing may preempt local limitations in Pennsylvania remains an open question. If, through future jurisprudence or legislative action, such preemption does not apply under Pennsylvania law (or the law of other jurisdictions in which we operate), the net effect may be to subject hydraulic fracturing activities to local limitations and potentially duplicative and inconsistent regulations.
In addition to chemical disclosure rules, some states have implemented permitting, well construction or water withdrawal regulations that may increase the costs of hydraulic fracturing operations. Pennsylvania and West Virginia have issued setback regulations for wells. Colorado recently enacted new setback restrictions as well as requirements to conduct sampling on water wells before and after drilling. In addition, states such as Texas and Pennsylvania have water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source.
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

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perform hydraulic fracturing. These developments could also lead to litigation challenging proposed or operating wells. The adoption of federal, state or local laws or the implementation of regulations regarding hydraulic fracturing that are more stringent could cause a decrease in the completion of new oil and gas wells, as well as increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. We use hydraulic fracturing extensively and any increased federal, state, or local regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover.
Clean Air Act. Our operations are subject to the Clean Air Act, or the CAA, and comparable state and local requirements. In 1990, the U.S. Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed, and continue to develop, regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Further, stricter requirements could negatively impact our production and operations. For example, the Texas Commission on Environmental Quality and the Railroad Commission of Texas have been evaluating possible additional regulation of air emissions in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state and federal levels.
Additionally, on April 17, 2012, the EPA issued new rules subjecting all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs. 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. 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, the EPA published updates to the 2012 performance standards, which, among other things, set the compliance deadline for tanks based upon when they were put into use. The EPA received numerous requests for reconsideration of 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. These rules, as well as any future laws and their implementing regulations may require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup or 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.
There have been recent claims asserted that individual wells and other facilities should be “aggregated” together and their collective emissions considered in determining whether major source permitting requirements apply under the CAA. If we were required to aggregate individual wells and other facilities, it could bring us within the ambit of the Title V permitting program, and we could be considered a major source for MACT applicability. For example, though the Sixth Circuit recently vacated an EPA determination to aggregate natural gas wells and a sweetening plant in Summit Petroleum Corp. v. EPA et al., the EPA released a December 21, 2012 memorandum stating that although the EPA will follow the court’s interpretation when considering aggregation in the Sixth Circuit, it will continue to follow its current practice of considering interrelatedness in other jurisdictions. In May 2014, the United States Circuit Court of Appeals for the District of Columbia, in National Environmental Development Association’s Clean Air Project v. EPA, ruled that the EPA cannot by policy memorandum direct the use of differing Clean Air Act interpretations in different regions of the country, thereby invalidating the December 21, 2012 memorandum. As a result of this decision, in order to comply with the various decisions described above, the EPA must follow the Summit court’s narrow interpretation when considering aggregation or revise its regulations to modify its test for aggregation. In addition, in Citizens for Pennsylvanias Future v. Ultra Resources, Inc., a case challenging a decision not to aggregate certain facilities in Pennsylvania, the court allowed the case to move forward by denying defendant’s motion to dismiss, even though the plaintiff had not exhausted review procedures with the administrative agency.
Greenhouse Gas Emissions. Both in the United States and worldwide, there is increasing attention being paid to the issue of climate change and the contributing effect of greenhouse gas, or GHG, emissions. On June 28, 2010, the EPA issued the “Final Mandatory Reporting of Greenhouse Gases” Rule, or the Reporting Rule, requiring all stationary sources that emit more than 25,000 tons of GHGs per year to collect and report to the EPA data regarding such emissions. The Reporting Rule establishes a new comprehensive scheme, which began in 2011, requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions occurring in the prior calendar year on a facility-by-facility basis. On November 9, 2010, the EPA issued final rules applying these regulations

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to the oil and gas source category, including oil and gas production, natural gas processing, transmission, distribution and storage facilities (Subpart W). More recently, in a December 2014 proposed rule, the EPA proposed to require GHG reporting by yet additional petroleum and natural gas systems, including various equipment and systems associated with hydraulic fracturing operations. This action does not require control of GHGs. However, the EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits.
In addition, in 2009, the EPA issued a final rule known as the EPA’s Endangerment Finding finding that current and projected concentrations of six key GHGs in the atmosphere threaten public health and the environment, as well as the welfare of current and future generations. Legal challenges to these findings have been asserted, and the U.S. Congress is considering legislation to delay or repeal the EPA’s actions, but we cannot predict the outcome of this litigation or these efforts. The EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. These rules 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 that the EPA will issue a proposed rule in the summer of 2015 that would cut methane emissions from oil and gas production by up to 45 percent by 2025 from the levels recorded in 2012.
On June 2, 2014, the EPA released the Clean Power Plan. Though the plan does not regulate hydraulic fracturing operations, it sets a national carbon pollution standard that is projected to cut emissions produced by United States power plants by 30% by 2030 as compared to 2005 levels. Although states can choose to rely on the four measures set by the EPA to meet this goal, the states themselves will ultimately decide the means to use. States can develop individual plans, or they can collaborate with other states. These measures states may employ include: renewable energy standards, efficiency improvements at plants, switching to natural gas, transmission efficiency improvements, energy storage technology, and expanding renewables or nuclear, and energy conservation programs. Under the proposed rule, states will have until June 2016 to submit final plans, although extensions may be allotted if needed. The final rule is expected to be issued in June 2015 and the emissions reductions are scheduled to commence in 2020. An Ohio-based coal company has already filed a legal challenge to the proposed rulemaking in the D.C. Circuit, and nine states have joined.
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.
As a result of this continued regulatory focus, future federal GHG regulations of the oil and gas industry remain a possibility. Also, many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities. While it is not possible to predict how any regulations to restrict GHG emissions may come into force, these and other legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs or curtail oil and gas operations in certain areas and could also adversely affect demand for the oil and gas we sell.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
OSHA. We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations, and the provision of such information to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations.

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Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of our facilities are in areas that may be designated as a habitat for endangered species, we believe that we are in substantial compliance with the Endangered Species Act. Moreover, the U.S. Fish and Wildlife Service continues its six-year effort to make listing decisions and critical habitat designations where necessary for over 250 species before the end of the agency’s 2017 fiscal year, as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. The presence of any protected species or the final designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse effect on our ability to develop and produce our reserves.
Employees and Labor Relations
We had a total of 164 employees as of December 31, 2014. We consider our current employee relations to be favorable. We and our employees are not subject to any collective bargaining agreements.
Available Information
Our internet address is http://www.pennvirginia.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics, Audit Committee Charter, Compensation and Benefits Committee Charter and Nominating and Governance Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
Item 1A    Risk Factors
Our business and operations are subject to a number of risks and uncertainties as described below. However, the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we may currently deem immaterial, may become important factors that harm our business, financial condition, 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.
Crude oil, NGL and natural gas 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 crude oil, NGLs and natural gas. Historically, crude oil, NGL and natural gas prices have been volatile, and they are likely to continue to be volatile. In particular, average monthly WTI crude oil prices have decreased from over $105 per barrel in June 2014 to less than $45 per barrel in January 2015. Decreases in commodity prices have led us to curtail drilling and other exploration activities in 2015. Even relatively modest drops in prices can affect significantly our financial results and impede our growth. Wide fluctuations in crude oil, NGLs and natural gas 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:
domestic and foreign supplies of crude oil, NGLs and natural gas;
domestic and foreign consumer demand for crude oil, NGLs and natural gas;
political and economic conditions in oil or gas producing regions;
the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree upon and maintain production constraints and oil price controls;
overall domestic and foreign economic conditions;
prices and availability of, and demand for, alternative fuels;
technological advances affecting energy consumption;
speculation by investors in oil and gas;
the availability, proximity and capacity of gathering, processing, refining and transportation facilities;
weather conditions; and
domestic and foreign governmental regulation and taxation.
It is impossible to predict future oil and gas price movements with certainty. However, many of our projections and estimates are based on assumptions as to the future prices of crude oil, NGLs and natural gas. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future will likely differ

