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, 2016
 Commission file number: 1-13283
 _________________________________________________________ 
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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)
14701 St. Mary's Lane, Suite 275
Houston, TX 77079
(Address of principal executive offices)
Registrant’s telephone number, including area code: (713) 722-6500
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
 
NASDAQ Global Select Market
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.    ¨
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
o
 
Non-accelerated filer
o
 
Smaller reporting company
ý

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 less than $1,000,000 as of June 30, 2016 (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 OTC Pink. 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.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.   Yes  ý     No   ¨
As of March 10, 2017, 14,992,018 shares of common stock of the registrant were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement relating to the registrant’s Annual Meeting of Shareholders, to be held on May 3, 2017, are incorporated by reference in Part III of this Form 10-K.
 





PENN VIRGINIA CORPORATION
ANNUAL REPORT ON FORM 10-K
 For the Fiscal Year Ended December 31, 2016
 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
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: 

potential adverse effects of the completed Chapter 11, or bankruptcy, proceedings on our liquidity, results of operations, brand,
business prospects, ability to retain financing and other risks and uncertainties related to our emergence from bankruptcy;
the ability to operate our business following emergence from bankruptcy;
our ability to satisfy our short-term and long-term liquidity needs, including our inability to generate sufficient cash
flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital
needs;
negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service
providers, customers, employees, and other third parties;
our new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors
used in estimating enterprise value vary significantly from the current estimates in connection with the application of
fresh start accounting;
plans, objectives, expectations and intentions contained in this report that are not historical;
our ability to execute our business plan in the current commodity price environment;
the sustained decline in and volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural gas;
our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;
our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well
operations;
any impairments, write-downs or write-offs of our reserves or assets;
the projected demand for and supply of oil, natural gas liquids and natural gas;
our ability to contract for drilling rigs, frac crews, 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 our 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 that estimated in our proved oil and natural gas reserves;
drilling and operating risks;
concentration of assets;
our ability to compete effectively against other oil and gas companies;
leasehold terms expiring before production can be established and our ability to replace expired leases;
costs or results of any strategic alternatives
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 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 Part I, Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2016.
Additional information concerning these and other factors can be found in our press releases and public 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 thousand cubic feet of natural gas.
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.
Nasdaq. The NASDAQ Global Select Market.
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.
Play. A geological formation with potential oil and gas reserves.

2




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. A non-GAAP measure representing the present value of estimated future oil and gas revenues, net of estimated direct costs, discounted at an annual discount rate of 10%. PV10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for any GAAP measure. PV10 does not purport to represent the fair value of oil and gas properties.
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
We are 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 drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale field, or the Eagle Ford, in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash. In August 2016, we terminated our remaining operations in the Marcellus Shale in Pennsylvania and are currently in the process of remediating the sites of our former wells in that region.
We were incorporated in the Commonwealth of Virginia in 1882. On December 28, 2016, our common stock began trading publicly on the Nasdaq under the symbol “PVAC.” Our headquarters and corporate office is located 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 the exploration, development and production of crude oil, NGLs and natural gas. Each of our operating regions has similar economic characteristics and meets the criteria for aggregation as one reporting segment.
We lease a highly contiguous position of approximately 54,000 net acres (as of March 10, 2017) in the core liquids-rich area or “volatile oil window” of the Eagle Ford in Gonzales and Lavaca Counties in Texas, which we believe contains a substantial number of drilling locations that will support a multi-year drilling inventory.
In 2016, our total production was comprised of 69 percent crude oil, 16 percent NGLs and 15 percent natural gas. Crude oil accounted for 87 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, 2016, our total proved reserves were approximately 50 MMBOE, of which 53 percent were proved developed reserves and 74 percent were crude oil. Approximately 95 percent of our reserves were located in South Texas and 51 percent were proved developed reserves. As of December 31, 2016, we had 431 gross (254.9 net) productive wells, approximately 78 percent of which we operate, and owned approximately 130,000 gross (90,000 net) acres of leasehold and royalty interests, approximately 38 percent of which were undeveloped. We suspended our drilling program in February 2016 due primarily to our financial condition at that time as well as unfavorable industry economic conditions including depressed commodity prices. We resumed our drilling program in November 2016 subsequent to our emergence from bankruptcy (see discussion below). During 2016, we drilled and completed five gross (2.9 net) wells, all in the Eagle Ford and all during the period prior to the aforementioned suspension of our drilling program. For a more detailed discussion of our production, reserves, drilling activities, wells and acreage, see Part I, Item 2, “Properties.”
Emergence from Bankruptcy Proceedings and Fresh Start Accounting
On May 12, 2016, or the Petition Date, we and eight of our subsidiaries, or the Chapter 11 Subsidiaries, filed voluntary petitions (In re Penn Virginia Corporation, et al, Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code, or the Bankruptcy Code, in the United States Bankruptcy Court for the Eastern District of Virginia, or the Bankruptcy Court.
On August 11, 2016, or the Confirmation Date, the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates, or the Plan, and we subsequently emerged from bankruptcy on September 12, 2016, or the Effective Date. For a more detailed discussion of our bankruptcy proceedings and our emergence from bankruptcy, see Key Developments included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 4 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
Upon the Effective Date, we adopted and applied the relevant guidance with respect to the accounting and financial reporting for entities that have emerged from bankruptcy proceedings, or Fresh Start Accounting. The adoption of Fresh Start Accounting resulted in a new reporting entity, the Successor, for financial reporting purposes. To facilitate our discussion and analysis of our properties, financial condition and results of operations herein, we refer to the reorganized company as the “Successor” for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. For a more detailed discussion of Fresh Start Accounting, see Note 5 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”

4




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 long-term agreements to provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region through 2041 as well as volume capacity support for certain downstream interstate pipeline transportation.
Natural gas service contracts. We have 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.
Drilling and Completion. From time to time we enter into short term drilling and completion contracts in the ordinary course of business to ensure availability of rigs and frac crews to satisfy our development program.
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, 2016, approximately 93 percent of our consolidated product revenues were attributable to three customers: Republic Midstream Marketing, LLC; Phillips 66 Company; 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. Competition is particularly intense in the acquisition of prospective oil and gas properties. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. We also compete with other oil and gas companies to secure drilling rigs and other equipment necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Such equipment and labor may be in short supply from time to time. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. 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, 2016, we have recorded asset retirement obligations of $2.5 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general.
In addition, the United States Environmental Protection Agency, or the EPA, has designated energy extraction as one of six national enforcement initiatives, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas extraction and production activities. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition, results of operations 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.

