Attached files

file filename
EX-31.1 - EXHIBIT 31.1 - PENN VIRGINIA CORPpva-20151231xex311.htm
EX-21.1 - SUBSIDIARIES OF PENN VIRGINIA CORPORATION - PENN VIRGINIA CORPpva-20151231xex211.htm
EX-23.2 - CONSENT OF DEGOLYER AND MACNAUGHTON, INC - PENN VIRGINIA CORPpva-20151231xex232.htm
EX-12.1 - EXHIBIT 12.1 - PENN VIRGINIA CORPpva-20151231xex121.htm
EX-32.2 - EXHIBIT 32.2 - PENN VIRGINIA CORPpva-20151231xex322.htm
EX-32.1 - EXHIBIT 32.1 - PENN VIRGINIA CORPpva-20151231xex321.htm
EX-31.2 - EXHIBIT 31.2 - PENN VIRGINIA CORPpva-20151231xex312.htm
EX-99.1 - EXHIBIT 99.1 - PENN VIRGINIA CORPpva-20151231xex991.htm
EX-23.1 - CONSENT OF KPMG LLP - PENN VIRGINIA CORPpva-20151231xex231.htm
EX-10.1.11 - EXHIBIT 10.1.11 - PENN VIRGINIA CORPpva-20151231xex10111.htm


 
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, 2015
 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:
Title of each class
 
Name of exchange on which registered
Common Stock, $0.01 Par Value
 
Not Applicable

Securities registered pursuant to Section 12(g) of the Act: None
__________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes  ¨    No  ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934 (“Exchange Act”).    Yes  ¨    No  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
o
 
Accelerated filer
ý
 
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 $310,407,928 as of June 30, 2015 (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 March 4, 2016, 86,353,944 shares of common stock of the registrant were outstanding.
 
 




PENN VIRGINIA CORPORATION AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K
 For the Fiscal Year Ended December 31, 2015
 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
 
Financial Condition
 
Results of Operations
 
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: 

our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms;
our ability to continue as a going concern;
our ability to refinance our debt obligations;
compliance with debt covenants;
reductions in the borrowing base under our revolving credit facility, or the Revolver;
our ability to continue to borrow under the Revolver;
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 resumption of our drilling program;
the projected demand for and supply of oil, natural gas liquids and natural gas;
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;
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, 2015.
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.

1



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.
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.
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.
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.
NYSE. New York Stock Exchange.
Operator. The entity responsible for the exploration and/or production of a lease or well.
OTC Pink. A marketplace, maintained by the OTC Markets Group, for trading in a wide spectrum of equity securities.
Play. A geological formation with potential oil and gas reserves.

2



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.
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.
SEC. United States Securities and Exchange Commission.
Service well. A well drilled or completed for the purpose of supporting production in an existing field.
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.
Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production.
Unconventional. Generally refers to hydrocarbon reservoirs that lack discrete boundaries that typically define conventional reservoirs. Examples include 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.



3



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 onshore exploration, development and production of crude oil, NGLs and natural gas. Our current operations consist primarily of operating our producing wells in the Eagle Ford Shale field, or Eagle Ford, in South Texas. We also have less significant operations in Oklahoma, primarily in the Granite Wash. We were incorporated in the Commonwealth of Virginia in 1882. Our common stock is publicly traded on the OTC Pink under the symbol “PVAH” subsequent to our delisting from the NYSE on January 12, 2016. Our common stock was previously traded on the NYSE under the symbol “PVA.” Our headquarters and corporate office is located in Radnor, Pennsylvania, and our operations are conducted primarily from our office in Houston, Texas. We also have an operations office near our Eagle Ford assets in South Texas.
We operate in and report our financial results and disclosures as one segment, which is 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.
We own a highly contiguous position of approximately 100,000 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 a more than 15-year drilling inventory. In 2015, we spent over $300 million, or substantially all, of our capital expenditures on our Eagle Ford operations and those operations accounted for 7.0 MMBOE, or 88 percent, of our 7.9 MMBOE total production.
We produce predominantly crude oil and NGLs. In 2015, our total production was comprised of 80 percent crude oil and NGLs and 20 percent natural gas. Crude oil and NGLs accounted for 90 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.
As of December 31, 2015, our proved reserves were approximately 44 MMBOE, of which 75 percent were proved developed reserves and 84 percent were oil and NGLs. We drilled and completed 61 gross (38.6 net) wells, all in Eagle Ford, in 2015. As of December 31, 2015, we had 432 gross (254.7 net) productive wells, approximately 86 percent of which we operate, and owned approximately 166,000 gross (120,000 net) acres of leasehold and royalty interests, approximately 54 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 divested essentially all of our natural gas-focused assets located in East Texas, Mississippi, Appalachia and the Arkoma Basin. In 2014, we sold our natural gas gathering and gas lift infrastructure assets in South Texas as well as the rights to construct an oil gathering system in South Texas. We received aggregate proceeds of approximately $535 million from these transactions. These proceeds were invested primarily in our Eagle Ford operations.
Industry Operating Environment and Outlook
Crude oil prices remained significantly depressed in 2015 and face continued pressure due to domestic and global supply and demand factors. The downward price pressure intensified in late 2015 and early 2016, with crude oil prices dropping below $27 per barrel in February 2016. Natural gas prices faced similar downward pressure in 2015, dropping below $1.70 per MMBtu in December 2015.
In response to these price declines, and given the uncertainty regarding the timing and magnitude of any price recovery, we have suspended our drilling activities. While we intend to resume drilling in 2016, there can be no assurance that we will have adequate capital to do so.
We have also taken other actions set forth below in response to low commodity prices:
completed an amendment to our Revolver;
reduced our drilling and completion costs through (i) contract renegotiations, (ii) improved techniques and (iii) capitalizing on lower industry pricing for related products and services;
sold all of our assets in East Texas for net proceeds of approximately $73 million in August 2015 and sold certain non-core Eagle Ford properties for net proceeds of approximately $13 million in October 2015;
suspended payment of dividends on our convertible preferred stock;
reduced our employee headcount by approximately 40 percent from year-end 2014 levels through administrative and operations restructuring initiatives taken in May and October 2015 and February 2016; and
engaged Kirkland & Ellis LLP, or K&E, and Jefferies LLC, or Jefferies, to advise us with respect to various financing and debt restructuring options.

4



For additional financial and other information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and Notes thereto included in Item 8, “Financial Statements and Supplementary Data.”
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.
Oil gathering and transportation service contracts. We have entered into agreements to provide us gathering, intermediate pipeline transportation and supplemental trucking services for a substantial portion of our Eagle Ford crude oil and condensate production. The gathering agreement has a 25-year term and the intermediate transportation agreement has a 10-year term, which is expected to commence in the first half of 2016.
Natural gas service contracts. We have entered into an agreement that provides gas lift, gathering, compression and transportation services for a substantial portion of our natural gas production in the South Texas region until 2039. 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. These contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We attempt to sell excess capacity to third parties at our discretion.
Drilling and Completion. Historically, we have had agreements with several vendors to provide oil and gas well drilling and well completion services. Generally, these agreements have been on a month-to-month basis, but from time to time we have entered into agreements for longer terms, some of which may include early termination provisions that require us to pay penalties if we terminate the agreements prior to the end of their original terms. Given the current industry environment and our recent decision to temporarily suspend our drilling operations, we currently have only one drilling contract with respect to which we have given early termination notice. That contract will expire on March 20, 2016, and we could be obligated to pay up to approximately $1.2 million in early termination charges.
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, 2015, approximately 64 percent of our consolidated product revenues were attributable to three customers: Phillips 66 Company; Sunoco Refining and Marketing, Inc.; and BP Products North America 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. 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. In the past, competition has been particularly intense in the acquisition of prospective oil and gas properties. Many of our larger competitors may have a competitive advantage when responding to commodity price volatility and overall industry cycles.
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, 2015, we have recorded asset retirement obligations of $2.6 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general.

5



In addition, the United States Environmental Protection Agency, or the EPA, has designated energy extraction as one of six national enforcement initiatives, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas extraction and production activities. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition, results of operations or 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 or wetlands without a permit issued by the EPA, the Army Corps of Engineers, or the Corps, or the state is prohibited. The Clean Water Act has been interpreted by these agencies to apply broadly. The EPA and the Corps released a rule to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, which went into effect in August 2015. The U.S. Court of Appeals for the Sixth Circuit has stayed the WOTUS rule nationwide pending further action of the court. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule. The WOTUS rule could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements.
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. The EPA has proposed new wastewater pretreatment standards that would prohibit onshore unconventional oil and gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste may result in increased costs

6



Safe Drinking Water Act. The Safe Drinking Water Act, or the SDWA, and the Underground Injection Control Program promulgated under the SDWA, establish the requirements for salt water disposal well activities and prohibit the migration of fluid containing contaminants into underground sources of drinking water. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells in which we act as operator. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional plays like the Eagle Ford and Granite Wash formations. The Fracturing Responsibility and Awareness of Chemicals Act, which has been repeatedly introduced by members of Congress during the past few years, 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 released a draft report in June 2015, which stated that EPA had not found evidence of widespread, systemic impacts on drinking water resources from hydraulic fracturing operations. This report has not yet been finalized, and the EPA’s ultimate conclusions may be impacted by recent comments from the EPA’s Science Advisory Board regarding the sufficiency of the data underlying some of the EPA’s conclusions.
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 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. In July 2015 the EPA’s Office of the Inspector General issued a report instructing the EPA to establish and publish an action plan with milestone dates outlining the steps necessary for determining whether to propose a rule by the end of January 2016. The EPA has indicated that it intends to publish a proposed rule in December 2016. 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.
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, or TRI, reporting requirements under the Emergency Planning and Community Right-to-Know Act, or the EPCRA. The TRI provisions of the EPCRA require covered facilities to report, on an annual basis, releases into the environment of specifically-listed chemicals. As a result, the EPA issued a response letter agreeing to create TRI requirements for natural gas processing plants, but declining to create TRI requirements for the other request areas, which included crude petroleum and natural gas, natural gas liquids, drilling oil and gas wells, oil and gas field exploration services, and oil and gas field services.
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. In November 2014, voters in the City of Denton, Texas, approved a local ordinance banning fracking. In May 2015, this local ordinance was preempted by state legislation.
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. For example, Texas and Pennsylvania have water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source.
Increased regulation of and attention given by environmental interest groups, as well as state and federal regulatory authorities, to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and gas, including from the developing shale plays, or could make it more difficult to 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.