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from our estimates. Any substantial or extended decline in the actual prices of crude oil, NGLs or natural gas would have a material adverse effect on our business, financial position, results of operations and cash flows and borrowing capacity, the quantities of oil and gas reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program. In addition, if we expect or experience significant sustained decreases in crude oil and natural gas prices such that the expected future cash flows from our crude oil and natural gas properties falls below the net book value of our properties, we may be required to write down the value of our crude oil and natural gas properties.  Any such asset impairments could materially and adversely affect our results of operations and, in turn, the trading price of our common stock
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 operating activities. We have historically succeeded in substantially replacing reserves primarily through exploration and development and, to a lesser extent, acquisitions. We have conducted such activities on our existing oil and gas properties as well as on newly acquired properties. We may not be able to continue to replace reserves and production from such activities at acceptable costs. Lower prices also decrease our cash flows from operating activities 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 operating activities are reduced and external sources of capital are limited. In addition, exploration and development activities involve numerous risks that may result in dry holes, the failure to produce oil and gas in commercial quantities and the inability to fully produce discovered reserves.
We are continually identifying and evaluating acquisition opportunities. Competition for oil and gas properties can be intense, however, 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 must make substantial capital expenditures to find, acquire, develop and produce oil and gas reserves. In 2015, we anticipate making capital expenditures, excluding acquisitions, of up to approximately $345 million compared to $794 million in 2014.
If crude oil or NGL prices continue to decrease, natural gas prices fail to recover or we encounter operating difficulties that result in our cash flow from operations being less than expected, we may have to further reduce our capital expenditures unless we have sufficient borrowing capacity under our revolving credit agreement, or the Revolver, or we obtain alternative 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 crude oil, NGLs and natural gas.
If our revenues were to decrease due to lower crude oil, NGL and natural gas prices, decreased production or other reasons, and if we could not obtain capital through the Revolver, or otherwise on acceptable terms, our ability to execute our development plans, replace our reserves or maintain production levels could be greatly limited.
We have a significant amount of indebtedness and our ability to service our indebtedness depends on certain financial, business and other factors, many of which are beyond our control.
As of December 31, 2014, we had an aggregate of approximately $1.1 billion of debt outstanding and would have been able to incur an additional $413.2 million (net of $1.8 million of letters of credit) under the Revolver. We may incur additional indebtedness in the future. Any increase in our level of indebtedness will have several important effects on our future operations, including, without limitation:
we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;
increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry conditions, as well as to competitive pressure; and
depending on the levels of our outstanding debt, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited.
Our ability to make scheduled payments of principal and interest on our indebtedness or to refinance our debt obligations depends on our future financial condition and operating performance, which will be subject to general economic conditions and to certain financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable

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to generate sufficient cash flows from operating activities in the future to service our debt, we may be forced, among other things, to:
seek additional financing in the debt or equity markets;
refinance or restructure all or a portion of our indebtedness;
sell selected assets;
reduce or delay planned capital expenditures; or
reduce or delay planned operating expenditures.
Such measures might not be successful and might not enable us to service our debt. In addition, any such financing, refinancing or sale of assets might not be available on economically favorable terms or at all.
The borrowing base under the Revolver may be reduced in the future if commodity prices remain below recent historical averages.
The borrowing base under the Revolver was $500 million as of December 31, 2014. Our borrowing base is redetermined twice each year and is scheduled to be redetermined during May 2015. If crude oil, NGL or natural gas prices decline or fail to recover to prior levels, the borrowing base under the Revolver may be reduced. As a result, we may be unable to obtain funding under the Revolver. If funding is not available when or in the amounts needed, or is available only on unfavorable terms, it might adversely affect our development plan as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, financial condition, results of operations and cash flows.
The Revolver and our other debt instruments have restrictive covenants that could limit our financial flexibility and our ability to borrow.
The Revolver and the indentures related to our outstanding senior notes contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests.
Our ability to borrow under the Revolver is subject to compliance with certain financial covenants, including leverage and current ratios. Under our current 2015 business plan, we are projected to be operating near the limits of the leverage permitted by the Revolver. If at any time we anticipate that we may exceed such limits, we would be forced to seek a means to cure the potential breach such as requesting a Revolver amendment to increase the permitted leverage, decreasing the pace or magnitude of our capital program or considering a capital markets transaction. There can be no assurance that any of these potential solutions would be successful and, if we were to exceed our leverage limits, we would be in breach of the Revolver.
The Revolver includes other restrictions that, among other things, limit our ability to incur indebtedness; grant liens; engage in mergers, consolidations and liquidations; make asset dispositions, restricted payments and investments; enter into transactions with affiliates; and amend, modify or prepay certain indebtedness. The indentures related to our outstanding senior notes contain limitations on our ability to effect mergers and change of control events, as well as other limitations, including:
limitations on the declaration and payment of dividends or other restricted payments;
limitations on incurring additional indebtedness or issuing preferred stock;
limitations on the creation or existence of certain liens;
limitations on incurring restrictions on the ability of certain of our subsidiaries to pay dividends or other payments;
limitations on transactions with affiliates; and
limitations on the sale of assets.
Our business plan and our compliance with these covenants are based on a number of assumptions, the most important of which is relatively stable oil and gas prices at economically sustainable levels. If the price that we receive for our oil and gas production deteriorates significantly from current levels it could lead to lower revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants contained in our revolving credit facility. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period as the amounts outstanding under our revolving credit facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings. Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.
Exploration and development drilling may not result in commercially productive reserves.
Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or 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:
unexpected drilling conditions;

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elevated pressure or irregularities in geologic formations;
title problems;
equipment failures or accidents;
costs, shortages or delays in the availability of drilling rigs, crews, equipment and materials;
shortages in experienced labor;
surface access restrictions;
failure to or delays in securing necessary regulatory approvals and permits, including delays due to potential hydraulic fracturing regulations;
fires, explosions, blow-outs and surface cratering; and
adverse weather conditions.
The prevailing prices of crude oil, NGLs and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs and equipment can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region. 
The wells we drill may not be productive and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or 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 exposed to the credit risk of our customers, and nonpayment or nonperformance by these parties would reduce our cash flows. 
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. In 2014, approximately 50 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 participate in oil and gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.
We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one party. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. In addition, the possibility of an economic downturn and the volatility in commodity prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established than we, are not able to fulfill their joint activity obligations. Some of our project partners have experienced liquidity and cash flow problems. These problems may lead our partners to attempt to delay the pace of drilling or project development in order to preserve cash. A partner may be unable or unwilling to pay its share of project costs. In some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial condition, results of operations and cash flows.
Our business and prospects for future success depend to a significant extent upon the continued service and performance of our management team.
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.