5




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 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 more stringent regulation under 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,” or WOTUS, for all Clean Water Act programs, which went into effect in August 2015. The rule is currently stayed, and the United States Supreme Court on January 13, 2017, agreed to hear a case regarding the question of which court had the jurisdiction over legal challenges to the WOTUS rule. In response to the stay and subsequent legal challenges, 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. However, the WOTUS rule also faces significant scrutiny from the Trump administration.
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. In 2016, the EPA finalized 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
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 EPA released the results of its comprehensive research study to investigate the potential adverse impacts of hydraulic fracturing on drinking water and ground water in December 2016, finding that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. These developments 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.

6




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. We currently disclose all hydraulic fracturing additives we use on www.FracFocus.org, a website created by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission.
Prohibitions and Other Regulatory Limitations on Hydraulic Fracturing. There have been a variety of regulatory initiatives at the state level to restrict oil and gas drilling operations in certain locations.
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 existing wells. The adoption of federal, state or local laws or the implementation of regulations regarding hydraulic fracturing that are more stringent could cause a decrease in the completion of new oil and gas wells, as well as increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. We use hydraulic fracturing extensively and any increased federal, state, or local regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover.
Clean Air Act. Our operations are subject to the Clean Air Act, or the CAA, and comparable state and local requirements. In 1990, the U.S. Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed, and continue to develop, regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Further, stricter requirements could negatively impact our production and operations.
On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. Further, in May 2016, the EPA issued final NSPS governing methane emissions from the oil and natural gas industry as well as source determination standards for determining when oil and gas sources should be aggregated for CAA permitting and compliance purposes. The NSPS for methane extends the 2012 NSPS to completions of hydraulically fractured oil wells, equipment leaks, pneumatic pumps and natural gas compressors. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests for oil and natural gas facilities. These rules are expected to result in an increase to our operating costs and change to our operations. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs on our operations.
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 emission control in those areas. While we are not able to determine the extent to which this new standard will impact our business at this time, it has the potential to have a material impact on our operations and cost structure.
In addition, on June 3, 2016, the EPA finalized a rule “aggregating” individual wells and other facilities and their collective emissions for purposes of determining whether major source permitting requirements apply under the CAA. These changes may introduce uncertainty into the permitting process and could require more lengthy and costly permitting processes and more expensive emission controls.
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

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with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
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. Most recently in April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. The EPA has issued the “Final Mandatory Reporting of Greenhouse Gases” Rule and a series of revisions to it, which requires operators of oil and gas production, natural gas processing, transmission, distribution and storage facilities and other stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions occurring in the prior calendar year on a facility-by-facility basis. 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 certain circumstances, large sources of GHG emissions are subject to preconstruction permitting under the EPA’s Prevention of Significant Deterioration program. This program historically has had minimal applicability to the oil and gas production industry. However, there can be no assurance that our operations will avoid applicability of these or similar permitting requirements, which impose costs relating to emissions control systems and the efforts needed to obtain the permit.
Additional GHG regulations potentially affecting our industry include those described above under the subheading “Clean Air Act” which relate to methane.
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.
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 59 employees as of December 31, 2016. 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. Investors can obtain current and important information about the company from our website on a regular basis. We intend for our website to serve as a means of public dissemination of information for purposes of Regulation FD.

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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 in the future. 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 recently emerged from bankruptcy, which could adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our recent emergence could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:
key suppliers could terminate their relationship or require financial assurances or enhanced performance;
our ability to renew existing contracts and compete for new business may be adversely affected;
our ability to attract, motivate and/or retain key executives and employees may be adversely affected;
employees may be distracted from performance of their duties or more easily attracted to other employment opportunities;
our ability to attract and retain customers may be negatively impacted;
we may experience challenges to the Plan; and
we may incur legal costs associated with addressing claims under the Plan.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting and the full cost method of accounting for oil and gas properties.
In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.
In addition, upon our emergence from bankruptcy, we adopted Fresh Start Accounting and the full cost method of accounting for oil and gas properties. Accordingly, our future financial condition and results of operations may not be comparable to the financial condition or results of operations reflected in the Predecessor’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock. The adoption of Fresh Start Accounting established a new basis for our assets and liabilities on the Effective Date. The adoption of the full cost method of accounting for oil and gas properties, as compared to the successful efforts method utilized by the Predecessor, results in the capitalization of additional costs as well as different methodologies to determine depletive write-offs and impairments. For a more detailed discussion of Fresh Start Accounting and the full cost method of accounting for oil and gas properties, see the discussion of “Critical Accounting Estimates” included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” as well as Notes 3, 5 and 7 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
If we cannot obtain sufficient capital when needed, we will not be able to continue with our 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 business strategy, we may be required to curtail operations, which could adversely affect our financial condition, results of operations and cash flows.

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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 relations, regulation and taxation.
It is impossible to predict future commodity price movements with certainty; however, many of our projections and estimates are based on assumptions as to the future prices of crude oil, NGLs and natural gas. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future will likely differ from our estimates. Any substantial or extended decline in the actual prices of crude oil, NGLs or natural gas would have a material adverse effect on our business, financial position, results of operations and cash flows and borrowing capacity, the quantities of oil and gas reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.
The market price of our common stock is subject to volatility.
Upon our emergence from bankruptcy, our Predecessor common stock was canceled and we issued new common stock. Our common stock is currently listed on the Nasdaq. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of Fresh Start Accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this report. Significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.
There may be future sales or other dilution of our equity, which may adversely affect the market price of our common stock.
We are not restricted from issuing additional common stock, including securities that are convertible into or exchangeable for, or that represent a right to receive, common stock. Any issuance of additional shares of our common stock or convertible securities will dilute the ownership interest of our common stockholders. Sales of a substantial number of shares of our common stock or other equity-related securities in the public market could depress the market price of our common stock and impair our ability to raise capital through the sale of additional equity securities. We cannot predict the effect that future sales of our common stock or other equity-related securities would have on the market price of our common stock.
Our future performance depends on our ability to find or acquire additional oil and gas reserves that are economically recoverable.
Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in oil and gas production and lower revenues and cash flows from operating activities. We must make substantial capital expenditures to find, acquire, develop and produce new oil and gas reserves. 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. Furthermore, external sources of capital may be limited.
Exploration and development drilling may not result in commercially productive reserves.
Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive 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, including:
unexpected drilling conditions;