7



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.
In 2012 the EPA issued new rules subjecting certain oil and gas operations 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. These regulations also establish specific requirements regarding emissions from production related wet seal and reciprocating compressors, pneumatic controllers, and storage vessels. In September 2015, the EPA proposed expanding the 2012 NSPS to create additional methane standards for new compressor stations, natural gas processing plants, and well sites. The proposed NSPS would limit natural gas emissions during well completions, impose new leak detection, and ongoing survey, repair, and recordkeeping requirements.
The EPA has also released new draft control guidance for reducing volatile organic compound emissions from existing oil and gas sources in certain ozone non-attainment areas. The EPA acknowledged that some of its recommendations mirror the requirements found in the proposed NSPS for new sources and that, if adopted by states, these recommendations would apply to both new and existing sources of volatile organic compounds in ozone non-attainment areas. If the rules are adopted as proposed and the guidance remains unchanged, they would impose new compliance costs on our operations.
In addition, in November 2015, the EPA also revised the existing National Ambient Air Quality Standards for ground level ozone to make the standard more stringent. Certain areas of the country previously in compliance with the various National Ambient Air Quality Standards, including areas where we operate, may be reclassified as non-attainment areas. The EPA has not yet designated which areas of the country are out of attainment with the new ground level ozone standard, and it will take the states several years to develop compliance plans for their non-attainment areas. If the areas where we operate are reclassified as non-attainment areas, such reclassifications may make it more difficult to construct new or modified sources of air pollution in those areas. A number of states have also filed or joined suits to challenge the EPA’s new standard in court. While we are not able to determine the extent to which this new standard will impact our business at this time, it does have the potential to have a material impact on our operations and cost structure.
Collectively, these rules and proposed rules, as well as any future laws and their implementing regulations, may require a number of modifications to our operations. We may, for example, be required to install new equipment to control emissions from our well sites or compressors at initial startup or by the applicable compliance deadline. We may also be required to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. We are currently researching the effect these new rules will have on our business, but generally expect them to add to the cost and expense of our operations.
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. Based on several recent court decisions striking down agency determinations and guidance, the EPA may only make these decisions based on physical proximity and is precluded from considering functional relationships between the facilities. In September 2015, the EPA proposed a rule with two options for defining a “source.” The EPA’s “preferred” option would codify the current approach whereby only sources that “are contiguous or are located within a short distance of one another”-a quarter mile-would be considered “adjacent” and thus a “single source.” The EPA’s second proposed option would allow sources located more than a quarter mile away if it they are “functionally interrelated” to the source, for example through a physical connection, such as a pipeline between equipment. If the EPA adopts the “functionally interrelated” test, it would introduce uncertainty into the permitting process and could require more lengthy and costly permitting processes and more expensive emission controls.
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

8



prior calendar year on a facility-by-facility basis. On November 9, 2010, the EPA issued final rules applying these regulations to the oil and gas source category, including oil and gas production, natural gas processing, transmission, distribution and storage facilities (Subpart W). In October 2015, the EPA released a final rule adding reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. In January 2016, the EPA proposed additional changes to the reporting requirements under the program. These rules do 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, which found that current and projected concentrations of six key GHGs in the atmosphere threaten public health and the environment, as well as the welfare of current and future generations. Legal challenges to these findings have been asserted, and the U.S. Congress is considering legislation to delay or repeal the EPA’s actions, but we cannot predict the outcome of this litigation or these efforts. The EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. These rules were subject to judicial challenge, but on June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit rejected challenges to the tailoring rule and other EPA rules relating to the regulation of GHGs under the CAA.
Starting July 1, 2011, the EPA required facilities that must already obtain New Source Review permits for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year. On March 27, 2012, the EPA issued its proposed NSPS for carbon dioxide emissions standard from new and modified power plants and held public hearings on the rule in May 2012 and accepted written comments until June 25, 2012. In its June 2013 Climate Action Plan, the Obama Administration announced its intent to issue regulations under Section 111(b) and Section 111(d) of the CAA to set NSPS for both new and existing power plants by June 2015. 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 industry.
In August 2015, the EPA issued its final Clean Power Plan rules establishing carbon pollution standards for power plants. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan, and has also proposed a federal compliance plan to implement the Clean Power Plan in the event that approvable state plans are not submitted. Judicial challenges have been be filed, which seek a stay of the implementation of the rules. Electricity generated by natural gas often results in lower CO2 emission rates than other forms of fossil fuels. Depending on the method of implementation selected by the states, and if implementation is not stayed pending resolution of the legal challenges, the Clean Power Plan could increase the demand for natural gas-generated electricity.
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.
In addition to regulatory programs aimed at reducing CO2 emissions, the EPA has also proposed regulating the emission of methane, which is also considered to be a GHG, from the oil and gas sector through the NSPS program. 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.

9



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 112 employees as of December 31, 2015. 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.
We have a significant amount of indebtedness, and there is substantial doubt about our ability to continue as a going concern.
As of December 31, 2015, we had an aggregate amount of approximately $1.2 billion of debt outstanding. We will be required to pay interest on our senior notes in the amount of $87.6 million in 2016, including $10.9 million in April 2016 and $32.9 million in May 2016. Our ability to make those payments is severely in doubt. In 2015, we incurred a loss from operations of $1.6 billion, including an impairment charge of $1.4 billion. As of March 11, 2016, we had only $32.3 million in cash and cash equivalents. Pursuant to the Eleventh Amendment to the Revolver dated as of March 15, 2016, or the Eleventh Amendment, the commitments under the Revolver were reduced to $171.8 million, which is equal to our currently outstanding loans ($170 million) and issued letters of credit ($1.8 million) under the Revolver. Because we do not have any unused commitment capacity, we will not be able to draw on the Revolver to pay our second quarter interest payments on our senior notes or for any other purpose. Furthermore, we are required, at the time of borrowing and as a condition to borrowing, to make certain representations to our lenders. We may not currently be able to make these representations, nor is it likely that we will be able to do so in the future unless we can restructure our debt obligations. There can be no assurance that we will be able to restructure our debt obligations. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or to otherwise extend the maturity dates, and to cure any potential defaults under the agreements governing such debt, there is no assurance that any particular action or actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our debt agreements will be sufficient.
Moreover, our lenders may in the future exercise their right to redetermine our $275 million borrowing base under the Revolver. Pursuant to the Eleventh Amendment, any such redetermination will not occur until after May 15, 2016. If our borrowing base is redetermined below the amount of our outstanding borrowings, a deficiency will result, and any deficiency must be repaid within 60 days. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”
The consolidated financial statements included in this Annual Report on Form 10‑K have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

10



The audit report we received with respect to our year-end 2015 consolidated financial statements contains an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” The Revolver requires us to deliver audited, consolidated financial statements without a “going concern” or like qualification or exception. As a result, we are in default under the Revolver. Our failure to obtain relief from this requirement under the Revolver could result in an acceleration of all of our outstanding debt obligations.
Under the Revolver, we are required to deliver audited, consolidated financial statements without a “going concern” or like qualification or exception. The audit report prepared by our auditors with respect to the financial statements in this Annual Report on Form 10-K includes an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” Therefore, we are in default under the Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default under the Revolver until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.” If we do not obtain a waiver or other suitable relief from the lenders under the Revolver prior to the expiration of the extension, there will exist an event of default under the Revolver.
If an event of default occurs under the Revolver, the lenders could accelerate the loans outstanding under the Revolver. In addition, if the lenders under the Revolver accelerate the loans outstanding under the Revolver, there will also be cross-defaults under the indentures related to our 7.25% Senior Notes due 2019, or the 2019 Senior Notes, and our 8.5% Senior Notes due 2020, or the 2020 Senior Notes. If these cross-defaults occurred, the holders of the 2019 Senior Notes or the 2020 Senior Notes could accelerate those notes.
If our lenders or our noteholders accelerate the payment of amounts outstanding under the Revolver, the 2019 Senior Notes or the 2020 Senior Notes, respectively, we do not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. We could attempt to obtain additional sources of capital from asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, we cannot provide any assurances that we will be successful in obtaining capital from such transactions on acceptable terms, or at all, and if we fail to obtain sufficient additional capital to repay the outstanding indebtedness and provide sufficient liquidity to meet our operating needs, it may be necessary for us to seek protection from creditors under Chapter 11 of the United States Bankruptcy Code, or Chapter 11.
If we cannot obtain sufficient capital when needed, we will not be able to continue with our historical business strategy.
Our business strategy has historically included maintaining a portfolio of properties that provide long-term, profitable growth through development in areas that support sustainable, lower-risk, repeatable, high-return drilling projects. In the future, we may not be able to obtain financing in sufficient amounts or on acceptable terms when needed, which could adversely affect our operating results and prospects. If we cannot raise the capital required to implement our historical business strategy, we may be required to curtail operations, which could adversely affect our financial condition and results of operations.
Unless we can obtain relief from our lenders, we will also be in breach of certain financial covenants under the Revolver during 2016.
Our ability to borrow under the Revolver is subject to compliance with certain financial covenants, including leverage and current ratios. While we were in compliance with the leverage covenant at December 31, 2015, based on our current operating forecast and capital structure, we do not believe that we will be able to comply with the leverage covenant during the next twelve months. Furthermore, we classified all of our debt as current as of December 31, 2015, which resulted in a breach of the current ratio covenant under the Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default under the Revolver, together with certain other defaults, will not become events of default until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.” If we do not obtain a waiver or other suitable relief from the lenders under the Revolver prior to expiration of the extension, there will exist an event of default under the Revolver. Even if we obtain such a waiver or other relief, we still believe we cannot comply with the leverage covenant during the next twelve months. If we cannot obtain from our lenders a waiver of such potential breach or an amendment of the leverage covenant, our breach would constitute an event of default that could result in an acceleration of substantially all of our outstanding indebtedness. We would not have sufficient capital to satisfy these obligations.