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Our business depends on gathering, processing, refining and transportation facilities owned by others.
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. 
We rely on third-party service providers to conduct the drilling and completion operations on properties we operate.
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.
Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on the acreage.
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.
Estimates of oil and gas reserves and future net cash flows 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 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, approximately 60 percent of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.
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 20.7 MMBOE of proved undeveloped reserves in 2014 as a result of the five-year limitation. 
You should not assume that the present value of estimated future net cash flows (standardized measure) referred to herein is the current fair value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the

14



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. Actual future net cash flows may also be affected by the amount and timing of actual production, supply and demand for oil and gas, increases or decreases in consumption of oil and gas and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor for us.
We may record impairment losses on our oil and gas properties.
Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment. Lower crude oil, NGL and natural gas prices may have the impact of shortening the economic lives on certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, thus reducing proved property reserve estimates. If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of depreciation, depletion and amortization, or DD&A, on the affected properties, which would decrease earnings or result in losses through higher DD&A expense. The revisions may also be sufficient enough to cause impairment losses on certain properties that would result in a further non-cash charge to reported earnings. 
GAAP requires that the carrying value of oil and gas properties be reviewed on a periodic basis for possible impairment. An impairment charge is recognized when the carrying value of oil and gas properties is greater than the undiscounted future net cash flows attributable to the property. In addition to revisions to reserves and the impact of lower commodity prices, impairments may occur due to increases in estimated operating and development costs 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 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 2014, other companies operated approximately 10 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.
Our property acquisitions carry significant risks.
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 are a relatively small company and therefore may not be able to compete effectively.
Compared to many of our competitors in the oil and gas industry, we are a small company. We face difficulties in competing with larger companies. The costs of doing business in the exploration and production industry, including such costs

15



as those required to explore new oil and natural gas plays, to acquire new acreage, and to develop attractive oil and natural gas projects, are significant. We face intense competition in all areas of our business from companies with greater and more productive assets, substantially larger staffs and greater financial and operating resources than we have. Our limited size has placed us at a disadvantage with respect to funding our operating costs, and means that we are more vulnerable to commodity price volatility and overall industry cycles, are less able to absorb the burden of changes in laws and regulations, and that poor results in any single exploration, development or production play can have a disproportionately negative impact on us.
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 lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with operating primarily in one major contiguous area.
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 a 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 Ford
We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and gas are subject to extensive federal, state and local laws and regulations, including complex environmental laws. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations, inability to obtain necessary regulatory approvals or a failure to comply with existing legal requirements may harm our business, results of operations or financial condition. We may be required to make large expenditures to comply with environmental and other governmental regulations. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, spacing of wells, unitization and pooling of properties, environmental protection and taxation. Our operations create the risk of environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water. In the event of environmental violations, we may be charged with remedial costs and land owners may file claims for alternative water supplies, property damage or bodily injury. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, result in liability for environmental damage regardless of negligence or fault. In addition, pollution and similar environmental risks generally are not fully insurable. These liabilities and costs could have a material adverse effect on our business, financial condition, results of operations and cash flows. See Item 1, “Business — Government Regulation and Environmental Matters.”
Our business involves many operating risks, including hydraulic fracturing, that may result in substantial losses for which insurance may be unavailable or inadequate.
Our operations are subject to all of the risks and hazards typically associated with the exploitation, development and exploration for and the production and transportation of oil and gas, including well stimulation and completion activities such as hydraulic fracturing. These operating risks include:
fires, explosions, blowouts, cratering and casing collapses;
formations with abnormal pressures;
pipeline ruptures or spills;
uncontrollable flows of oil, natural gas or well fluids;
migration of fracturing fluids into surrounding groundwater;
spills or releases of fracturing fluids including from trucks sometimes used to deliver these materials;
spills or releases of brine or other produced water that may go off-site;
subsurface conditions that prevent us from (i) stimulating the planned number of stages, (ii) accessing the entirety of the wellbore with our tools during completion or (iii) removing all fracturing materials from the wellbore to allow production to begin;
environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases; and
natural disasters and other adverse weather conditions, terrorism, vandalism and physical, electronic and cyber security breaches.

16



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:
delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements, which may include limitations on hydraulic fracturing or the discharge of GHGs; and
the need to shut down, abandon and relocate drilling operations;
the need to sample, test and monitor drinking water in particular areas and to provide filtration or other drinking water supplies to users of water supplies that may have been impacted or threatened by potential contamination from fracturing fluids;
the need to modify drill sites to ensure there are no spills or releases off-site and to investigate and/or remediate any spills or releases that might have occurred; or
suspension of our operations.
In accordance with industry practice, we maintain insurance at a level that balances the cost of insurance with our assessment of the risk and our ability to achieve a reasonable rate of return on our investments. We cannot assure you that our insurance will be adequate to cover losses or liabilities or that we 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. 
Access to water to conduct hydraulic fracturing may not be available if water sources become scarce.
The availability of water is crucial to conduct hydraulic fracturing. Approximately 80,000-100,000 gallons of water are necessary for drilling and completing one well with hydraulic fracturing in Texas. In recent years, Texas has experienced severe droughts that have limited the water supplies that are necessary to conduct hydraulic fracturing. Although we have taken measures to secure our water supply, we can make no assurances that sufficient water resources will be available in the short or long term to carry out our current activities.
Laws and regulations restricting emissions of greenhouse gases could force us to incur increased capital and operating costs and could have a material adverse effect on our 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, 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, the EPA proposed to add GHG reporting requirements applicable to petroleum and natural gas systems, including various equipment and systems associated with hydraulic fracturing operations. 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 rule in the summer of 2015 that would cut methane emissions from oil and gas production by up to 45 percent by 2025 from the levels recorded in 2012. 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.
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 fulsome 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 Change.”

17



Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
The practice of hydraulic fracturing has come under increased scrutiny by the environmental community. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into prospective rock formations to stimulate oil and 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. A draft of the study was expected to be released to the public in 2014, but has yet to be issued. 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”) programs. 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.
Restrictions on drilling activities intended to protect certain species of wildlife or their habitat may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
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.
Derivative transactions may limit our potential gains and involve other risks. 
In order to manage our exposure to price risks in the sale of our crude oil, NGLs and natural gas, we periodically enter into 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: 
our production is less than expected;
there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
the counterparties to our futures contracts fail to perform under the contracts; or
a sudden, unexpected event materially impacts crude oil, NGL or natural gas prices.

18



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.
Our ability to use net operating loss carryforwards to offset future taxable income may be subject to certain limitations.
 Our ability to utilize U.S. net operating loss, or NOL, carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended, or the Code. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of our stock by 5% shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. As of December 31, 2014, we do not believe that an ownership change has occurred; however, to the extent an ownership change has occurred or were to occur in the future, it is possible that the limitations imposed on our ability to use pre-ownership change losses could cause a significant net increase in our U.S. federal income tax liability and could cause U.S. federal income taxes to be paid earlier than they otherwise would be paid if such limitations were not in effect.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation.
President Obama’s budget proposal for fiscal year 2015 recommended 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, the repeal of the percentage depletion allowance for oil and gas properties, the elimination of current deductions for intangible drilling and development costs, the elimination of the deduction for United States production activities for oil and gas production, and an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could have a material adverse effect on us.
We may not be able to keep pace with technological developments in our industry.
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.
A cyber incident could result in theft of confidential information, data corruption or operational disruption.
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.
If our systems for protecting against cyber incidents prove not to be sufficient, we could be adversely affected by unauthorized access to our digital systems which could result in theft of confidential information, data corruption or operational disruption. As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and enhance our protective systems or to investigate and remediate any vulnerabilities.
Item 1B
Unresolved Staff Comments
We have received no written SEC staff comments regarding our periodic or current reports under the Exchange Act that were issued 180 days or more preceding the end of our 2014 fiscal year and remain unresolved.