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elevated pressure or irregularities in geologic formations;
title problems;
equipment failures or accidents;
costs, shortages or delays in the availability of drilling rigs, crews, equipment and materials;
shortages in experienced labor;
surface access restrictions;
failure to secure 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, frac crews, production and other equipment and related services. The availability of drilling rigs, frac crews and equipment can vary significantly from region to region at any particular time. Although land drilling rigs and frac crews can be moved from one region to another in response to changes in levels of demand, an undersupply in any region may result in drilling and/or completions delays and higher well costs 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 holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover initial drilling costs.
Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our business, financial condition, results of operations and cash flows. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or natural gas from all of them.
We may not adhere to our proposed drilling schedule.
Our final determination of whether to drill any wells will be dependent on a number of factors, including:
the results of our exploration efforts and the acquisition, review and analysis of the seismic data;
the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
the approval of the prospects by the other participants after additional data has been compiled;
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and gas and the availability and prices of drilling rigs and crews, frac crews, and related equipment and material; and
the availability of leases and permits on reasonable terms for the prospects.
Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. There can be no assurance that these projects can be successfully developed or that any identified drill sites or budgeted wells will, if drilled, encounter reservoirs of commercially productive oil or gas or that we will be able to complete such wells on a timely basis, or at all. We may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects or budgeted wells within such project area.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may cause volatility in our quarterly operating results.
The unavailability, high cost or shortage of drilling rigs, frac crews, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, frac crews, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of drilling rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig and frac crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs and frac crews at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing drilling rigs or frac crews, and such service providers may choose to cease providing services to us. Shortages of drilling rigs, frac crews, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars,

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fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.
Pursuant to the Plan, the composition of our Board changed significantly. Currently, the Board is made up of four directors, none of which previously served on the Board of the Company. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.
The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.
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.
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 our 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 2016, approximately 93 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.
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

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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, 2016, approximately 47 percent of our estimated proved reserves were proved undeveloped, compared to 25 percent at December 31, 2015. 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.
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. With all other factors held constant, if commodity prices used in the reserve report were to decrease by 10%, our standardized measure and PV-10 would have decreased from $317.5 million to $234.9 million, respectively. Any adjustments to the estimates of proved reserves or decreases in the price of our commodities may decrease the value of our securities.
We may record impairments 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 a write-down that would further decrease reported earnings.
The full cost method of accounting for oil and gas properties under GAAP requires that at the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated discounted future net revenues from proved properties adjusted for costs excluded from amortization and related income taxes, or a Ceiling Test. The estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. In addition to revisions to reserves and the impact of lower commodity prices, Ceiling Test write-downs may occur due to increases in estimated operating and development costs and other factors.
During the past several years, we have been required to write-down the value of certain of our oil and gas properties and related assets, including $1.4 billion in 2015 while we applied the the successful efforts method of accounting for oil and gas properties. We could experience additional write-downs in the future while applying the full cost method of accounting for oil and gas properties. While such a charge reflects our ability to recover the carrying value of our investments, it does not impact our cash flows from operating activities.

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Our business depends on gathering, processing, refining and transportation facilities owned by others.
We deliver substantially all of our oil and gas production through pipelines and trucks that we do not own. The marketability of our production depends upon the availability, proximity and capacity of these pipelines and trucks, as well as gathering systems, gas processing facilities and downstream refineries. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells, the reduction in wellhead pricing or the delay or discontinuance of development plans for properties. Federal, state and local regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather, process, refine and market our oil and gas.
We rely on third-party service providers to conduct the drilling and completion operations on properties we operate.
Where we are the operator of a property, we rely on third-party service providers to perform necessary drilling and completion operations. The ability and availability 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, NGLs and natural gas, prevailing economic conditions and financial, business and other factors. The failure of a third-party service provider to adequately perform operations on a timely basis could delay drilling or completion operations, 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.
We have limited control over the activities on properties we do not operate.
In 2016, other companies operated approximately nine 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

14




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.
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.
The borrowing base under our credit facility may be reduced in the future if commodity prices decline.
The borrowing base under our credit agreement, or Credit Facility, is $128 million as of December 31, 2016. Our borrowing base is redetermined at least twice each year and is scheduled to be redetermined during April 2017. If crude oil, NGL or natural gas prices decline, the borrowing base under the Credit Facility may be reduced. As a result, we may be unable to obtain funding under the Credit Facility. If funding is not available when or in the amounts needed, or is available only on unfavorable terms, it might adversely affect our development plan and our ability to make new acquisitions, each of which could have a material adverse effect on our production, financial condition, results of operations and cash flows.
The Credit Facility has restrictive covenants that could limit our financial flexibility.
The Credit Facility contains financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the Credit Facility is subject to compliance with certain financial covenants, including leverage, interest coverage and current ratios.
The Credit Facility includes other restrictions that, among other things, limit our ability to incur indebtedness; grant liens; engage in mergers, consolidations and liquidations; make asset dispositions, restricted payments and investments; enter into transactions with affiliates; and amend, modify or prepay certain indebtedness.
Our business plan and our compliance with these covenants are based on a number of assumptions, the most important of which is relatively stable oil and gas prices at economically sustainable levels. If the price that we receive for our oil and gas production deteriorates significantly from current levels it could lead to lower revenues, cash flows and earnings, which in turn could lead to a default under certain financial covenants contained in our Credit Facility. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period as the amounts outstanding under our Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings. Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts. We may not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.
We do not expect to pay dividends in the foreseeable future.
We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

15




Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and Bylaws include, among other things, those that:
authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;
establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and
limit the persons who may call special meetings of stockholders.
While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.
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 Part I, 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 or produced water 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.

16




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 drill and 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 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.
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 issued rules restricting methane emissions from hydraulically fractured and refractured gas wells, compressors, pneumatic controls, storage vessels, and natural gas processing plants. For more information on GHG regulation, see Part I, 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, see Part I, Item 1, “Business - Environmental Regulation - Climate Change.”
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells. The EPA released the final results of its comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources in December 2016. The EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. The results of the EPA’s study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. In past sessions, Congress has considered, but did not pass, legislation to amend the Safe Drinking Water Act, or SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. The EPA has issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority.

17




In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans/moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. Texas has adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Moreover, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, Texas regulators have asserted regulatory authority to limit injection activities in certain wells in an effort to reduce seismic activity. A 2015 U.S. Geological Survey report identified areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction.
The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.
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 three years or less. While intended to reduce the effects of volatile crude oil, NGL and natural gas prices, such transactions may limit our potential gains if crude oil, NGL or natural gas prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how crude oil, NGL or natural gas prices fluctuate in the future.
In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
our production is less than expected;
there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
the counterparties to our futures contracts fail to perform under the contracts; or
a sudden, unexpected event materially impacts crude oil, NGL or natural gas prices.
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, 2016, 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.

18




Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and 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.
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.
A cyber incident could result in theft of confidential information, data corruption or operational disruption.
The oil and gas industry is increasingly 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 insufficient, 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
None.
Item 2
 Properties
As of December 31, 2016, our primary oil and gas assets were 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.