11



We may seek protection from our creditors under Chapter 11 or an involuntary petition for bankruptcy may be filed against us, either of which could have a material adverse impact on our business, financial condition, results of operations, and cash flows and could place our shareholders at significant risk of losing all of their investment in our shares.
We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness in private transactions. However, if our attempts are unsuccessful or we are unable to complete such a restructuring on satisfactory terms, we may choose to pursue a filing under Chapter 11.
Seeking bankruptcy court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. For as long as a Chapter 11 proceeding continued, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing on our business operations. Bankruptcy court protection also could make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our customers and suppliers might lose confidence in our ability to reorganize our business successfully and could seek to establish alternative commercial relationships.
Additionally, all of our indebtedness is senior to the existing common stock in our capital structure. As a result, we believe that seeking bankruptcy court protection under a Chapter 11 proceeding could cause the shares of our existing common stock to be canceled, resulting in a limited recovery, if any, for shareholders of our common stock, and would place shareholders of our common stock at significant risk of losing all of their investment in our shares.
Our substantial indebtedness, liquidity issues and potential to seek restructuring transactions may have a material adverse effect on our business and operations.
Our substantial indebtedness, liquidity issues and efforts to negotiate restructuring transactions may result in uncertainty about our business and cause, among other things:
third parties to lose confidence in our ability to explore and produce oil and natural gas, resulting in a significant decline in our revenues, profitability and cash flow;
difficulty retaining, attracting or replacing key employees;
employees to be distracted from performance of their duties or more easily attracted to other career opportunities;
our suppliers, vendors, hedge counterparties and service providers to renegotiate the terms of our agreements, terminate their relationship with us or require financial assurances from us.
Continued depressed commodity prices have hurt our profitability, financial condition and ability to service our debt as a result of which we have taken several steps to conserve capital which could further adversely affect our business and financial condition.
Our revenues, operating results, cash flows, profitability, growth rate, value of oil and gas properties and ability to service debt depend heavily on prevailing market prices for crude oil, NGLs and natural gas. Average monthly WTI crude oil and natural gas prices have decreased approximately 75 percent and 53 percent from June 2014 to January 2016. These decreases have led us to take steps to conserve capital by, among other things, suspending our drilling operations, completing reductions in force and extending the time for payment of our service providers. While we intend to resume drilling in 2016, there can be no assurance that we will have adequate capital to do so. Likewise, while we intend to pay all amounts due to our service providers, there can be no assurance that we will be able to do so or that our service providers will not decline to work for us or take action against us for non-payment. Furthermore, the lag in operations and reductions in force which we have completed could have an adverse impact on our continuing employees, making it difficult for us to retain their services.
Prices for crude oil, NGLs and natural gas prices are dependent on many factors that are beyond our control.
Prices for crude oil, NGLs and natural gas are dependent on many 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.

12



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 must make substantial capital expenditures to find, acquire, develop and produce oil and gas reserves. Because of significantly low commodity prices, we may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves with our cash flows from operating activities. Because of our financial and liquidity positions, external sources of capital are limited.
Our common stock has been delisted from the NYSE and will not be listed on any other national securities exchange in the near future.
We received notice from the NYSE that trading of our common stock was suspended at the opening of business on January 12, 2016, and the NYSE filed with the SEC to remove our common stock from listing and registration on the NYSE. As a result, our common stock now trades in the OTC Pink market under the ticker symbol “PVAH.” Securities traded in the OTC Pink market generally have significantly less liquidity than securities traded on a national securities exchange, due to factors such as the reduced number of investors that will consider investing in the securities, the reduced number of market makers in the securities, and the reduced number of securities analysts that follow such securities. As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all. Because of the limited market and generally low volume of trading in our common stock that could occur, the share price of our common stock could be more likely to be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the market’s perception of our business, and announcements made by us, our competitors or parties with whom we have business relationships. The lack of liquidity in our common stock may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future.
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;
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.

13



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. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly affect our overall credit risk. Recently, many of our customers’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payments or perform on their obligations to us. In 2015, approximately 64 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 under joint venture arrangements. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one party. We could be held liable for joint venture 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 volatility in commodity prices and currently depressed commodity environment increases the likelihood that some of these working interest owners may not be able to fulfill their joint venture obligations. Some of our project partners have experienced liquidity and cash flow problems. These problems have led and may lead our partners to continue to attempt to delay the pace of 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.
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 and subject to the availability of capital.

14



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, 2015, approximately 25 percent of our estimated proved reserves were proved undeveloped, compared to 60 percent at December 31, 2014. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from proved developed non-producing reserves will not be realized until sometime 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 experienced negative revisions of 45.6 MMBOE in 2015 due to fewer locations, lower EURs and lower prices compared to year-end 2014.
You should not assume that the present value of estimated future net cash flows (standardized measure) referred to herein is the current fair value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the 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, availability of financing for capital expenditures necessary to develop our undeveloped reserves, 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 of certain fields because it becomes uneconomic to produce all reserves within 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 significant enough to result in impairment losses on certain properties that would further decrease 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. We recorded an impairment charge of approximately $1.4 billion during 2015. We could experience additional impairments in the future. While an impairment charge reflects our ability to recover the carrying value of our investments, it does not impact our cash flows from operating activities.

15



We have limited control over the activities on properties we do not operate.
In 2015, other companies operated approximately 15 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.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.
Our initial technical reviews of properties we acquire are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well and environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with acquired properties, and such risks and liabilities could have a material adverse effect on its results of operations and financial condition.
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 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 capital and 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.

16



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 are 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-related 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.
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.

17



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;
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. A significant amount of water is necessary for drilling and completing each well with hydraulic fracturing in Texas. In the past, 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.
Our production may not satisfy the minimum gross volume requirements under our gathering agreements with Republic Midstream, LLC, or Republic, and, as a result, we may be required to make deficiency payments.
We have entered into a gathering agreement with Republic that requires us to provide a minimum delivery commitment of 15,000 gross BOPD of crude oil. The commitment is for a 10 year term beginning once the system has been constructed and is operational, currently expected in the first half of 2016. Although our production and reserves are currently sufficient to fulfill the delivery commitment under the agreement, future oil production may not be sufficient to meet the minimum volume requirements. If we do not purchase volumes in the market or make other arrangements to satisfy the commitments, we would be required to make deficiency payments that total $1.75 per undelivered Bbl.
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, the EPA implemented rules requiring annual reporting of GHG emissions from specified large GHG emission sources in the United States for emissions occurring after January 1, 2010. In October 2015 the EPA released a final rule adding reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.
Moreover, the Obama administration has announced in its Climate Action Plan that it intends to adopt additional regulations to reduce emissions of GHGs in the coming years, likely including further restrictions on emissions of methane from oil and gas operations. More specifically, the EPA issued its final Clean Power Plan rules in August 2015 that establish carbon pollution standards for power plants, and has proposed New Source Performance Standards, or NSPS, to reduce methane emissions from the oil and gas industry. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. See Item 1, “Business – Government Regulation and Environmental Matters.”
In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our financial condition, results of operations and cash flows. For a more complete discussion of environmental laws and regulations intended to address climate change and their impact on our business and operations, please see “Business – Environmental Regulation – Climate Change.”

18



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. The EPA released a draft report in June 2015, which stated that EPA had not found evidence of widespread, systemic impacts on drinking water resources from hydraulic fracturing operations. This report has not yet been finalized, and the EPA’s ultimate conclusions may be impacted by recent comments from the EPA’s Science Advisory Board regarding the sufficiency of the data underlying some of the EPA’s conclusions. In May 2014, the EPA issued an advance notice of proposed rulemaking relating to the collection of information on various chemicals and mixtures used in hydraulic fracturing. The EPA 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, or NESHAP, programs. The EPA has proposed additional NSPS regulations of volatile organic compound and methane emissions from the oil and gas industry, and has released draft guidance that could potentially extend such requirements to existing oil and gas sources in ozone non-attainment areas.
In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. In addition, some states and local governments have enacted legislation or adopted regulations, and the U.S. Congress and other states are considering enacting legislation or adopting regulations, that could impose more stringent permitting, disclosure, monitoring, well construction and water use requirements on hydraulic fracturing operations.
Individually or collectively, such new legislation or regulation could result in increased compliance and operating costs, delays or additional operating restrictions. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. While we do not believe that compliance with such requirements will have a material adverse effect on our operations, these requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations, any of which could be significant.
If the use of hydraulic fracturing is limited, prohibited or subjected to further regulation, these requirements could delay or effectively prevent the extraction of oil and gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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.