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Item 2
 Properties
The following map shows the general locations of our oil and gas assets as of December 31, 2014:




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

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Summary of Oil and Gas Reserves
Proved Reserves
The following tables summarize certain information regarding our estimated proved reserves as of December 31 for each of the years presented:
 
Crude Oil
 
NGLs
 
Natural
Gas
 
Oil
Equivalents
 
Standardized
Measure
 
Price Measurement Used 1
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
(MMBOE)
 
$ in millions
 
$/Bbl of Oil
 
$/Bbl of NGLs
 
$/MMBtu
2014
 

 
 
 
 

 
 

 
 

 
 

 
 

 
 
Developed
 
 
 
 
 
 

 
 
 
 
 
 
 
 
Producing
21.8

 
7.4

 
77.9

 
42.1

 
$
794.9

 
 
 
 
 
 
Non-producing
0.3

 
0.7

 
16.6

 
3.8

 
8.6

 
 
 
 
 
 
 
22.1

 
8.1

 
94.5

 
45.9

 
803.5

 
 
 
 
 
 
Undeveloped
47.0

 
11.1

 
64.7

 
68.9

 
378.9

 
 
 
 
 
 
 
69.0

 
19.2

 
159.2

 
114.8

 
$
1,182.4

 
$
92.91

 
$
25.49

 
$
4.32

2013

 

 

 

 

 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Producing
19.0

 
7.5

 
146.5

 
50.9

 
$
701.7

 
 
 
 
 
 
Non-producing
0.3

 
1.0

 
16.7

 
4.1

 
7.3

 
 
 
 
 
 
 
19.3

 
8.5

 
163.2

 
55.0

 
709.0

 
 
 
 
 
 
Undeveloped
41.4

 
13.4

 
158.9

 
81.3

 
554.8

 
 
 
 
 
 
 
60.7

 
21.9

 
322.1

 
136.3

 
$
1,263.8

 
$
103.11

 
$
31.10

 
$
3.47

2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Producing
10.2

 
7.0

 
152.0

 
42.5

 
$
408.5

 
 
 
 
 
 
Non-producing
0.3

 
1.2

 
17.4

 
4.5

 
43.0

 
 
 
 
 
 
 
10.5

 
8.3

 
169.4

 
47.0

 
451.5

 
 
 
 
 
 
Undeveloped
14.4

 
12.4

 
238.1

 
66.5

 
46.4

 
 
 
 
 
 
 
24.9

 
20.7

 
407.5

 
113.5

 
$
497.9

 
$
102.24

 
$
39.48

 
$
2.47

___________________
1 Crude oil and natural gas prices were based on average (beginning of month basis) sales prices per Bbl and MMBtu with the representative price of natural gas adjusted for basis premium and energy content to arrive at the appropriate net price. NGL prices were estimated as a percentage of the base crude oil price.
All of our reserves are located in the continental United States. The following table sets forth by region the estimated quantities of proved reserves and the percentages thereof that are represented by proved developed reserves as of December 31, 2014:
 
 
Proved
 
% of Total
Proved
 
% Proved
Region
 
Reserves
 
Reserves
 
Developed
 
 
(MMBOE)
 
 

 
 

Texas
 
 
 


 
 
South Texas
 
94.1

 
82
%
 
29
%
East Texas
 
13.7

 
12
%
 
85
%
Mid-Continent
 
6.9

 
6
%
 
95
%
Other 1
 
0.1

 
%
 
100
%
 
 
114.8

 
100
%
 
40
%
___________________
1 Comprised of our three active Marcellus Shale wells.

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Proved Undeveloped Reserves
The proved undeveloped reserves included in our reserve estimates relate to wells that are forecasted to be drilled within the next five years. The following tables set forth the changes in our proved undeveloped reserves during the year ended December 31, 2014 and the total proved undeveloped reserves as of December 31, 2014 by region:
 
Crude Oil
 
NGLs
 
Natural Gas
 
Oil Equivalents
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
(MMBOE)
Proved undeveloped reserves at beginning of year
41.4

 
13.4

 
158.9

 
81.3

Revisions of previous estimates
(5.1
)
 
(5.4
)
 
(84.2
)
 
(24.5
)
Extensions, discoveries and other additions
18.4

 
5.1

 
26.5

 
28.0

Sale of reserves in place

 

 
(26.1
)
 
(4.4
)
Conversion to proved developed reserves
(7.7
)
 
(2.0
)
 
(10.5
)
 
(11.5
)
Proved undeveloped reserves at end of year
47.0

 
11.1

 
64.7

 
68.9

 
 
 
 
 
 
 
 
Texas
 
 
 
 
 
 
 
South Texas
46.7

 
10.7

 
54.7

 
66.5

East Texas
0.2

 
0.3

 
8.9

 
2.0

Mid-Continent
0.1

 
0.1

 
1.1

 
0.4

 
47.0

 
11.1

 
64.7

 
68.9

In 2014, our proved undeveloped reserves decreased by 12.4 MMBOE. We experienced negative revisions due to locations that are not expected to be drilled during a five-year period primarily in the Cotton Valley and Haynesville Shale (19.1 MMBOE) and the Granite Wash (1.6 MMBOE). We also experienced downward revisions in the Eagle Ford due primarily to the elimination of certain locations (3.8 MMBOE). Extensions, discoveries and other additions of 28.0 MMBOE were attributable to our activities in the Eagle Ford. We sold our Selma Chalk assets in Mississippi resulting in a decrease of 4.4 MMBOE. In addition, we converted 11.5 MMBOE from proved undeveloped to proved developed reserves in the Eagle Ford. During 2014, we incurred capital expenditures of approximately $381 million in connection with the conversion of proved undeveloped reserves to proved developed reserves.
Preparation of Reserves Estimates and Internal Controls
The proved reserve estimates were prepared by Wright & Company, 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, Inc., prepared for us and dated January 9, 2015, 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, 2014 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, Inc. Our Vice President, Operations & Engineering has over 29 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.
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.”
Qualifications of Third Party Petroleum Engineers
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.