19




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 1
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
(MMBOE)
 
$ in millions
 
$ in millions
2016 (Successor)
 

 
 
 
 

 
 

 
 

 
 

Developed
 
 
 
 
 
 

 
 
 
 
Producing
17.5

 
4.3

 
24.8

 
25.9

 
 
 
 
Non-producing
0.2

 
0.1

 
0.1

 
0.3

 
 
 
 
 
17.7

 
4.4

 
24.9

 
26.2

 
 
 
 
Undeveloped
18.9

 
2.4

 
11.8

 
23.3

 
 
 
 
 
36.6

 
6.8

 
36.7

 
49.5

 
$
317.5

 
$
317.5

 
 
 
 
 
 
 
 
 
 
 
 
Price measurement used 2
$42.75/Bbl

 
$12.33/Bbl

 
$2.48/MMBtu

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2015 (Predecessor)

 

 

 

 

 
 
Developed
 
 
 
 
 
 
 
 
 
 
 
Producing
19.6

 
6.1

 
36.8

 
31.8

 
 
 
 
Non-producing
0.6

 
0.1

 
0.4

 
0.8

 
 
 
 
 
20.2

 
6.2

 
37.2

 
32.6

 
 
 
 
Undeveloped
9.3

 
1.0

 
5.0

 
11.1

 
 
 
 
 
29.5

 
7.2

 
42.2

 
43.7

 
$
323.3

 
$
323.3

 
 
 
 
 
 
 
 
 
 
 
 
Price measurement used 2
$50.28/Bbl

 
$14.44/Bbl

 
$2.70/MMBtu

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2014 (Predecessor)
 
 
 
 
 
 
 
 
 
 
 
Developed
 
 
 
 
 
 
 
 
 
 
 
Producing
21.8

 
7.4

 
77.9

 
42.1

 
 
 
 
Non-producing
0.3

 
0.7

 
16.6

 
3.8

 
 
 
 
 
22.1

 
8.1

 
94.5

 
45.9

 
 
 
 
Undeveloped
47.0

 
11.1

 
64.7

 
68.9

 
 
 
 
 
69.0

 
19.2

 
159.2

 
114.8

 
$
1,182.4

 
$
1,472.5

 
 
 
 
 
 
 
 
 
 
 
 
Price measurement used 2
$94.99/Bbl

 
$25.49/Bbl

 
$4.35/MMBtu

 
 
 
 
 
 
___________________
1 PV10 represents a non-GAAP measure that is most directly comparable to the Standardized Measure as defined in GAAP. The Standardized Measure represents the discounted future net cash flows from our proved reserves after future income taxes discounted at 10% in accordance with SEC criteria. PV10 represents the Standardized Measure without regard to income taxes. Our Standardized Measures for 2016 and 2015 did not include any income tax effect. Accordingly, our PV10 and Standardized Measure values are equivalent as of those dates. We believe that PV10 is a meaningful supplemental disclosure to the Standardized Measure as the the PV10 concept is widely used within the industry and by the financial and investment community to evaluate the proved reserves on a comparable basis across companies without regard to the individual owner’s unique income tax position. We utilize PV10 to evaluate the potential return on investment in our oil and gas properties as well as evaluating properties for potential purchases and sales.
2 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, as adjusted for basis differentials and product quality, were as follows: crude oil - $40.97, $45.78 and $92.91 each per Bbl, NGLs - $11.82, $13.15 and $25.09 each per Bbl and natural gas - $2.40, $2.59 and $4.32 each per MMBtu, for December 31, 2016, 2015 and 2014, respectively. NGL prices were estimated as a percentage of the base crude oil price.

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, 2016:
 
 
Proved
 
% of Total
Proved
 
% Proved
Region
 
Reserves
 
Reserves
 
Developed
 
 
(MMBOE)
 
 

 
 

South Texas
 
47.0

 
95
%
 
51
%
Mid-Continent
 
2.5

 
5
%
 
100
%
 
 
49.5

 
100
%
 
53
%
A discussion and analysis of the changes in our total proved reserves is provided in the Supplemental Information on Oil and Gas Producing Activities included in Part II, Item 8, “Financial Statements and Supplementary Data.”

20




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. The following table sets forth the changes in our proved undeveloped reserves, all of which are located in the Eagle Ford in South Texas, during the year ended December 31, 2016:
 
Crude Oil
 
NGLs
 
Natural Gas
 
Oil Equivalents
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
(MMBOE)
Proved undeveloped reserves at beginning of year (Predecessor)
9.3

 
1.0

 
5.0

 
11.1

Revisions of previous estimates
(1.3
)
 

 

 
(1.3
)
Extensions and discoveries
11.5

 
1.5

 
7.2

 
14.2

Conversion to proved developed reserves
(0.6
)
 
(0.1
)
 
(0.4
)
 
(0.7
)
Proved undeveloped reserves at end of year (Successor)
18.9

 
2.4

 
11.8

 
23.3

In 2016, our proved undeveloped reserves increased by 12.2 MMBOE. We experienced negative revisions of 1.3 MMBOE due to the loss of certain locations resulting from changes in the timing of our development plans and lower EURs due primarily to lower commodity prices compared to year-end 2015. Extensions and discoveries of 14.2 MMBOE were attributable primarily to the resumption of our development plans in the Eagle Ford. In addition, we converted 0.7 MMBOE from proved undeveloped to proved developed reserves in the Eagle Ford. During 2016, we incurred capital expenditures of $6.8 million in connection with the conversion of proved undeveloped reserves to proved developed reserves. The conversion of these reserves occurred in the first quarter of 2016 prior to the termination of our drilling program which preceded our bankruptcy filing. Accordingly, our conversion rate of proved undeveloped reserves as of beginning of the year is not representative as we did not resume our drilling program until November 2016.
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 included in Part II, Item 8, “Financial Statements and Supplementary Data” and the report of DeGolyer and MacNaughton, Inc., dated February 9, 2017, 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, 2016 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 Part I, 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 petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.
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. In addition, we sold certain non-core properties in the Eagle Ford and Granite Wash in October 2015. The production associated with these former properties is also included within “Divested properties.” Our remaining operations are represented in the Eagle Ford in South Texas, the Granite Wash in Oklahoma and relatively minor operations, which we terminated in August 2016, in the Marcellus Shale in Pennsylvania.