19



In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
our production is less than expected;
there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
the counterparties to our futures contracts fail to perform under the contracts; or
a sudden, unexpected event materially impacts crude oil, NGL or natural gas prices.
In addition, derivative instruments involve basis risk. Basis risk in a derivative contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of production may have more or less variability than the regional price index used for the sale of that production.
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, 2015, 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.
Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.
Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U. S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income and state income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that increases the taxes states impose on oil and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years beginning October 1, 2016. The adoption of this, or similar proposals, would result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil.
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 adversely affected.

20



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 2015 fiscal year and remain unresolved.
Item 2
 Properties
As of December 31, 2015, our primary oil and gas assets are located in Gonzales and Lavaca Counties in South Texas and Washita and Custer Counties in Western Oklahoma.
Facilities
All of our office facilities are leased and 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. As is customary in the oil and gas industry, however, we make a cursory review of title when we acquire farmout acreage or 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.

21



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
 
PV10
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
(MMBOE)
 
$ in millions
 
$ in millions
2015
 

 
 
 
 

 
 

 
 

 
 

Developed
 
 
 
 
 
 

 
 
 
 
Producing
19.6

 
6.1

 
36.8

 
31.8

 
$
325.6

 
$
325.6

Non-producing
0.6

 
0.1

 
0.4

 
0.8

 
4.3

 
4.3

 
20.2

 
6.2

 
37.2

 
32.6

 
329.9

 
329.9

Undeveloped
9.3

 
1.0

 
5.0

 
11.1

 
(6.6
)
 
(6.6
)
 
29.5

 
7.2

 
42.2

 
43.7

 
$
323.3

 
$
323.3

 
 
 
 
 
 
 
 
 
 
 
 
Price measurement used 1
$45.78/Bbl

 
$13.15/Bbl

 
$2.70/MMBtu

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2014

 

 

 

 

 
 
Developed
 
 
 
 
 
 
 
 
 
 
 
Producing
21.8

 
7.4

 
77.9

 
42.1

 
$
794.9

 
$
989.9

Non-producing
0.3

 
0.7

 
16.6

 
3.8

 
8.6

 
10.7

 
22.1

 
8.1

 
94.5

 
45.9

 
803.5

 
1,000.6

Undeveloped
47.0

 
11.1

 
64.7

 
68.9

 
378.9

 
471.9

 
69.0

 
19.2

 
159.2

 
114.8

 
$
1,182.4

 
$
1,472.5

 
 
 
 
 
 
 
 
 
 
 
 
Price measurement used 1
$92.91/Bbl

 
$25.49/Bbl

 
$4.32/MMBtu

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
 
 
 
 
Producing
19.0

 
7.5

 
146.5

 
50.9

 
$
701.7

 
$
953.1

Non-producing
0.3

 
1.0

 
16.7

 
4.1

 
7.3

 
9.9

 
19.3

 
8.5

 
163.2

 
55.0

 
709.0

 
963.0

Undeveloped
41.4

 
13.4

 
158.9

 
81.3

 
554.8

 
753.6

 
60.7

 
21.9

 
322.1

 
136.3

 
$
1,263.8

 
$
1,716.6

 
 
 
 
 
 
 
 
 
 
 
 
Price measurement used 1
$103.11/Bbl

 
$31.10/Bbl

 
$3.47/MMBtu

 
 
 
 
 
 
___________________
1 Crude oil and natural gas prices were based on average (beginning of month basis) sales prices per Bbl and MMBtu. The representative prices of crude oil and natural gas were adjusted for basis differentials 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, 2015:
 
 
Proved
 
% of Total
Proved
 
% Proved
Region
 
Reserves
 
Reserves
 
Developed
 
 
(MMBOE)
 
 

 
 

South Texas
 
40.1

 
92
%
 
72
%
Mid-Continent and other 1
 
3.6

 
8
%
 
100
%
 
 
43.7

 
100
%
 
75
%
___________________
1 Includes approximately 0.1 MMBOE attributable to our three active Marcellus Shale wells.

22



Proved Undeveloped Reserves
The proved undeveloped reserves included in our reserve estimates relate to wells that are forecasted to be drilled within the next three years, assuming availability of capital. The following tables set forth the changes in our proved undeveloped reserves during the year ended December 31, 2015 and the total proved undeveloped reserves as of December 31, 2015 by region:
 
Crude Oil
 
NGLs
 
Natural Gas
 
Oil Equivalents
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
(MMBOE)
Proved undeveloped reserves at beginning of year
47.0

 
11.1

 
64.7

 
68.9

Revisions of previous estimates
(30.8
)
 
(7.9
)
 
(41.4
)
 
(45.6
)
Extensions, discoveries and other additions
1.2

 
0.1

 
0.6

 
1.4

Sale of reserves in place
(1.5
)
 
(0.4
)
 
(9.5
)
 
(3.5
)
Conversion to proved developed reserves
(6.6
)
 
(1.9
)
 
(9.4
)
 
(10.1
)
Proved undeveloped reserves at end of year
9.3

 
1.0

 
5.0

 
11.1

 
 
 
 
 
 
 
 
South Texas
9.3

 
1.0

 
5.0

 
11.1

Mid-Continent and other

 

 

 

 
9.3

 
1.0

 
5.0

 
11.1

In 2015, our proved undeveloped reserves decreased by 57.8 MMBOE. We experienced negative revisions of 45.6 MMBOE due to fewer locations, lower EURs and lower prices compared to year-end 2014. Extensions, discoveries and other additions of 1.4 MMBOE were attributable to our development activities in Eagle Ford. We sold our Haynesville Shale and Cotton Valley assets in East Texas as well as certain non-core Eagle Ford properties resulting in decreases of 2.0 MMBOE and 1.5 MMBOE. In addition, we converted 10.1 MMBOE from proved undeveloped to proved developed reserves in Eagle Ford. During 2015, we incurred capital expenditures of approximately $222.6 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 DeGolyer and MacNaughton, Inc., our independent third party petroleum engineers. For additional information regarding estimates of proved reserves and other information about our oil and gas reserves, see the Supplemental Information on Oil and Gas Producing Activities (Unaudited) in our Notes to the Consolidated Financial Statements and the report of DeGolyer and MacNaughton, Inc., dated February 3, 2016, which is included as an Exhibit to this Annual Report on Form 10-K. We did not file any reports during the year ended December 31, 2015 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 DeGolyer and MacNaughton, Inc. Our Vice President, Operations & Engineering has over 30 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 DeGolyer and MacNaughton, 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. DeGolyer and MacNaughton, 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.

23



Oil and Gas Production, Production Prices and Production Costs
In the tables that follow, we have presented our former operations in the Haynesville Shale and Cotton Valley in East Texas and Selma Chalk in Mississippi, which were sold in 2015 and 2014 as “Divested properties.” The sales of those operations represented complete divestitures and we have retained no interests therein. Our remaining operations are represented in the Eagle Ford in South Texas, the Granite Wash in Oklahoma and relatively minor operations in the Marcellus Shale in Pennsylvania.
Oil and Gas Production by Region
The following tables set forth by region our total production and average daily production for the periods presented:
 
 
 
 
Total Production
for the Year Ended December 31,
Region
 
 
 
 
 
 
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
 
 

 
(MBOE) 
 
 

South Texas 1
 
 
 
 
 
 
 
6,995

 
5,913

 
4,091

Mid-Continent and other 2
 
 
 
 
 
 
 
479

 
765

 
962

Divested properties 3
 
 
 
 
 
 
 
449

 
1,256

 
1,771

 
 

 

 

 
7,923

 
7,934

 
6,824

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average Daily Production
for the Year Ended December 31,
Region
 
 
 
 
 
 
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
 
 
 
(BOEPD) 
 
 
South Texas 1
 
 
 
 
 
 
 
19,165

 
16,201

 
11,208

Mid-Continent and other 2
 
 
 
 
 
 
 
1,311

 
2,096

 
2,636

Divested properties 3
 
 
 
 
 
 
 
1,847

 
3,441

 
4,852

 
 
 
 
 
 
 
 
22,323

 
21,738

 
18,696

_____________________________________________
1 Includes total production and average daily production of approximately 92 MBOE (303 BOEPD), 96 MBOE (264 BOEPD) and 33 MBOE (90 BOEPD) for 2015, 2014 and 2013, respectively, attributable to certain non-core Eagle Ford properties that we sold in October 2015.
2 Includes total production and average daily production of approximately 19 MBOE (61 BOEPD), 22 MBOE (61 BOEPD) and 29 MBOE (81 BOEPD) for 2015, 2014 and 2013, respectively, attributable to certain Mid-Continent properties that we sold in October 2015. Also includes total production and average daily production of approximately 22 MBOE (60 BOEPD), 24 MBOE (66 BOEPD) and 25 MBOE (67 BOEPD) for 2015, 2014 and 2013, respectively, attributable to our three active Marcellus Shale wells.
3 We sold all of our properties in the Haynesville Shale and Cotton Valley in East Texas in August 2015, which represented total production and average daily production of approximately 449 MBOE (1,847 BOEPD), 844 MBOE (2,311 BOEPD) and 1,020 MBOE (2,794 BOEPD) in 2015, 2014 and 2013, respectively. 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) and 751 MBOE (2,058 BOEPD) in 2014 and 2013.
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,
 