22



Oil and Gas Production, Production Prices and Production Costs
Oil and Gas Production by Region
The following tables set forth by region the total production and average daily production for the periods presented:
 
 
 
 
Total Production
for the Year Ended December 31,
Region
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
 
 
 
 
 
 
 
 

 
(MBOE) 
 
 

Texas
 
 
 
 
 
 
 
 
 
 
 
 
South Texas 1
 
 
 
 
 
 
 
5,913

 
4,091

 
2,334

East Texas
 
 
 
 
 
 
 
844

 
1,020

 
1,337

Mid-Continent
 
 
 
 
 
 
 
741

 
937

 
1,211

Other 2
 
 
 
 
 
 
 
437

 
776

 
1,631

 
 

 

 

 
7,934

 
6,824

 
6,513

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average Daily Production
for the Year Ended December 31,
 
 
 
 
 
 
 
 
2014
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
(BOEPD) 
 
 
Texas
 
 
 
 
 
 
 
 
 
 
 
 
South Texas 1
 
 
 
 
 
 
 
16,201

 
11,208

 
6,377

East Texas
 
 
 
 
 
 
 
2,311

 
2,795

 
3,653

Mid-Continent
 
 
 
 
 
 
 
2,029

 
2,567

 
3,309

Other 2
 
 
 
 
 
 
 
1,196

 
2,126

 
4,456

 
 
 
 
 
 
 
 
21,738

 
18,696

 
17,795

_______________________
1 We completed the EF Acquisition in April 2013.
2 Currently consists of our three active Marcellus Shale wells. We sold all of our properties in the Selma Chalk in Mississippi in July 2014, which represented annual production and average daily production of approximately 412 MBOE (1,946 BOEPD), 751 MBOE (2,058 BOEPD) and 847 MBOE (2,314 BOEPD) in 2014, 2013 and 2012, respectively. We sold all of our properties in West Virginia, Kentucky and Virginia in July 2012, which represented annual production and average daily production of approximately 741 MBOE (2,100 BOEPD) in 2012.
Production Prices and Production Costs
The following table sets forth the average sales prices per unit of volume and our average production costs, not including ad valorem and production/severance taxes, per unit of production for the periods presented:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Average prices:
 
 
 
 
 
Crude oil ($ per Bbl)
$
90.50

 
$
101.13

 
$
101.95

NGLs ($ per Bbl)
$
31.14

 
$
31.30

 
$
35.13

Natural gas ($ per Mcf)
$
4.44

 
$
3.64

 
$
2.46

Aggregate ($ per BOE)
$
64.64

 
$
63.11

 
$
47.67

Average production and lifting cost ($ per BOE):
 
 
 
 
 
Lease operating
$
6.09

 
$
5.20

 
$
4.80

Gathering processing and transportation
2.31

 
1.88

 
2.18

 
$
8.40

 
$
7.08

 
$
6.98


23



Significant Fields
Our properties in the Eagle Ford in South Texas, which contain primarily oil reserves, represent approximately 82 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.
The following table sets forth certain information with respect to this field for the periods presented:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Production:
 

 
 

 
 

Crude oil (MBbl)
4,450

 
3,197

 
1,960

NGLs (MBbl)
773

 
478

 
205

Natural gas (MMcf)
4,070

 
2,406

 
1,015

Total (MBOE)
5,901

 
4,077

 
2,334

Percent of total company production
74
%
 
60
%
 
36
%
Average prices:
 
 
 
 
 
Crude oil ($ per Bbl)
$
90.57

 
$
101.55

 
$
103.33

NGLs ($ per Bbl)
$
25.23

 
$
26.68

 
$
31.43

Natural gas ($ per Mcf)
$
4.20

 
$
3.52

 
$
2.56

Aggregate ($ per BOE)
$
74.49

 
$
84.85

 
$
90.63

Average production and lifting cost ($ per BOE)1:
 
 
 
 
 
Lease operating
$
5.36

 
$
4.30

 
$
3.12

Gathering processing and transportation
1.76

 
1.08

 
0.72

 
$
7.12

 
$
5.38

 
$
3.84

______________
1 Excludes production/severance and ad valorem taxes.
Drilling and Other Exploratory and Development Activities
The following table sets forth the gross and net development and exploratory wells that we drilled during the years ended December 31, 2014, 2013 and 2012 and wells that were in progress at the end of each year. The number of wells drilled refers to the number of wells completed at any time during the year, regardless of when drilling was initiated. 
 
2014
 
2013
 
2012
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development
 

 
 

 
 

 
 

 
 

 
 

Productive
83

 
50.8

 
58

 
34.1

 
36

 
27.8

Non-productive
1

 
0.8

 

 

 

 

Under evaluation

 

 
1

 
0.5

 

 

Total development
84

 
51.6

 
59

 
34.6

 
36

 
27.8

 
 
 
 
 
 
 
 
 
 
 
 
Exploratory
 

 
 

 
 

 
 

 
 

 
 

Productive

 

 

 

 
5

 
3.9

Non-productive

 

 

 

 

 

Under evaluation

 

 

 

 
1

 
1.0

Total exploratory

 

 

 

 
6

 
4.9

Total
84

 
51.6

 
59

 
34.6

 
42

 
32.7

 
 
 
 
 
 
 
 
 
 
 
 
Wells in progress at end of year1
28

 
14.3

 
16

 
11.5

 
3

 
2.7

___________
1 Includes 12 gross (5.4 net) wells completing or flowing back, 11 gross (5.9 net) waiting on completion and five gross (3.0 net) wells being drilled as of December 31, 2014.

24



The following table sets forth the regions in which we drilled our wells for the periods presented:
 
 
2014
 
2013
 
2012
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Texas
 
 
 
 
 
 
 
 
 
 
 
 
South Texas 1
 
84

 
51.6

 
57

 
34.1

 
35

 
29.5

East Texas
 

 

 

 

 

 

Mid-Continent
 

 

 
2

 
0.5

 
7

 
3.2

Other
 

 

 

 

 

 

 
 
84

 
51.6

 
59

 
34.6

 
42

 
32.7

_____________
1 Includes six gross (2.2 net) wells acquired in 2013 in connection with the EF Acquisition that were in progress when acquired.
Present Activities
As of December 31, 2014, we had 28 gross (14.3 net) wells in progress, all of which were located in the Eagle Ford in South Texas. As of February 20, 2015, 17 gross (8.6 net) of these wells had been successfully completed and were producing.
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 not have any material commitments to provide a fixed and determinable quantity of our products beyond the current month.
Productive Wells
The following table sets forth by region the productive wells in which we had a working interest as of December 31, 2014:
 
 
Primarily Oil
 
Primarily Natural Gas
 
Total
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Texas
 
 
 
 
 
 
 
 
 


 


South Texas 1
 
275

 
175.2

 

 

 
275

 
175.2

East Texas
 

 

 
356

 
254.9

 
356

 
254.9

Mid-Continent
 
5

 
3.1

 
99

 
42.6

 
104

 
45.7

Other 2
 

 

 
3

 
3.0

 
3

 
3.0

 
 
280

 
178.3

 
458

 
300.5

 
738

 
478.8

_______________________
1 Includes wells in both the lower and upper Eagle Ford, or Marl, as well as the Pearsall Shale and Austin Chalk.
2 Consists of our three active Marcellus wells.
Of the total wells presented in the table above, we are the operator of 607 gross (246 oil and 361 gas) and 433.0 net (165.3 oil and 267.7 gas) wells. In addition to the above working interest wells, we own royalty interests in nine gross wells.
Acreage
The following table sets forth by region our developed and undeveloped acreage as of December 31, 2014 (in thousands):
 
 
Developed 
 
Undeveloped 
 
Total 
Region
 
Gross 
 
Net 
 
Gross 
 
Net 
 
Gross 
 
Net 
Texas
 
 
 
 
 
 
 
 
 


 


South Texas
 
70.4

 
45.2

 
69.3

 
56.6

 
139.7

 
101.8

East Texas
 
45.3

 
32.0

 
2.1

 
0.6

 
47.4

 
32.6

Mid-Continent
 
16.5

 
8.0

 
5.0

 
1.8

 
21.5

 
9.8

Other
 
1.7

 
1.3

 
13.7

 
13.1

 
15.4

 
14.4

 
 
133.9

 
86.5

 
90.1

 
72.1

 
224.0

 
158.6


25



The primary terms of our leases generally range from three to five years and we do not have any concessions. As of December 31, 2014, our net undeveloped acreage is scheduled to expire as shown in the table below, unless the primary lease terms are, where appropriate, extended, HBP or otherwise changed:
 
2015
 
2016
 
2017
 
Thereafter
Percent of gross undeveloped acreage
20
%
 
44
%
 
24
%
 
12
%
Percent of net undeveloped acreage
15
%
 
45
%
 
26
%
 
14
%
We do not believe that the scheduled expiration of our undeveloped acreage will substantially affect our ability or plans to conduct our exploration and development activities.
 