21




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
 
 
Successor
 
 
Predecessor
 
 
September 13 Through
 
 
January 1 Through
 
 
 
 
 
 
December 31,
 
 
September 12,
 
Year Ended December 31,
Region
 
2016
 
 
2016
 
2015
 
2014
 
 
(MBOE) 
 
 
 

 
(MBOE) 
 
 

South Texas
 
937

 
 
3,071

 
6,903

 
5,817

Mid-Continent and other 1
 
103

 
 
276

 
460

 
743

Divested properties 2
 

 
 

 
560

 
1,375

 
 
1,040

 
 
3,346

 
7,923

 
7,934

 
 
 
 
 
 
 
 
 
 
 
 
Average Daily Production
 
 
Successor
 
 
Predecessor
 
 
September 13 Through
 
 
January 1 Through
 
 
 
 
 
 
December 31,
 
 
September 12,
 
Year Ended December 31,
Region
 
2016
 
 
2016
 
2015
 
2014
 
 
(BOEPD) 
 
 
 
 
(BOEPD) 
 
 
South Texas
 
8,518

 
 
11,996

 
18,912

 
15,937

Mid-Continent and other 1
 
936

 
 
1,082

 
1,260

 
2,036

Divested properties 2
 

 
 

 
2,151

 
3,765

 
 
9,454

 
 
13,078

 
22,323

 
21,738

_____________________________________________
1 Includes total production and average daily production of approximately 10 MBOE (48 BOEPD), 22 MBOE (60 BOEPD) and 24 MBOE (66 BOEPD) for 2016, 2015 and 2014, respectively, attributable to our three active Marcellus Shale wells.
2 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) and 844 MBOE (2,311 BOEPD) in 2015 and 2014, 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) in 2014. We sold certain non-core properties in the Eagle Ford and Granite Wash in October 2015, which represented total production and average daily production of approximately 111 MBOE (364 BOEPD) and 118 MBOE (325 BOEPD) in 2015 and 2014, respectively.
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:
 
Successor
 
 
Predecessor
 
September 13 Through
 
 
January 1 Through
 
 
 
 
 
December 31,
 
 
September 12,
 
Year Ended December 31,
 
2016
 
 
2016
 
2015
 
2014
Average prices:
 
 
 
 
 
 
 
 
Crude oil ($ per Bbl)
$
46.63

 
 
$
35.21

 
$
44.81

 
$
90.50

NGLs ($ per Bbl)
$
16.51

 
 
$
11.38

 
$
12.24

 
$
31.14

Natural gas ($ per Mcf)
$
2.81

 
 
$
2.06

 
$
2.62

 
$
4.44

Aggregate ($ per BOE)
$
37.17

 
 
$
27.99

 
$
33.19

 
$
64.64

Average production and lifting cost ($ per BOE):
 
 
 
 
 
 
 
 
Lease operating
$
5.13

 
 
$
4.67

 
$
5.36

 
$
6.09

Gathering processing and transportation
2.93

 
 
3.96

 
3.01

 
2.31

 
$
8.06

 
 
$
8.63

 
$
8.37

 
$
8.40


22




Significant Fields
Our properties in the Eagle Ford in South Texas, which contain primarily oil reserves, represented approximately 95 percent of our total equivalent proved reserves as of December 31, 2016.
The following table sets forth certain information with respect to this field for the periods presented:
 
Successor
 
 
Predecessor
 
September 13 Through
 
 
January 1 Through
 
 
 
 
 
December 31,
 
 
September 12,
 
Year Ended December 31,
 
2016
 
 
2016
 
2015
 
2014
Production: 1
 
 
 
 

 
 

 
 

Crude oil (MBbl)
695

 
 
2,265

 
4,733

 
4,369

NGLs (MBbl)
130

 
 
449

 
1,169

 
771

Natural gas (MMcf)
674

 
 
2,141

 
6,011

 
4,063

Total (MBOE)
937

 
 
3,071

 
6,903

 
5,817

Percent of total company production
90
%
 
 
92
%
 
87
%
 
73
%
Average prices:
 
 
 
 
 
 
 
 
Crude oil ($ per Bbl)
$
46.73

 
 
$
35.24

 
$
44.73

 
$
90.70

NGLs ($ per Bbl)
$
14.82

 
 
$
10.34

 
$
11.03

 
$
25.24

Natural gas ($ per Mcf)
$
2.79

 
 
$
2.05

 
$
2.64

 
$
4.20

Aggregate ($ per BOE)
$
38.71

 
 
$
28.94

 
$
34.84

 
$
74.40

Average production and lifting cost ($ per BOE): 2
 
 
 
 
 
 
 
 
Lease operating
$
5.39

 
 
$
4.58

 
$
5.04

 
$
5.36

Gathering processing and transportation
2.58

 
 
3.50

 
2.66

 
1.76

 
$
7.97

 
 
$
8.08

 
$
7.70

 
$
7.12

_____________________________________________
1 Excludes production from certain non-core Eagle Ford properties that we sold in October 2015.
2 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, all of which were in the Eagle Ford in South Texas, during the years ended December 31, 2016, 2015 and 2014, 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. 
 
 
 
 
 
2016
 
2015
 
2014
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development
 

 
 

 
 

 
 

 
 

 
 

Productive
5

 
2.9

 
61

 
38.6

 
83

 
50.8

Dry well

 

 

 

 
1

 
0.8

Under evaluation

 

 

 

 

 

Total
5

 
2.9

 
61

 
38.6

 
84

 
51.6

 
 
 
 
 
 
 
 
 
 
 
 
Wells in progress at end of year1
5

 
2.6

 
4

 
2.3

 
28

 
14.3

___________
1 Includes three gross (1.4 net) wells completing, one gross (0.6 net) well waiting on completion and one gross (0.6 net) well being drilled as of December 31, 2016.
Present Activities
As of December 31, 2016, we had five gross (2.6 net) wells in progress, all of which were located in the Eagle Ford in South Texas. As of March 15, 2017, all 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 8,000 BOPD (gross) in our South Texas region

23




for a period of 15 years under a gathering agreement with Republic Midstream, LLC, or Republic Midstream. Our production and reserves are currently sufficient to fulfill the current 8,000 BOPD delivery commitment under those agreements. In 2016 following the suspension of our drilling program, we incurred deficiencies of $0.4 million as a result of our inability to satisfy the 15,000 BOPD delivery commitment under such agreements prior to their August 2016 amendments.
Productive Wells
The following table sets forth by region the productive wells in which we had a working interest as of December 31, 2016:
 
 
Primarily Oil
 
Primarily Natural Gas
 
Total
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
South Texas 1
 
334

 
212.2

 

 

 
334

 
212.2

Mid-Continent
 
2

 
1.6

 
95

 
41.1

 
97

 
42.7

 
 
336

 
213.8

 
95

 
41.1

 
431

 
254.9

Of the total wells presented in the table above, we are the operator of 335 gross (304 oil and 31 gas) and 220.6 net (201.3 oil and 19.3 gas) wells. In addition to the above working interest wells, we own royalty interests in 12 gross wells.
Acreage
The following table sets forth by region our developed and undeveloped acreage as of December 31, 2016 (in thousands):
 
 
Developed 
 
Undeveloped 
 
Total 
Region
 
Gross 
 
Net 
 
Gross 
 
Net 
 
Gross 
 
Net 
South Texas
 
74.5

 
48.2

 
27.5

 
22.3

 
102.0

 
70.5

Mid-Continent and other
 
15.6

 
7.4

 
12.1

 
11.9

 
27.7

 
19.3

 
 
90.1

 
55.6

 
39.6

 
34.2

 
129.7

 
89.8

The primary terms of our leases generally range from three to five years and we do not have any concessions. All of our acreage in the Granite Wash in Oklahoma and the Marcellus Shale in Pennsylvania, both of which are included in the Mid-Continent and other region, is HBP. As of December 31, 2016, 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:
Region
 
2017
 
2018
 
2019
 
Thereafter
South Texas
 
17.7
 
3.5
 
0.0
 
1.1
Mid-Continent and other
 
2.5
 
0.0
 
9.4
 
0.0
We plan to allow approximately 20,500 gross (17,700 net) acres of undeveloped acreage in the Eagle Ford expire as scheduled in 2017 as they are not considered core to our current development plans. Accordingly, we do not believe that the scheduled expiration of our undeveloped acreage will substantially affect our ability or plans to conduct our exploration and development activities.
 