2015
 
2014
 
2013
Average prices:
 
 
 
 
 
Crude oil ($ per Bbl)
$
44.81

 
$
91.50

 
$
101.13

NGLs ($ per Bbl)
$
12.24

 
$
31.14

 
$
31.30

Natural gas ($ per Mcf)
$
2.62

 
$
4.44

 
$
3.64

Aggregate ($ per BOE)
$
33.19

 
$
64.64

 
$
63.11

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

 
$
6.09

 
$
5.20

Gathering processing and transportation
3.01

 
2.31

 
1.88

 
$
8.37

 
$
8.40

 
$
7.08


24



Significant Fields
Our properties in the Eagle Ford in South Texas, which contain primarily oil reserves, represented approximately 92 percent of our total equivalent proved reserve quantities as of December 31, 2015.
The following table sets forth certain information with respect to this field for the periods presented:
 
Year Ended December 31,
 
2015
 
2014
 
2013
Production:
 

 
 

 
 

Crude oil (MBbl)
4,817

 
4,450

 
3,197

NGLs (MBbl)
1,170

 
773

 
478

Natural gas (MMcf)
6,026

 
4,070

 
2,406

Total (MBOE)
6,991

 
5,901

 
4,077

Percent of total company production
88
%
 
74
%
 
60
%
Average prices:
 
 
 
 
 
Crude oil ($ per Bbl)
$
44.79

 
$
90.57

 
$
101.55

NGLs ($ per Bbl)
$
11.04

 
$
25.23

 
$
26.68

Natural gas ($ per Mcf)
$
2.64

 
$
4.20

 
$
3.52

Aggregate ($ per BOE)
$
34.98

 
$
74.49

 
$
84.85

Average production and lifting cost ($ per BOE)1:
 
 
 
 
 
Lease operating
$
5.04

 
$
5.36

 
$
4.30

Gathering processing and transportation
2.66

 
1.76

 
1.08

 
$
7.70

 
$
7.12

 
$
5.38

______________
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 wells that we drilled during the years ended December 31, 2015, 2014 and 2013, respectively, and wells that were in progress at the end of each year. There were no exploratory wells drilled in any of the years presented. The number of wells drilled refers to the number of wells completed at any time during the year, regardless of when drilling was initiated. 
 
2015
 
2014
 
2013
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development
 

 
 

 
 

 
 

 
 

 
 

Productive
61

 
38.6

 
83

 
50.8

 
58

 
34.1

Dry well

 

 
1

 
0.8

 

 

Under evaluation

 

 

 

 
1

 
0.5

 
 
 
 
 
 
 
 
 
 
 
 
Total
61

 
38.6

 
84

 
51.6

 
59

 
34.6

 
 
 
 
 
 
 
 
 
 
 
 
Wells in progress at end of year1
4

 
2.3

 
28

 
14.3

 
16

 
11.5

___________
1 Includes two gross (1.7 net) wells completing, one gross (0.3 net) well waiting on completion and one gross (0.3 net) well being drilled as of December 31, 2015.
The following table sets forth the regions in which we drilled our wells for the periods presented:
 
 
2015
 
2014
 
2013
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
South Texas
 
61

 
38.6

 
84

 
51.6

 
57

 
34.1

Mid-Continent and other
 

 

 

 

 
2

 
0.5

 
 
61

 
38.6

 
84

 
51.6

 
59

 
34.6


25



Present Activities
As of December 31, 2015, we had four gross (2.3 net) wells in progress, all of which were located in the Eagle Ford in South Texas. As of March 4, 2016, all four 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. We have commitments to provide minimum deliveries of crude oil of 15,000 BOPD in our South Texas region for a period of ten years under a gathering agreement with Republic Midstream, LLC, or Republic. This commitment is for a 10 year term beginning once the system has been constructed and is operational, currently expected in the first half of 2016. Although, our production and reserves are currently sufficient to fulfill the delivery commitment under the agreement, future oil production may not be sufficient to meet the minimum volume requirements. If we do not purchase volumes in the market or make other arrangements to satisfy the commitments, we would be required to make deficiency payments that total $1.75 per undelivered Bbl.
We also have a contractual obligation for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the sale of our natural gas assets in West Virginia, Kentucky and Virginia in 2012, we no longer have production to satisfy this commitment. While we sell our unused firm transportation to the extent possible, we recognized an obligation in 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract. The undiscounted amount payable on an annual basis for the each of the next five years is $2.7 million and a combined amount of $4.6 million is expected to be payable for 2021 through expiration in 2022.
Productive Wells
The following table sets forth by region the productive wells in which we had a working interest as of December 31, 2015:
 
 
Primarily Oil
 
Primarily Natural Gas
 
Total
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
South Texas 1
 
332

 
209.7

 

 

 
332

 
209.7

Mid-Continent and other
 
2

 
1.5

 
98

 
43.5

 
100

 
45.0

 
 
334

 
211.2

 
98

 
43.5

 
432

 
254.7

_____________________________________________
1 Includes wells in the Austin Chalk.
Of the total wells presented in the table above, we are the operator of 333 gross (299 oil and 34 gas) and 220 net (198.3 oil and 21.7 gas) wells. In addition to the above working interest wells, we own royalty interests in 9 gross wells.
Acreage
The following table sets forth by region our developed and undeveloped acreage as of December 31, 2015 (in thousands):
 
 
Developed 
 
Undeveloped 
 
Total 
Region
 
Gross 
 
Net 
 
Gross 
 
Net 
 
Gross 
 
Net 
South Texas
 
75.6

 
48.3

 
61.4

 
51.7

 
137.0

 
100.0

Mid-Continent and other
 
16.9

 
8.4

 
12.0

 
11.9

 
28.9

 
20.3

 
 
92.5

 
56.7

 
73.4

 
63.6

 
165.9

 
120.3

The primary terms of our leases generally range from three to five years and we do not have any concessions. As of December 31, 2015, 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:
 
2016
 
2017
 
2018
 
Thereafter
Percent of gross undeveloped acreage
43
%
 
35
%
 
8
%
 
14
%
Percent of net undeveloped acreage
45
%
 
31
%
 
6
%
 
18
%
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.
 

26



Item 3
Legal Proceedings
See Note 14 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
On January 13, 2016, our common stock began trading on the OTC Pink under the symbol “PVAH.” Prior to being suspended from trading on January 12, 2016, our common stock was traded on the NYSE under the symbol “PVA.”
The high and low sales prices (composite transactions) related to each fiscal quarter in 2015 and 2014, as reported by the NYSE, were as follows:
 
 
 
 
 
 
 
 
 
 
 
Sales Price
Quarter Ended
 
 
 
High
 
Low
December 31, 2015
 
 
 
$
1.23

 
$
0.26

September 30, 2015
 
 
 
$
4.39

 
$
0.53

June 30, 2015
 
 
 
$
8.03

 
$
3.87

March 31, 2015
 
 
 
$
7.91

 
$
4.55

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

Equity Holders
As of February 26, 2016, there were 366 record holders and 16,483 beneficial owners (held in street name) of our common stock.
Dividends
We have not in the last three fiscal years, nor do we intend in the foreseeable future, to pay any cash dividends on our common stock. Additionally, pursuant to the Eleventh Amendment, we are no longer permitted to make payments of dividends on our common stock.
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 16 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.

27



Issuer Purchases of Equity Securities
We did not repurchase any shares of our common stock in the fourth quarter of 2015.
A portion of the compensation for certain non-employee members of our board of directors has been paid in deferred common stock units in recent years through the third quarter of 2015. Each deferred common stock unit represents one share of common stock, vests immediately upon issuance, and is available to the holder upon retirement from our board of directors. Deferred common stock units that have not been converted into common stock are presented for financial reporting purposes as treasury stock carried at cost.
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, 2015, there were nine exploration and production companies in the Standard & Poor’s 600 Oil & Gas Exploration & Production Index: Bill Barret Corporation, Bonanza Creek Energy Inc, Carrizo Oil & Gas, Inc., Contango Oil & Gas Company, Northern Oil & Gas, Inc., PDC Energy, Inc., Rex Energy Corporation, Stone Energy Corporation and Synergy Resources Corporation. The graph assumes $100 is invested on January 1, 2011 in us and each index at December 31, 2010 closing prices.
 
December 31,
 
2011
 
2012
 
2013
 
2014
 
2015
Penn Virginia Corporation
$
32.23

 
$
27.45

 
$
58.70

 
$
41.58

 
$
1.87

S&P Small Cap 600 Index
$
101.02

 
$
117.51

 
$
166.05

 
$
175.61

 
$
172.15

S&P 600 Oil & Gas Exploration & Production Index
$
94.15

 
$
85.10

 
$
119.34

 
$
73.06

 
$
41.52

 

28



Item 6
Selected Financial Data
The following selected historical financial and operating information was derived from our Consolidated Financial Statements as of and for each of the five years ended December 31, 2015. The selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our Consolidated Financial Statements and the accompanying Notes and Supplementary Data in Item 8, “Financial Statements and Supplementary Data.”
 