Item 3
Legal Proceedings
See Note 12 to our Consolidated Financial Statements included in Item 8,“Financial Statements and Supplementary Data,” for a more detailed discussion of our legal contingencies. 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.

Item 4
Mine Safety Disclosures
Not applicable.
Part II

 Item 5
Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock is traded on the NYSE under the symbol “PVA.” The high and low sales prices (composite transactions) related to each fiscal quarter in 2014 and 2013 were as follows:
 
 
 
 
 
 
 
 
 
 
 
Sales Price
Quarter Ended
 
 
 
High
 
Low
December 31, 2014
 
 
 
$
12.89

 
$
4.32

September 30, 2014
 
 
 
$
17.20

 
$
11.53

June 30, 2014
 
 
 
$
18.20

 
$
13.54

March 31, 2014
 
 
 
$
18.04

 
$
8.91

December 31, 2013
 
 
 
$
11.21

 
$
6.50

September 30, 2013
 
 
 
$
6.72

 
$
4.50

June 30, 2013
 
 
 
$
5.17

 
$
3.56

March 31, 2013
 
 
 
$
5.00

 
$
3.97

Equity Holders
As of February 20, 2015, there were 378 record holders and 17,927 beneficial owners (held in street name) of our common stock.
Dividends
In July 2012, we discontinued the quarterly dividend on our common stock. Although our future dividend policy is within the discretion of our board of directors and will depend on various factors, we do not anticipate declaring or paying dividends in the foreseeable future.
Securities Authorized for Issuance Under Equity Compensation Plans
See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” and Note 14 to our Consolidated Financial Statements included in Item 8. “Financial Statements and Supplementary Data” for information regarding shares of common stock authorized for issuance under our stock compensation plans.

26



Issuer Purchases of Equity Securities
We did not repurchase any shares of our common stock in the fourth quarter of 2014.
A portion of the compensation paid to certain non-employee members of our board of directors is paid in deferred common stock units. Each deferred common stock unit represents one share of common stock, vests immediately upon issuance, and is available to the holder upon 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.

Performance Graph
The following graph compares our five-year cumulative total shareholder return (assuming reinvestment of dividends) with the cumulative total return of the Standard & Poor’s 600 Oil & Gas Exploration & Production Index and the Standard & Poor’s Small Cap 600 Index. As of December 31, 2014, there were eleven exploration and production companies in the Standard & Poor’s 600 Oil & Gas Exploration & Production Index: Approach Resources Inc., Bill Barret Corporation, Bonanza Creek Energy Inc, Carrizo Oil & Gas, Inc., Comstock Resources, Inc., Contango Oil & Gas Company, Northern Oil & Gas, Inc., PDC Energy, Inc., Penn Virginia Corporation, PetroQuest Energy, Inc., Stone Energy Corporation, Swift Energy Company and Synergy Resources Corporation. The graph assumes $100 is invested on January 1, 2010 in us and each index at December 31, 2009 closing prices.
 
December 31,
 
2010
 
2011
 
2012
 
2013
 
2014
Penn Virginia Corporation
$
79.99

 
$
25.78

 
$
21.96

 
$
46.96

 
$
33.26

S&P Small Cap 600 Index
$
126.31

 
$
127.59

 
$
148.42

 
$
209.74

 
$
221.81

S&P 600 Oil & Gas Exploration & Production Index
$
145.40

 
$
139.60

 
$
123.73

 
$
173.52

 
$
106.22

 

27



Item 6
Selected Financial Data
The following selected historical financial and operating information was derived from our Consolidated Financial Statements as of and for the years ended December 31, 2014, 2013, 2012, 2011 and 2010. 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.”
 
2014
 
2013
 
2012
 
2011
 
2010
 
(in thousands, except per share amounts)
Statements of Operations Data:
 

 
 

 
 

 
 

 
 

Revenues
$
636,773

 
$
431,468

 
$
317,149

 
$
306,005

 
$
254,438

Operating loss 1
$
(615,985
)
 
$
(92,046
)
 
$
(147,091
)
 
$
(155,419
)
 
$
(98,808
)
Loss from continuing operations
$
(409,592
)
 
$
(143,070
)
 
$
(104,589
)
 
$
(132,915
)
 
$
(65,327
)
Net income (loss)
$
(409,592
)
 
$
(143,070
)
 
$
(104,589
)
 
$
(132,915
)
 
$
19,667

Loss attributable to Penn Virginia Corporation
$
(409,592
)
 
$
(143,070
)
 
$
(104,589
)
 
$
(132,915
)
 
$
(8,423
)
Preferred stock dividends
$
17,148

 
$
6,900

 
$
1,687

 
$

 
$

Loss attributable to common shareholders
$
(430,996
)
 
$
(149,970
)
 
$
(106,276
)
 
$
(132,915
)
 
$
(8,423
)
Common Stock Data 2:
 

 
 

 
 

 
 

 
 

Earnings (loss) per common share, basic
 

 
 

 
 

 
 

 
 

Continuing operations
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
 
$
(2.90
)
 
$
(1.44
)
Discontinued operations
$

 
$

 
$

 
$

 
$
0.12

Gain on sale of discontinued operations
$

 
$

 
$

 
$

 
$
1.13

Net income (loss)
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
 
$
(2.90
)
 
$
(0.19
)
Earnings (loss) per common share, diluted
 

 
 

 
 

 
 

 
 

Continuing operations
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
 
$
(2.90
)
 
$
(1.44
)
Discontinued operations
$

 
$

 
$

 
$

 
$
0.12

Gain on sale of discontinued operations
$

 
$

 
$

 
$

 
$
1.13

Net income (loss)
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
 
$
(2.90
)
 
$
(0.19
)
Weighted-average shares outstanding:
 

 
 

 
 

 
 

 
 

Basic
68,887

 
62,335

 
47,919

 
45,784

 
45,553

Diluted
68,887

 
62,335

 
47,919

 
45,784

 
45,553

Actual shares outstanding at year-end
71,569

 
65,307

 
55,117

 
45,714

 
45,557

Dividends declared per share of common stock
$

 
$

 
$
0.1125

 
$
0.225

 
$
0.225

Market value at year-end
$
6.68

 
$
9.43

 
$
4.41

 
$
5.29

 
$
16.82

Number of shareholders
18,306

 
11,335

 
7,656

 
6,787

 
6,708

Preferred Stock Data3:
 
 
 
 
 
 
 
 
 
Actual shares outstanding at year-end
19,445

 
11,500

 
11,500

 

 

Dividends declared per share of preferred stock
$
600.00

 
$
600.00

 
$
146.67

 
$

 
$

Balance Sheet and Other Financial Data:
 