Item 3
Legal Proceedings
On May 12, 2016, we and the Chapter 11 Subsidiaries filed voluntary petitions (In re Penn Virginia Corporation, et al. Case No. 16-32395) seeking relief under the Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia.
On August 11, 2016, the Bankruptcy Court confirmed our Plan, and we subsequently emerged from bankruptcy on September 12, 2016. See Note 4 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,” for a more detailed discussion of our bankruptcy proceedings.
On February 7, 2017, a former shareholder of the Company filed a motion in the Bankruptcy Court requesting that the Bankruptcy Court set aside its prior order confirming the Plan, previously confirmed on August 11, 2016. This motion currently has no impact on the order confirming the Plan. We believe the motion is without merit and will defend confirmation of the Plan.
See Note 16 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” 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.

24




Part II
 Item 5
Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
In connection with our reorganization and emergence from bankruptcy, all of our Predecessor common stock, formerly traded under the symbol “PVA,” was canceled, extinguished and discharged. On November 15, 2016, our Successor common stock, or New Common Stock, was listed on the OTCQX U.S. Premier Market under the symbol “PVAC.” Prior to such time, there was no established trading market for the New Common Stock. On December 28, 2016, the New Common Stock was listed and began trading on the Nasdaq under the symbol “PVAC.”
The market data below represents the high and low sales prices (composite transactions) of the New Common Stock since November 15, 2016:
 
 
 
 
 
 
 
 
 
 
 
Sales Price
Quarter Ended
 
 
 
High
 
Low
December 31, 2016
 
 
 
$
50.00

 
$
34.75

Equity Holders
As of March 1, 2017, there were 59 record holders and 1,702 beneficial owners (held in street name) of our New Common Stock.
Dividends
We have not paid nor do we intend in the foreseeable future to pay any cash dividends on the New Common Stock. Furthermore, we are restricted from paying dividends under the Credit Facility.
Securities Authorized for Issuance Under Equity Compensation Plans
See Part III, Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” and Note 18 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” for information regarding shares of New Common Stock authorized for issuance under our stock compensation plans.
Recent Sales of Unregistered Securities
Pursuant to the Plan, a total of $50 million of proceeds were received on the Effective Date from a rights offering conducted in connection with the Plan, or the Rights Offering, resulting in the issuance of 7,633,588 shares of New Common Stock to holders of claims arising under our 7.25% Senior Notes due 2019, or the 2019 Senior Notes, and 8.50% Senior Notes due 2020, or the 2020 Senior Notes, and, together with the 2019 Senior Notes, the Senior Notes, certain holders of general unsecured claims and to the parties, or Backstop Parties, supporting a backstop commitment agreement, or the Backstop Commitment Agreement. The shares of New Common Stock issued to participants in the Rights Offering and to the Backstop Commitment Parties were issued under the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) thereof.
Issuer Purchases of Equity Securities
We did not repurchase any shares of our New Common Stock in the fourth quarter of 2016.
 

25




Item 6
Selected Financial Data
The following selected historical financial and operating information was derived from our Consolidated Financial Statements. The selected financial data should be read in conjunction with Part II, 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 Part II, Item 8, “Financial Statements and Supplementary Data.”
 
Successor
 
 
Predecessor
 
September 13
 
 
January 1
 
 
 
 
 
 
 
 
 
Through
 
 
Through
 
 
 
 
 
 
 
 
 
December 31,
 
 
September 12,
 
Year Ended December 31,
 
2016
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
 
 
(in thousands, except per share amounts)
Statements of Operations and Other Data:
 
 
 
 

 
 

 
 

 
 

 
 

Revenues
$
39,003

 
 
$
94,310

 
$
305,298

 
$
636,773

 
$
431,468

 
$
317,149

Operating income (loss )1
$
11,391

 
 
$
(20,856
)
 
$
(1,565,041
)
 
$
(615,985
)
 
$
(92,046
)
 
$
(147,091
)
Net income (loss) 2
$
(5,296
)
 
 
$
1,054,602

 
$
(1,582,961
)
 
$
(409,592
)
 
$
(143,070
)
 
$
(104,589
)
Preferred stock dividends 3
$

 
 
$
5,972

 
$
22,789

 
$
17,148

 
$
6,900

 
$
1,687

Income (loss) attributable to common shareholders 2
$
(5,296
)
 
 
$
1,048,630

 
$
(1,605,750
)
 
$
(430,996
)
 
$
(149,970
)
 
$
(106,276
)
Income (loss) per common share, basic
$
(0.35
)
 
 
$
11.91

 
$
(21.81
)
 
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
Income (loss) per common share, diluted
$
(0.35
)
 
 
$
8.50

 
$
(21.81
)
 
$
(6.26
)
 
$
(2.41
)
 
$
(2.22
)
Weighted-average shares outstanding:
 
 
 
 
 
 

 
 

 
 

 
 

Basic
14,992

 
 
88,013

 
73,639

 
68,887

 
62,335

 
47,919

Diluted
14,992

 
 
124,087

 
73,639

 
68,887

 
62,335

 
47,919

Dividends declared per share
$

 
 
$

 
$

 
$

 
$

 
$
0.113

Cash provided by operating activities
$
30,774

 
 
$
30,247

 
$
169,303

 
$
282,724

 
$
261,512

 
$
241,458

Cash paid for capital expenditures
$
4,812

 
 
$
15,359

 
$
364,844

 
$
774,139

 
$
504,203

 
$
370,907

 
 
 
 
 
 
 
 
 
 
 
 
 
Total production (MBOE)
1,040

 
 
3,346

 
7,923

 
7,934

 
6,824

 
6,513

 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
September 12,
 
December 31,
Balance Sheet and Other Data:
2016
 
 
2016
 
2015
 
2014
 
2013
 
2012
Property and equipment, net
$
247,473

 
 