2015
 
2014
 
2013
 
2012
 
2011
 
(in thousands, except per share amounts)
Statements of Operations Data:
 

 
 

 
 

 
 

 
 

Revenues
$
305,298

 
$
636,773

 
$
431,468

 
$
317,149

 
$
306,005

Operating loss 1
$
(1,565,041
)
 
$
(615,985
)
 
$
(92,046
)
 
$
(147,091
)
 
$
(155,419
)
Net income (loss)
$
(1,582,961
)
 
$
(409,592
)
 
$
(143,070
)
 
$
(104,589
)
 
$
(132,915
)
Preferred stock dividends 2
$
22,789

 
$
17,148

 
$
6,900

 
$
1,687

 
$

Loss attributable to common shareholders
$
(1,605,750
)
 
$
(430,996
)
 
$
(149,970
)
 
$
(106,276
)
 
$
(132,915
)
Common Stock Data:
 

 
 

 
 

 
 

 
 

Loss per common share, basic
$
(21.81
)
 
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
 
$
(2.90
)
Loss per common share, diluted
$
(21.81
)
 
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
 
$
(2.90
)
Weighted-average shares outstanding:
 

 
 

 
 

 
 

 
 

Basic
73,639

 
68,887

 
62,335

 
47,919

 
45,784

Diluted
73,639

 
68,887

 
62,335

 
47,919

 
45,784

Actual shares outstanding at year-end
81,253

 
71,569

 
65,307

 
55,117

 
45,714

Dividends declared per share of common stock
$

 
$

 
$

 
$
0.113

 
$
0.225

Market value at year-end
$
0.30

 
$
6.68

 
$
9.43

 
$
4.41

 
$
5.29

Number of shareholders
16,849

 
18,306

 
11,335

 
7,656

 
6,787

Preferred Stock Data 3:
 
 
 
 
 
 
 
 
 
Actual shares outstanding at year-end:
 
 
 
 
 
 
 
 
 
Series A
3,915

 
7,945

 
11,500

 
11,500

 

Series B
27,551

 
32,500

 

 

 

Dividends declared per share of preferred stock 4:
 
 
 
 
 
 
 
 
 
Series A
$
300.00

 
$
600.00

 
$
600.00

 
$
146.67

 
$

Series B
$
300.00

 
$
348.33

 
$

 
$

 
$

Balance Sheet and Other Financial Data:
 

 
 

 
 

 
 

 
 

Property and equipment, net
$
344,395

 
$
1,825,098

 
$
2,237,304

 
$
1,723,359

 
$
1,777,575

Total assets 5
$
517,725

 
$
2,201,810

 
$
2,472,830

 
$
1,831,733

 
$
1,929,819

Total debt 5
$
1,224,383

 
$
1,085,429

 
$
1,252,808

 
$
583,503

 
$
684,073

Shareholders’ equity (deficit)
$
(915,121
)
 
$
675,817

 
$
788,804

 
$
895,116

 
$
846,309

Cash provided by operating activities
$
169,303

 
$
282,724

 
$
261,512

 
$
241,458

 
$
144,741

Cash paid for capital expenditures
$
364,844

 
$
774,139

 
$
504,203

 
$
370,907

 
$
445,623

Other Statistical Data:
 

 
 

 
 

 
 

 
 

Total production (MBOE)
7,923

 
7,934

 
6,824

 
6,513

 
7,759

Proved reserves (MMBOE)
44

 
115

 
136

 
113

 
147

_____________________________________________
1 Operating loss for 2015, 2014, 2013, 2012 and 2011 included impairment charges of $1.4 billion, $791.8 million, $132.2 million, $104.5 million and $104.7 million, respectively.
2 
Includes accumulated preferred stock dividends of $10.7 million for 2015 as described in footnote 4 below. Excludes inducements paid for the conversion of preferred stock of $4.3 million in 2014.
3 Outstanding preferred stock is in the form of depositary shares representing a 1/100th ownership interest in a share of either our 6% Series A Convertible Perpetual Preferred Stock, or Series A Preferred Stock, or our 6% Series B Convertible Perpetual Preferred Stock, or Series B Preferred Stock, as applicable. Each share of the Series A Preferred Stock and B Preferred Stock has a liquidation preference of $10,000 per share or $100 per depositary share.
4 
In September 2015, we suspended our quarterly dividends on the Series A Preferred Stock and the Series B Preferred Stock. The suspension resulted in the accumulation of dividends for the quarterly periods ended September 30, 2015 and December 31, 2015 of $1.7 million for the Series A Preferred Stock and $9.0 million for the Series B Preferred Stock.
5 
Total assets and total debt have been adjusted downward from the prior year presentation by $24.6 million, $28.2 million, $11.3 million and $13.2 million as of December 31, 2014, 2013, 2012 and 2011, respectively, due the adoption in 2015 of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs, or ASU 2015–03 on a retrospective basis. ASU 2015–03 requires that debt issuance costs, which were previously presented as assets, be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. In addition, total assets were further reduced by $0.1 million and $6.1 million as of December 31. 2014 and 2013 due to the adoption in 2015 of ASU 2015–17, Balance Sheet Classification of Deferred Taxes, which requires the combination of all deferred income tax assets and liabilities to be presented as a single noncurrent amount.

29



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. 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. Our current operations consist primarily of operating our producing wells in the Eagle Ford in South Texas. We also have less significant operations in Oklahoma, primarily in the Granite Wash.
The majority of our Eagle Ford wells were drilled by us between 2011 and 2015. As commodity prices began their precipitous decline in the second half of 2014, we reduced our capital program while exploiting our most productive drilling locations, attempting to maintain a consistent level of period-to-period growth to offset natural production declines and securing our most strategic acreage through the drillbit.
We began 2015 with eight drilling rigs operating in the Eagle Ford. All of these rigs were initially contracted in 2014 or earlier at times when (i) the spot price for crude oil was substantially higher and (ii) we were executing our business plans to aggressively develop our acquired acreage in this region. By the end of 2015, we had reduced our capital program to one operated drilling rig.
Throughout 2015, we explored strategic alternatives to enhance liquidity, including first and second lien financing transactions. In December 2015, a potential first lien financing agreement was terminated. We incurred $6.2 million in professional fees and consulting costs associated with this proposed transaction and other financing efforts during 2015.
The continued deterioration of commodity prices as reflected in the future strip pricing as of December 31, 2015 triggered an impairment of approximately $1.4 billion to our Eagle Ford properties, reducing their carrying value to their estimated fair value.

30



The following table sets forth certain historical summary operating and financial statistics for the periods presented: 
 
Year Ended December 31,
 
2015
 
2014
 
2013
Total production (MBOE)
7,923

 
7,934

 
6,824

Average daily production (BOEPD)
22,323

 
21,738

 
18,696

Crude oil and NGL production (MBbl)
6,304

 
5,754

 
4,417

Crude oil and NGL production as a percent of total
80
%
 
73
%
 
65
%
Product revenues, as reported
$
262,980

 
$
512,882

 
$
430,693

Product revenues, adjusted for derivatives
$
401,149

 
$
505,458

 
$
429,651

Crude oil and NGL revenues as a percent of total, as reported
90
%
 
89
%
 
88
%
Realized prices:
 
 
 
 
 
Crude oil ($/Bbl)
$
44.81

 
$
90.50

 
$
101.13

NGL ($/Bbl)
$
12.24

 
$
31.14

 
$
31.30

Natural gas ($/Mcf)
$
2.62

 
$
4.44

 
$
3.64

Aggregate ($/BOE)
$
33.19

 
$
64.64

 
$
63.11

Production and lifting costs ($/BOE):
 
 
 
 
 
Lease operating
$
5.36

 
$
6.09

 
$
5.20

Gathering, processing and transportation
$
3.01

 
$
2.31

 
$
1.88

Production and ad valorem taxes ($/BOE)
$
2.06

 
$
3.53

 
$
3.28

General and administrative ($/BOE) 1
$
4.99

 
$
5.15

 
$
6.46

Total operating costs ($/BOE)
$
15.42

 
$
17.08

 
$
16.82

Depreciation, depletion and amortization ($/BOE)
$
42.22

 
$
37.85

 
$
35.99

Cash provided by operating activities
$
169,303

 
$
282,724

 
$
261,512

Cash paid for capital expenditures
$
364,844

 
$
774,139

 
$
504,203

Cash and cash equivalents at end of period
$
11,955

 
$
6,252

 
$
23,474

Debt outstanding, net of discount, at end of period
$
1,245,000

 
$
1,110,000

 
$
1,281,000

Credit available under revolving credit facility at end of period 2
$

 
$
413,196

 
$
191,346

Proved reserves (MMBOE)
44

 
115

 
136

Net development wells drilled and completed
38.6

 
51.6

 
34.6

_____________________________________________
1 Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.57, $0.46 and $0.84 and liability-classified share-based compensation of $(0.09), $0.57 and $0.60 for the years ended December 31, 2015, 2014 and 2013, respectively.
2 
As of December 31, 2015, we were and continue to be unable to draw on the Revolver (see “Key Developments” and “Financial Condition” sections that follow).