 
 

 
 

 
 

 
 

Property and equipment, net
$
1,825,098

 
$
2,237,304

 
$
1,723,359

 
$
1,777,575

 
$
1,705,584

Total assets
$
2,226,434

 
$
2,507,087

 
$
1,842,989

 
$
1,943,053

 
$
1,944,600

Total debt
$
1,110,000

 
$
1,281,000

 
$
594,759

 
$
697,307

 
$
506,536

Shareholders’ equity
$
675,817

 
$
788,804

 
$
895,116

 
$
846,309

 
$
980,276

Cash provided by operating activities
$
282,724

 
$
261,512

 
$
241,458

 
$
144,741

 
$
79,839

Cash paid for capital expenditures
$
774,139

 
$
504,203

 
$
370,907

 
$
445,623

 
$
405,994

Other Statistical Data:
 

 
 

 
 

 
 

 
 

Total production (MBOE)
7,934

 
6,824

 
6,513

 
7,759

 
7,867

Proved reserves (MMBOE)
115

 
136

 
113

 
147

 
157

_____________________
1 Operating loss for 2014, 2013, 2012, 2011 and 2010 included impairment charges of $791.8 million, $132.2 million, $104.5 million, $104.7 million and $46.0 million respectively.
2 Our former coal and natural resource management and natural gas midstream businesses are reported as discontinued operations for 2010.
3 Outstanding preferred stock is in the form of 794,463 depositary shares each representing a 1/100th ownership interest in a share of our 6% Series A Convertible Perpetual Preferred Stock, or Series A Preferred Stock, and 3,250,000 depositary shares each representing a 1/100th ownership interest in a share of our 6% Series B Convertible Perpetual Preferred Stock, or Series B Preferred Stock. Each share of the Series A and B Preferred Stock has a liquidation preference of $10,000 per share or $100 per depositary share.

28



Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations 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. Certain year-over-year changes are presented as not meaningful, or “NM,” where disclosure of the actual value does not otherwise enhance the analysis. Also, due to the combination of different units of volumetric measure and the number of decimal places presented, certain results may not calculate explicitly from the values presented in the tables.
 Overview and Executive Summary
We are an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various onshore regions of the United States. Our current operations consist primarily of drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma and the Haynesville Shale and Cotton Valley in East Texas. As of December 31, 2014, we had proved oil and gas reserves of approximately 115 MMBOE.
The following table sets forth certain summary operating and financial statistics for the periods presented: 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Total production (MBOE)
7,934

 
6,824

 
6,513

Average daily production (BOEPD)
21,738

 
18,696

 
17,795

Crude oil and NGL production (MBbl)
5,754

 
4,417

 
3,136

Crude oil and NGL production as a percent of total
73
%
 
65
%
 
48
%
Product revenues, as reported
$
512,882

 
$
430,693

 
$
310,484

Product revenues, adjusted for derivatives
$
505,458

 
$
429,651

 
$
338,802

Crude oil and NGL revenues as a percent of total, as reported
89
%
 
88
%
 
84
%
Realized prices:
 
 
 
 
 
Crude oil ($/Bbl)
$
90.50

 
$
101.13

 
$
101.95

NGL ($/Bbl)
$
31.14

 
$
31.30

 
$
35.13

Natural gas ($/Mcf)
$
4.44

 
$
3.64

 
$
2.46

Aggregate ($/BOE)
$
64.64

 
$
63.11

 
$
47.67

Production and lifting costs ($/BOE):
 
 
 
 
 
Lease operating
$
6.09

 
$
5.20

 
$
4.80

Gathering, processing and transportation
$
2.31

 
$
1.88

 
$
2.18

Production and ad valorem taxes ($/BOE)
$
3.53

 
$
3.28

 
$
1.63

General and administrative ($/BOE) 1
$
5.15

 
$
6.46

 
$
5.96

Total operating costs ($/BOE)
$
17.08

 
$
16.82

 
$
14.57

Depreciation, depletion and amortization ($/BOE)
$
37.85

 
$
35.99

 
$
31.68

Cash provided by operating activities 2
$
282,724

 
$
261,512

 
$
241,458

Cash paid for capital expenditures, excluding 2013 EF Acquisition
$
774,139

 
$
504,203

 
$
370,907

Cash and cash equivalents at end of period
$
6,252

 
$
23,474

 
$
17,650

Debt outstanding, net of discount, at end of period
$
1,110,000

 
$
1,281,000

 
$
594,759

Credit available under revolving credit facility at end of period 3
$
413,196

 
$
191,346

 
$
297,922

Proved reserves (MMBOE)
115

 
136

 
113

Net development wells drilled
51.6

 
34.6

 
27.8

Net exploratory wells drilled

 

 
4.9

______________________________
1 Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.46, $0.84 and $0.98 and liability-classified share-based compensation of $0.57, $0.60 and $0.11 for the years ended December 31, 2014, 2013 and 2012.
2 Includes the receipt of a federal income tax refund of approximately $32 million in the year ended December 31, 2012 attributable to 2010 and prior years.
3 As reduced by outstanding borrowings and letters of credit. Also, excludes an additional $50 million attributable to the excess of the borrowing base of $500 million over the current commitment of $450 million for 2014.