$
253,510

 
$
344,395

 
$
1,825,098

 
$
2,237,304

 
$
1,723,359

Total assets
$
291,686

 
 
$
333,974

 
$
517,725

 
$
2,201,810

 
$
2,472,830

 
$
1,831,733

Total debt
$
25,000

 
 
$
75,350

 
$
1,224,383

 
$
1,085,429

 
$
1,252,808

 
$
583,503

Shareholders’ equity (deficit)
$
185,548

 
 
$
190,895

 
$
(915,121
)
 
$
675,817

 
$
788,804

 
$
895,116

 
 
 
 
 
 
 
 
 
 
 
 
 
Actual shares outstanding at period-end
14,992

 
 
14,992

 
81,253

 
71,569

 
65,307

 
55,117

Proved reserves as of December 31,(MMBOE)
49

 
 
 
 
44

 
115

 
136

 
113

_____________________________________________
1 Operating loss for 2015, 2014, 2013 and 2012 included impairment charges of $1.4 billion, $791.8 million, $132.2 million and $104.5 million, respectively.
2 
Net income and Income attributable to common shareholders for the period of January 1 through September 12, 2016 includes reorganization items attributable to our bankruptcy proceedings of $1.145 billion.
3 
Excludes inducements paid for the conversion of preferred stock of $4.3 million in 2014.




26




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 Part II, 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 and rounding, 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 onshore exploration, development and production of crude oil, NGLs and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale field, or the Eagle Ford, in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash. In August 2016, we terminated our remaining operations in the Marcellus Shale in Pennsylvania and are currently in the process of remediating the sites of our former wells in that region.
As discussed in further detail in Note 5 to our Consolidated Financial Statements, we have adopted and applied Fresh Start Accounting as a result of our emergence from bankruptcy. Accordingly, our Consolidated Financial Statements and Notes after September 12, 2016 are not comparable to the Consolidated Financial Statements and Notes prior to that date. To facilitate our discussion and analysis of our financial condition and results of operations herein, we refer to the reorganized company as the “Successor” for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. Furthermore, our presentations herein include a “black line” division to delineate the lack of comparability between the Predecessor and Successor. In order to facilitate our discussion herein, we have addressed the Successor and Predecessor periods discretely and have provided comparative analysis, to the extent practical, where appropriate. In addition, and as referenced in Note 2 to the Consolidated Financial Statements, we have adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations and financial position for the Successor periods will be substantially different from our historic trends.
While crude oil prices have recovered somewhat from recent historic low levels of less than $30 per Bbl in February 2016 to approximately $55 per Bbl by the end of 2016, they remain depressed due to domestic and global supply and demand factors compared to the period of 2009 through 2014 when we initially began our expansion into the Eagle Ford. Similarly, the costs for drilling, completion and general oilfield products and services have declined as the industry experienced reduced demand for such products and services. While many of these costs remain at low levels, it is anticipated that certain costs, including those for drilling and completion services, will rise as industry drilling activity continues to recover and expand. Among other factors expected to drive this increase is the consolidation of certain service providers as financially weaker vendors were forced out of the market resulting in fewer choices for upstream producers.


27




The following table sets forth certain historical summary operating and financial statistics for the periods presented: 
 
Successor
 
 
Predecessor
 
September 13 Through
 
 
January 1 Through
 
 
 
 
 
December 31,
 
 
September 12,
 
Year Ended December 31,
 
2016
 
 
2016
 
2015
 
2014
Total production (MBOE)
1,040

 
 
3,346

 
7,923

 
7,934

Average daily production (BOEPD)
9,454

 
 
13,081

 
22,323

 
21,738

Crude oil production (MBbl)
711

 
 
2,311

 
4,923

 
4,644

Crude oil production as a percent of total
68
%
 
 
69
%
 
62
%
 
59
%
Product revenues
$
38,654

 
 
$
93,649

 
$
262,980

 
$
512,882

Crude oil revenues
$
33,157

 
 
$
81,377

 
$
220,596

 
$
420,286

Crude oil revenues as a percent of total
86
%
 
 
87
%
 
84
%
 
82
%
Realized prices:
 
 
 
 
 
 
 
 
Crude oil ($/Bbl)
$
46.63

 
 
$
35.21

 
$
44.81

 
$
90.50

NGL ($/Bbl)
$
16.51

 
 
$
11.38

 
$
12.24

 
$
31.14

Natural gas ($/Mcf)
$
2.81

 
 
$
2.06

 
$
2.62

 
$
4.44

Aggregate ($/BOE)
$
37.17

 
 
$
27.99

 
$
33.19

 
$
64.64

Production and lifting costs ($/BOE):
 
 
 
 
 
 
 
 
Lease operating
$
5.13

 
 
$
4.67

 
$
5.36

 
$
6.09

Gathering, processing and transportation
$
2.93

 
 
$
3.96

 
$
3.01

 
$
2.31

Production and ad valorem taxes ($/BOE)
$
2.40

 
 
$
1.04

 
$
2.06

 
$
3.53

General and administrative ($/BOE) 1
$
4.89

 
 
$
4.66

 
$
4.08

 
$
4.93

Depreciation, depletion and amortization ($/BOE)
$
11.20

 
 
$
10.04

 
$
42.22

 
$
37.85

Cash provided by operating activities
$
30,774

 
 
$
30,247

 
$
169,303

 
$
282,724

Cash paid for capital expenditures
$
4,812

 
 
$
15,359

 
$
364,844

 
$
774,139

Cash and cash equivalents at end of period
$
6,761

 
 
$
31,414

 
$
11,955

 
$
6,252

Debt outstanding, net of discount, at end of period
$
25,000

 
 
$
75,350

 
$
1,245,000

 
$
1,110,000

Credit available under credit facility at end of period 2
$
102,232

 
 
$
51,883

 
$

 
$
413,196

Proved reserves at the end of the period (MMBOE)
49

 
 
 
 
44

 
115

Net development wells drilled and completed

 
 
2.9

 
38.6

 
51.6

_____________________________________________
1 Excludes equity-classified share-based compensation, liability-classified share-based compensation and significant special charges, including strategic and financial advisory costs prior to our bankruptcy filing, among others as described in the discussion of “Results of Operations - General and Administrative Expenses,” of $6.98, $1.39 and $1.25 for the Predecessor period in 2016 and the years ended December 31, 2015 and 2014, respectively.
2 
As of December 31, 2015, we were unable to draw on our pre-petition credit facility, or RBL.
Key Developments
The following general business developments and corporate actions had or may have a significant impact on our results of operations, financial position and cash flows:
Bankruptcy Proceedings
On the Petition Date, we and the Chapter 11 Subsidiaries, filed voluntary petitions (In re Penn Virginia Corporation, et al, Case No. 16-32395) seeking relief under the Bankruptcy Code in the Bankruptcy Court. On the Confirmation Date, the Bankruptcy Court confirmed our Plan and we subsequently emerged from bankruptcy on the Effective Date.
Debtors-In-Possession. From the Petition Date through the Effective Date, we and the Chapter 11 Subsidiaries operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all “first day” motions filed by us and the Chapter 11 Subsidiaries, which were designed primarily to minimize the impact of the bankruptcy proceedings on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders.