31



Key Developments
The following general business developments and corporate actions in 2015 and 2016 had or may have a significant impact on our results of operations, financial position and cash flows:
Depressed Commodity Prices and Our Hedging Program
Commodity prices have exhibited significant volatility and continued a decline that began in mid-2014 and has lasted throughout 2015 and into 2016. Crude oil prices declined from a high of over $105 per barrel in June 2014 to less than $27 per barrel in February 2016. Natural gas prices faced similar downward pressure in 2015, dropping below $1.70 per MMBtu in December 2015. The deterioration of commodity prices triggered an impairment of approximately $1.4 billion to our Eagle Ford properties. Our crude oil derivatives provided cash settlements of $137.5 million during the year ended December 31, 2015. For 2016, we have hedged a total of approximately 6,000 BOPD at a weighted-average swap price of $80.41 per barrel. We expect to remain unhedged with respect to natural gas production for the foreseeable future.
Ongoing Efforts to Refinance the Company and Improve Liquidity
As of December 31, 2015, the total outstanding principal amount of our debt obligations was $1.2 billion. We are continuing to actively explore and evaluate various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations. In January 2016, we retained K&E and Jefferies to provide strategic advice generally and to act as our advisors in that regard. The timing and outcome of these efforts is highly uncertain. One or more of these alternatives could potentially be consummated without the consent of any one or more of our current security holders and, if consummated, could be dilutive to the holders of our outstanding equity securities and adversely affect the trading prices and values of our current debt and equity securities or if we were to seek protection under the bankruptcy laws, could cause the shares of our common stock to be canceled, with limited recovery, if any. Furthermore, there can be no assurance that any of these alternatives will be successful on acceptable terms or at all.     
While we were in compliance with the leverage covenant under the Revolver at December 31, 2015, based on our current operating forecast and capital structure, we do not believe that we will be able to comply with the leverage covenant during the next twelve months. Furthermore, we reclassified all of our debt as current as of December 31, 2015, which represents a breach of the current ratio covenant under the Revolver. Pursuant to the Eleventh Amendment to the Revolver, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default under the Revolver until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). If we do not obtain a waiver or other suitable relief from the lenders under the Revolver before the extension expires, there will exist an event of default under the Revolver. Even if we obtain such a waiver or other relief, we still believe we cannot comply with the leverage covenant during the next twelve months. If we cannot obtain from our lenders a waiver of such potential breach or an amendment of the leverage covenant, our breach would constitute an event of default that could result in an acceleration of substantially all of our outstanding indebtedness. We would not have sufficient capital to satisfy these obligations. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”
Additionally, as further described under “Financial Condition – Ability to Continue as a Going Concern” below, our registered independent public accountants have issued an opinion with a going concern explanatory paragraph on our consolidated financial statements. As a result, we are in default under our Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default under the Revolver until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). If we are unable to obtain a waiver or other suitable relief with respect to these defaults, an event of default may occur and could result in an acceleration of our Revolver and potential cross-default and acceleration of substantially all of our other indebtedness. We would not have sufficient capital to satisfy these obligations
Reduced Capital Budget and Suspension of Drilling Program
In response to the recent declines in commodity prices, and given the uncertainty regarding the timing and magnitude of any price recovery, we suspended our drilling activities in February 2016. While we intend to resume drilling in 2016, there can be no assurance that we will have adequate capital to do so.
Revolver Amendments and Commitment and Borrowing Base Reduction
On March 15, 2016, we entered into the Eleventh Amendment to the Revolver. The Eleventh Amendment provides (i) for an extension before certain events of default under the Revolver will occur, (ii) for a reduction in commitments to $171.8 million and (iii) that the borrowing base under the Revolver is not subject to scheduled redetermination until May 15, 2016. Specifically, the extension period with respect to events of default is through 12:01 am on April 12, 2016, which can be further extended through 12:01 am on May 10, 2016 if certain conditions have been satisfied. The extension period can be terminated early upon certain triggering events.

32



The key conditions to the first extension (April 12, 2016) and entry to the Eleventh Amendment are: (i) termination of certain hedge agreements and application of the proceeds against the loans (which will result in a further reduction of our lenders’ commitments), (ii) entry into control agreements over deposit accounts, subject to customary exceptions, (iii) payment of advisor fees, and (iv) agreement to certain changes to the Revolver, including increasing the interest rate by 1.00%, tightening certain restrictive covenants and agreeing that monthly hedge settlements will be applied against the loans (which will result in a further reduction in our lenders’ commitments).
The key conditions to the second extension (May 10, 2016) are: (i) termination of certain additional hedges and application of most of the proceeds against the loans (which will result in a further reduction in our lenders’ commitments)and (ii) no notification by the representative of the ad hoc committee of unsecured noteholders that they do not support such extension. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”
In January 2016, the Revolver was amended to (i) allow us to convert to or continue LIBOR loans without having to make a solvency representation and (ii) increase our mortgage requirement from 80 percent to 100 percent (subject to certain exceptions) of our proved reserves. In November 2015, in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver to $275 million due primarily to depressed commodity prices and our reduced capital program.
Suspension of Preferred Stock Dividends
In September 2015, we announced a suspension of quarterly dividends on our outstanding Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015. The suspension was extended through the quarter ended December 31, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarters ended September 30, 2015 and December 31, 2015 and any future unpaid dividends, will accumulate. For the year ended December 31, 2015, we accumulated a total of $10.7 million in unpaid preferred stock dividends. The suspension of quarterly dividends does not affect our business operations and does not cause an event of default under any of our debt agreements. Pursuant to the Eleventh Amendment, we are precluded from making dividend payments on our Series A and Series B Preferred Stock.
Sale of Assets
In October 2015, we sold certain non-core Eagle Ford properties for $12.5 million, net of transaction costs and customary closing adjustments. We recognized a loss of $9.5 million on this transaction in the fourth quarter of 2015.
In August 2015, we sold our East Texas assets and received cash proceeds of approximately $73 million, net of transaction costs and customary closing adjustments. The effective date of the sale was May 1, 2015 and we recognized a gain of approximately $43 million. The properties sold had net production of 1,898 BOEPD during the second quarter of 2015, consisting of 74 percent natural gas, 19 percent NGLs and seven percent crude oil.
The net proceeds from these transactions were used to pay down a portion of our outstanding borrowings under the Revolver.
Production and Development in the Eagle Ford
Our Eagle Ford production was 16,544 BOEPD during the three months ended December 31, 2015 with oil comprising 11,764 BOPD, or 71 percent, and NGLs and natural gas comprising approximately 16 percent and 13 percent. Our fourth quarter production represented an 11 percent decrease compared to 18,528 BOEPD during the three months ended September 30, 2015, of which 12,826 BOPD, or 69 percent, was crude oil, 17 percent was NGLs and 14 percent was natural gas. The sequential decline in production was attributable to our reduction in drilling activity.
During the three months ended December 31, 2015, we drilled and completed six gross (4.5 net) wells in the Eagle Ford for a total of 61 gross (38.6 net) wells for the full year. The last 11 wells that we drilled and completed were two-string lower Eagle Ford wells with slickwater stimulation. The average drilling and completion costs for these wells totaled approximately $5.2 million per well.
During the three months ended December 31, 2015, the wells that we drilled and completed had an average IP rate of over 1,600 BOEPD over an average of 19.5 frac stages, with 71 percent of production from crude oil, compared to an average of approximately 1,500 BOEPD over an average of 21.2 frac stages in the three months ended September 30, 2015. The average amount of proppant per stage for these was approximately 450,000 pounds and the average amount of proppant per lateral foot was approximately 2,020 pounds, compared to approximately 422,000 pounds per stage and 1,800 pounds per lateral foot in the three months ended September 30, 2015. Of the five gross wells that we have completed in 2016, three had IP rates in excess of 3,500 BOEPD with approximately 93 percent production from crude oil over an average of 27.7 frac stages. These particular wells are among the most productive wells we have drilled in the Eagle Ford thus far. We believe the strong improvement in early-time production rates is attributable to the use of slickwater stimulations, continued use of “zipper fracs” for alternating laterals on multi-well pads and increased frac intensity as measured by the increased proppant pumped per stage.

33



Financial Condition
Ability to Continue as a Going Concern    
The precipitous decline in oil and natural gas prices during 2015 and into 2016 has had a significant adverse impact on our business, and as a result of our financial condition, our registered independent public accountants have issued an opinion with an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” The Revolver requires us to deliver audited, consolidated financial statements without a “going concern” or like qualification or exception. Furthermore, we have classified all of our total outstanding debt as short-term as of December 31, 2015, which represents a breach of the current ratio covenant under the Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default until April 12, 2016 (which can be further extended until May 10, 2016 if certain other conditions have been satisfied). For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.” If we do not obtain a waiver or other suitable relief from the lenders under the Revolver before the extension expires, there will exist an event of default under the Revolver. Even if we obtain such a waiver or other relief, we still believe we cannot comply with the leverage covenant during the next twelve months. If we cannot obtain from our lenders a waiver of such potential breach or an amendment of the leverage covenant, our breach would constitute an event of default that could result in an acceleration of substantially all of our outstanding indebtedness. We would not have sufficient capital to satisfy these obligations.
Liquidity
Our primary sources of liquidity have historically included cash from operating activities, borrowings under the Revolver, proceeds from the sales of assets and, from time to time, proceeds from capital market transactions, including the offering of debt and equity securities. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. As a result of continued low oil and natural gas prices during 2015 and into 2016, our liquidity has been significantly negatively impacted.
As of December 31, 2015, we had an aggregate amount of approximately $1.2 billion of debt outstanding. We will be required to pay interest on our senior notes in the amount of $87.6 million in 2016, including $10.9 million in April 2016 and $32.9 million in May 2016. Our ability to make those payments is severely in doubt. In 2015, we incurred a loss from operations of $1.6 billion, including an impairment charge of $1.4 billion. As of March 11, 2016, we had only $32.3 million in cash and cash equivalents. Pursuant to the Eleventh Amendment, the commitments under the Revolver were reduced to $171.8 million, which is equal to our currently outstanding loans ($170 million) and issued letters of credit ($1.8 million) under the Revolver. Because we do not have any unused commitment capacity, we will not be able to draw on the Revolver to pay our second quarter interest payments on our senior notes or for any other purpose. Furthermore, we are required, at the time of borrowing and as a condition to borrowing, to make certain representations to our lenders. We may not currently be able to make these representations, nor is it likely that we will be able to do so in the future unless we can restructure our debt obligations. There can be no assurance that we will be able to restructure our debt obligations. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or to otherwise extend the maturity dates, and to cure any potential defaults under the agreements governing such debt, there is no assurance that any particular action or actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our debt agreements will be sufficient.
Moreover, our lenders may in the future exercise their right to redetermine our $275 million borrowing base under the Revolver. Pursuant to the Eleventh Amendment, any such redetermination will not occur until after May 15, 2016. If our borrowing base is redetermined below the amount of our outstanding borrowings, a deficiency will result, and any deficiency must be repaid within 60 days. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”