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In 2014, our crude oil and NGL production increased to 73 percent compared to 65 percent of our total production in 2013. Consistent with our growth in liquids-focused production, our cash from operating activities, excluding working capital changes, increased approximately $41 million, or 17 percent, for 2014 compared to 2013, despite declining crude oil and NGL prices during the second half of 2014.
Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. Since our initial acquisition in this region in 2010 and through February 20, 2015, we have added a total of 280 gross wells, including 246 gross wells that are operated by us and 34 gross wells that are operated by our partners. We are currently operating a total of three drilling rigs, all in the Eagle Ford. Our capital program, which is substantially dedicated to this play, is being financed with a combination of cash from operating activities and borrowings under the Revolver.
To mitigate the volatile effect of commodity price fluctuations, we have a comprehensive hedging program in place. The Financial Condition discussion that follows and Note 5 to the Consolidated Financial Statements provide a detailed summary of our open commodity derivative positions as well as the historical results of our hedging program for the years ended December 31, 2014, 2013 and 2012.
Key Developments
The following general business developments and corporate actions in 2014 had or are expected to have a significant impact on our results of operations, financial position and cash flows: (i) significant decline in commodity prices and the addition of crude oil hedge contracts for calendar year 2015 and 2016, (ii) drilling results and future development plans in the Eagle Ford, (iii) an increase in our borrowing base under the Revolver, (iv) the acquisition of additional Eagle Ford acreage, (v) the sale of our Mississippi assets, South Texas oil gathering rights and South Texas natural gas gathering and gas lift assets, (vi) the resolution of arbitration related to the EF Acquisition and (vii) our recent preferred stock offering.
Significant Decline in Commodity Prices and Addition of Crude Oil Hedge Contracts for Calendar Years 2015 and 2016
In the second half of 2014, commodity prices, particularly crude oil, began to decline from recent high levels. The decline became precipitous late in the fourth quarter of 2014 and into the first quarter of 2015. As discussed below, the significant magnitude of this price decline has led to substantial changes in our operating and drilling programs.
In addition to adjusting our capital program as a result of the decline in commodity pricing, we were also able to enter into additional crude oil derivative contracts for calendar years 2015 and 2016 in order to hedge a portion of our crude oil production for those periods prior to the most significant price declines. Accordingly, in 2014, we provided additional hedge contracts for an average of 9,500 BOPD at a weighted-average price of $89.47 per Bbl for 2015 and 4,000 BOPD at a price of $88.12 per Bbl for 2016. The addition of these contracts has increased our total hedged crude oil production to 13,000 BOPD at a weighted-average price of $90.48 per Bbl for the first half of 2015 and 11,000 BOPD at a weighted-average price of $89.86 per Bbl for the second half of 2015. As a result of these activities, approximately 80 to 90 percent of our total estimated crude oil production for 2015 is subject to favorable hedges.
Drilling Results and Future Development Plans for the Eagle Ford
During 2014, we completed and turned in line 84 gross (51.6 net) operated wells in the Eagle Ford. Our Eagle Ford production was 17,459 net barrels of oil equivalent per day, or BOEPD, during the three months ended December 31, 2014 with oil comprising 12,676 BOPD, or 73 percent, and NGLs and natural gas comprising approximately 14 percent and 13 percent, respectively. In the month of December 2014, our average Eagle Ford production was 18,636 BOEPD, 71 percent of which was crude oil, 15 percent was NGLs and 14 percent was natural gas.
Beginning in March 2014, we have completed and turned in line 17 Upper Eagle Ford wells, including one well that had an operational issue. The average IP rate for the other 16 wells was1,217 BOEPD (61 percent crude oil) and the average 30-day rate for 14 of these 16 wells with sufficient production history was 1,009 BOEPD (61 percent crude oil). The early performance and lower initial rates of decline for the Upper Eagle Ford wells are an improvement over what we have experienced thus far in the Lower Eagle Ford. The internal EUR for these wells averaged approximately 717 MBOE, with a range of 388 to 1,231 MBOE. Due to these favorable results, we plan to devote approximately 42 percent of our 2015 capital expenditures to drilling additional Upper Eagle Ford wells.
Our total capital expenditures for 2015 are anticipated to be up to approximately $345 million, of which 90 percent has been allocated to drilling and completion activities. We intend to operate three to four drilling rigs in the Eagle Ford during 2015. We expect to drill and complete approximately 64 gross wells in the Eagle Ford in 2015 including 24 gross wells in the Upper Eagle Ford. We anticipate our 2015 drilling and completion costs to decrease from 2014 levels as a result of: (i) a decrease in the number of frac stages per well due to an increase in the distance between stages, (ii) a reduction in the amount of proppant per stage, (iii) renegotiated service sector costs and (iv) an ongoing improvement in operational execution of the drilling and completion program.

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Borrowing Base Increase
In October 2014, the borrowing base under the Revolver was increased to $500 million from $437.5 million in connection with our regular semi-annual redetermination. For more information about our Revolver, please read “Capital Resources—Revolver Borrowings.”
Acquisition of Additional Eagle Ford Acreage
In July 2014, we entered into a definitive agreement to acquire approximately 13,125 gross (11,660 net) acres in Lavaca County, Texas, the vast majority of which are in the “volatile oil window” of the Eagle Ford. The transaction closed in August 2014 for $45.6 million, of which $34.9 million was paid at closing and the balance of $10.6 million will be paid over the next three years as a drilling carry. We anticipate commencing drilling activities on this acreage in 2015. The transaction, combined with recent leasing, brings our total Eagle Ford acreage position to approximately 140,000 gross (101,800 net) acres. The acquired acreage, most of which we expect will be prospective in the Upper Eagle Ford, is adjacent to our Shiner area.
2014 Asset Dispositions
Sale of Mississippi Assets. In July 2014, we sold our Selma Chalk assets in Mississippi for proceeds of $67.9 million, net of transaction costs and customary closing adjustments. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 to write down these assets to their estimated fair value.
Sale of Rights to Construct an Oil Gathering System in South Texas. In July 2014, we sold the rights to construct a crude oil gathering and intermediate transportation system in South Texas to Republic Midstream, LLC, or Republic, for proceeds of $147.1 million, net of transaction costs. Concurrent with the sale, we entered into agreements with Republic to provide us gathering and intermediate pipeline transportation services for a substantial portion of our South Texas crude oil and condensate production for a term of 25 years. We realized a gain of $147.1 million, of which $63.0 million was recognized upon the closing of the transaction and the remaining $84.1 million was deferred and will be recognized over a twenty-five year period after the system has been constructed and is operational, currently expected to be in the third quarter of 2015.
Sale of South Texas Natural Gas Gathering and Gas Lift Assets. In January 2014, we sold our natural gas gathering and gas lift assets in South Texas to American Midstream Partners, LP, or AMID, for proceeds of approximately $96 million, net of transaction costs. Concurrent with the sale, we entered into an agreement with AMID to provide us natural gas gathering, compression and gas lift services for a substantial portion of our current and future South Texas natural gas production. We realized a gain of $67.3 million, of which $56.7 million was recognized upon the closing of the transaction and the remaining $10.6 million was deferred and is being recognized over a twenty-five year period.
Settlement of Arbitration
Commencing December 2013, we were involved in arbitration with Magnum Hunter Resources Corporation, or MHR, the seller in the EF Acquisition. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. In July 2014, we received the arbitrators determination, which required MHR to pay us a total of $35.1 million, including purchase price adjustments, revenue suspense funds due to partners and royalty owners and interest ($1.3 million) on the funds since the date of acquisition. Payment of the arbitration settlement was made by MHR in August 2014.
Preferred Stock Offering and Induced Conversion of Outstanding Preferred Stock
In June 2014, we completed a private offering of 3,250,000 depositary shares each representing 1/100th interest in a share of our 6% Series B Convertible Perpetual Preferred Stock, or the Series B Preferred Stock, for approximately $313 million of proceeds, net of underwriting fees and issuance costs. Concurrent with the Series B Preferred Stock offering and subsequently in July 2014, we paid a total of $4.3 million to induce the conversion of 3,527 shares, or 352,732 depositary shares, of our 6% Series A Convertible Perpetual Preferred Stock, or the Series A Preferred Stock. A total of 5.9 million shares of our common stock were issued in connection with the induced conversion of the Series A Preferred Stock.



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Results of Operations
Production 
The following tables set forth a summary of our total and daily production volumes by product and geographic region for the periods presented (certain results in the tables below may not calculate due to rounding): 
 
Total Production
 
Average Daily Production
Crude oil
Year Ended December 31,
 
2014 vs.
 
2013 vs.
 
Year Ended December 31,
 
2014 vs.
 
2013 vs.
 
2014
 
2013
 
2012
 
2013
 
2012
 
2014
 
2013
 
2012
 
2013
 
2012
 
(MBbl)
 
(Bbl per day)
Texas
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
South Texas
4,459

 
3,199

 
1,960

 
1,259

 
1,240

 
12,216

 
8,766

 
5,354

 
3,451

 
3,412

East Texas
54

 
63

 
71

 
(10
)
 
(8
)
 
148

 
174

 
194

 
(26
)
 
(20
)
Mid-Continent
126

 
160

 
206

 
(35
)
 
(46
)
 
345

 
440

 
563

 
(94
)
 
(124
)
Other
5

 
12

 
15

 
(7
)
 
(3
)
 
14

 
33

 
41

 
(19
)
 
(8
)
 
4,644

 
3,435