34



Capital Resources
Our business plan for 2016 reflects a suspension of our drilling program as a result of depressed commodity prices. Upon the resumption of a drilling program, if any, we expect to allocate substantially all of our capital expenditures to the Eagle Ford. We continually review our drilling and capital expenditure plans and may change the amount we spend, or the allocations, based on available opportunities, product pricing, industry conditions, cash from operating activities and the overall availability of capital. For a detailed analysis of our historical capital expenditures, see the Cash Flows discussion that follows.
Cash From Operating Activities. In addition to commodity price volatility, as discussed in detail below, our cash from operating activities is impacted by the timing of our working capital requirements. The most significant component thereof is the timing of payments made for drilling and completion capital expenditures and the related billing and collection of our partners’ share thereof. This component can be substantial to the extent that we are the operator of lower working interest wells. In certain circumstances, we have and will continue to utilize capital cash calls to mitigate the burden on our working capital. In addition, we have been required to make prepayments for certain oilfield products and services due to the recent reduction in our credit standing.
We historically have actively managed our exposure to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of collar and swap contracts. The level of our hedging activity and duration of the instruments employed depend on our cash flow at risk, available hedge prices, the magnitude of our capital program and our operating strategy. During 2015, our commodity derivatives portfolio resulted in $137.5 million of net cash receipts related to lower than anticipated prices received for our crude oil production and $0.7 million of net cash receipts attributable to lower than anticipated prices received for our natural gas production. If commodity prices remain depressed, we anticipate that our derivative portfolio will continue to result in receipts from settlements for the remainder of 2016.
For 2016, we have hedged approximately 6,000 BOPD at weighted-average floor/swap prices of $80.41 per barrel. Our natural gas hedges have expired and we anticipate remaining unhedged with respect to natural gas production for 2016.
Revolver Borrowings. As of December 31, 2015, the Revolver provided for a revolving commitment and borrowing base of $275 million, including up to $20 million for the issuance of letters of credit. The borrowing base under the Revolver is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base.
The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had outstanding borrowings of $170 million and letters of credit of $1.8 million as of December 31, 2015. Pursuant to the Eleventh Amendment, the commitments under the Revolver were reduced to $171.8 million, which is equal to our currently outstanding loans ($170 million) and issued letters of credit ($1.8 million) under the Revolver. Because we do not have any unused commitment capacity, we will not be able to draw on the Revolver to pay our second quarter interest payments on our senior notes or for any other purpose. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults under the agreements governing such debt, there is no assurance that any particular action or actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our debt agreements will be sufficient.
Moreover, our lenders may in the future exercise their right to redetermine our $275 million borrowing base under the Revolver. Pursuant to the Eleventh Amendment, any such redetermination will not occur until after May 15, 2016. If our borrowing base is redetermined below the amount of our outstanding borrowings, a deficiency will result, and any deficiency must be repaid within 60 days.
For additional information regarding the terms and covenants under the Revolver, see “Capitalization” discussion that follows. The following table summarizes our borrowing activity under the Revolver during the periods presented:
 
Borrowings Outstanding
 
 
 
Weighted-
Average
 
Maximum
 
Weighted-
Average Rate
Three months ended December 31, 2015
$
160,543

 
$
170,000

 
2.5151
%
Year ended December 31, 2015
$
173,904

 
$
232,000

 
2.1981
%
Proceeds from Sales of Assets. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and non-strategic undeveloped acreage, among others.
Capital Market Transactions. From time-to-time and under market conditions that we believe are favorable to us, we have undertaken capital market transactions, including the offering of debt and equity securities. Historically, we have entered into such transactions to facilitate acquisitions and to pursue opportunities to adjust our total capitalization.

35



Cash Flows
The following table summarizes our cash flows for the periods presented:
 
Year Ended December 31,
 
 
 
2015
 
2014
 
Variance
Cash flows from operating activities
 
 
 
 


Operating cash flows, net
$
146,211

 
$
373,362

 
$
(227,151
)
Working capital changes (excluding interest, income taxes and restructuring and exit costs paid), net
(15,918
)
 
8,282

 
(24,200
)
Commodity derivative settlements received (paid), net:
 
 
 
 

Crude oil
137,488

 
(6,170
)
 
143,658

Natural gas
681

 
(1,254
)
 
1,935

Interest payments, net of amounts capitalized
(86,226
)
 
(84,797
)
 
(1,429
)
Income taxes received (paid), net
714

 
(3,612
)
 
4,326

Strategic and financial advisory costs paid
(3,693
)
 

 
(3,693
)
Drilling rig termination costs paid
(6,636
)
 

 
(6,636
)
Acquisition-related arbitration costs paid

 
(589
)
 
589

Restructuring and exit costs paid
(3,318
)
 
(2,498
)
 
(820
)
Net cash provided by operating activities
169,303

 
282,724

 
(113,421
)
Cash flows from investing activities
 

 
 

 
 

Capital expenditures – property and equipment
(364,844
)
 
(774,139
)
 
409,295

Acquisition and working capital-related settlements, net

 
33,712

 
(33,712
)
Proceeds from sales of assets, net
85,189

 
313,933

 
(228,744
)
Net cash used in investing activities
(279,655
)
 
(426,494
)
 
146,839

Cash flows from financing activities
 

 
 

 
 

Proceeds (repayments) from revolving credit facility borrowings, net
135,000

 
(171,000
)
 
306,000

Proceeds from the issuance of preferred stock, net

 
313,330

 
(313,330
)
Payments made to induce conversion of preferred stock

 
(4,256
)
 
4,256

Debt issuance costs paid
(744
)
 
(151
)
 
(593
)
Dividends paid on preferred stock
(18,201
)
 
(12,803
)
 
(5,398
)
Other, net

 
1,428

 
(1,428
)
Net cash provided by financing activities
116,055

 
126,548

 
(10,493
)
Net increase (decrease) in cash and cash equivalents
$
5,703

 
$
(17,222
)
 
$
22,925

Cash Flows From Operating Activities. Commodity prices declined substantially during 2015 resulting in lower realized cash receipts from our product revenues. Our working capital utilization increased during 2015 as we paid down a substantial level of accounts payable and accrued expenses in 2015 attributable to activities from 2014. In addition, we were required to make prepayments in the latter part of the fourth quarter of 2015 for certain oilfield services due to deterioration in our credit standing. During 2015, we paid early termination charges for the early release of four drilling rigs, of which $0.7 million had been accrued at the end of 2014. During 2015, we also incurred and paid higher professional fees and other consulting costs associated with our strategic initiatives, including our refinancing efforts and our search for a new chief executive officer. Restructuring and exit costs paid were higher during 2015 due primarily to the payment of termination and severance benefits of approximately $1.0 million in connection with reductions in headcount. Cash paid for interest, net of amounts capitalized, was higher during 2015 due primarily to higher average amounts outstanding under the Revolver. The overall decline in operating cash flows was partially offset by (i) cash settlements from our commodity derivatives portfolio during 2015 as compared to net payments during 2014 and (ii) the receipt of federal income tax refunds in 2015 as compared to federal and state income tax payments in 2014.
Cash Flows From Investing Activities. As illustrated in the tables below, our cash payments for capital expenditures were substantially lower during 2015 compared to 2014 due primarily to the reduction in our capital program including (i) reductions in the number of operated drilling rigs from eight at the beginning of 2015 to one by the end of the year, (ii) corresponding reductions in well completion and frac crews, (iii) lower pipeline and gathering infrastructure expenditures and (iv) the completion of our water system infrastructure project in 2014.

36



The following table sets forth costs related to our capital expenditure program for the periods presented:
 
Year Ended December 31,
 
2015
 
2014
Oil and gas:
 

 
 

Drilling and completion
$
284,225

 
$
667,385

Lease acquisitions and other land-related costs 1
16,052

 
98,443

Geological and geophysical (seismic) costs
828

 
5,106

Pipeline, gathering facilities and other equipment
3,884

 
21,538

 
304,989

 
792,472

Other – Corporate
562

 
1,463

Total capital program costs
$
305,551

 
$
793,935

_________________
1 Includes site-preparation and other pre-drilling costs.
The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures for additions to property and equipment as reported in our Consolidated Statements of Cash Flows for the periods presented:
 
Year Ended December 31,
 
2015
 
2014
Total capital program costs