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Pre-Petition Agreements. Immediately prior to the Petition Date, the holders, or the Ad Hoc Committee, of approximately 86 percent of the $1,075 million principal amount of the Senior Notes agreed to a restructuring support agreement, or the RSA, that set forth the general framework of the Plan and the timeline for the bankruptcy proceedings. In addition, we entered into the Backstop Commitment Agreement pursuant to which the Backstop Parties committed to provide a $50 million commitment to backstop the Rights Offering.
Plan of Reorganization. Pursuant to the terms of the Plan, which was supported by us, the holders of 100 percent of the claims attributable to our RBL, or the RBL Lenders, the Ad Hoc Committee and the Official Committee of Unsecured Claimholders, or the UCC, the following transactions were completed subsequent to the Confirmation Date and prior to or at the Effective Date:
the approximately $1,122 million of indebtedness, including accrued interest, attributable to our Senior Notes and certain other unsecured claims were exchanged for 6,069,074 shares representing 41 percent of the New Common Stock;
a total of $50 million of proceeds were received on the Effective Date from the Rights Offering resulting in the issuance of 7,633,588 shares representing 51 percent of New Common Stock to holders of claims arising under the Senior Notes, certain holders of general unsecured claims and to the Backstop Parties;
the Backstop Parties received a backstop fee comprised of 472,902 shares representing three percent of New Common Stock;
an additional 816,454 shares representing five percent of New Common Stock were authorized for disputed general unsecured claims and non-accredited investor holders of the Senior Notes and subsequently, 749,600 shares of New Common Stock were reserved for issuance under a new management incentive plan;
on the Effective Date, we entered into a shareholders agreement and a registration rights agreement and amended our articles of incorporation and bylaws for the authorization of the New Common Stock and to provide customary registration rights thereunder, among other corporate governance actions;
holders of claims arising under the RBL were paid in full from cash on hand, $75.4 million from borrowings under the Credit Facility (see below, the discussion of “Liquidity” that follows and Note 11 to the Consolidated Financial Statements) and proceeds from the Rights Offering;
the debtor-in-possession credit facility, or DIP Facility, under which there were no outstanding borrowings at any time from the Petition Date through the Effective Date, was canceled and less than $0.1 million in fees were paid in full in cash;
certain other priority claims were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditor claim-holders;
a cash reserve of $2.7 million was established for certain other secured, priority or convenience claims pending resolution as of the Effective Date;
an escrow account for professional service fees attributable to our advisers and those of the UCC was funded by us with cash of $14.6 million, and we paid $7.2 million for professional fees and expenses on behalf of the RBL Lenders, the Ad Hoc Committee and the indenture trustee for the Senior Notes;
on the Effective Date, our previous interim Chief Executive Officer, Edward B. Cloues, resigned and each member of our board of directors resigned and was replaced by new board members: Darin G. Holderness, CPA, Marc McCarthy and Harry Quarls and, in October 2016 by Jerry R. Schuyler;
our Predecessor preferred stock and common stock was canceled, extinguished and discharged; and
all of our Predecessor share-based compensation plans and supplemental employee retirement plan, or the SERP, entitlements were canceled.
While our emergence from bankruptcy is effectively complete, certain administrative and claims resolution activities will continue under the authority of the Bankruptcy Court until complete. As of March 10, 2017, certain claims, including secured tax and other priority, administrative and convenience claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of New Common Stock have been allocated, certain of these matters must be settled with cash payments. As of December 31, 2016, we had $3.9 million reserved for outstanding claims to be potentially settled in cash. This reserve is included as a component of accounts payable and accrued liabilities on our Consolidated Balance Sheet.
New Credit Facility
We entered into the Credit Facility on the Effective Date. The Credit Facility provides us with up to $200 million in borrowing commitments and the initial borrowing base under the Credit Facility is $128 million. Please read “Financial Condition - Capitalization: Revolving Credit Facility,” which follows.

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Production, Capital and Development Plans
Total production for the quarter and year ended December 31, 2016 (for the combined Predecessor and Successor periods) was 857 MBOE and 4,386 MBOE, or 9,316 BOEPD and 11,983 BOEPD, with 68 percent and 69 percent of production comprised of oil, 16 percent and 16 percent comprised of NGLs and 16 percent and 15 percent comprised on natural gas. For the year, 1,040 MBOE was attributable to the Successor and 3,346 MBOE was attributable to the Predecessor. Production from our Eagle Ford operations during the quarter and annual periods was 773 MBOE and 4,008 MBOE or 8,402 BOEPD and 10,951 BOEPD, 937 MBOE of which was attributable to the Successor and 3,071 MBOE of which was attributable to the Predecessor. Approximately 74 percent and 67 percent of our Eagle Ford production for the combined periods was from crude oil, 14 percent and 13 percent was from NGLs and 12 percent and 20 percent was from natural gas. Production from Eagle Ford operations was approximately 90 percent and 91 percent of total Company production during these combined periods and was derived from 302 operated and 32 outside-operated legacy wells.
We restarted our Eagle Ford drilling program in November 2016 by drilling the third well on the three-well Sable pad and have since drilled seven additional wells with six wells completed through March 10, 2017. The Sable wells were turned to sales in February 2017 and have been producing with 24-hour IP rates for the pad reaching 6,540 BOEPD (6,156 BOPD, or 94 percent oil). The 30-day IP rate for the Sable pad was 2,776 BOEPD (2,614 BOPD, or 94 percent oil). We recently completed the three-well Axis pad at the northern extent of our acreage, which generated a combined 24-hour IP rate of 6,341 BOEPD (5,908 BOPD, or 93 percent oil). The three-well Axis pad was turned to sales at the beginning of March 2017. We also recently finished drilling the four-well Kudu pad and are preparing to commence completion operations. Our first rig has moved to the Zebra pad to drill the first of three wells. Our second rig recently spudded the Lager 3H.
Capital expenditures for 2017 are expected to total between $120 and $140 million with approximately 90 percent of capital being directed to drilling and completions on our Eagle Ford assets. The capital plan provides for drilling 41 to 44 gross wells (19 to 22 net wells) with 31 to 34 gross wells (16 to 19 net wells) turned to sales. We plan to fund our 2017 capital expenditures with cash from operating activities and borrowings under the Credit Facility.
As of March 10, 2017, we had approximately 54,000 net core Eagle Ford acres largely held by production.
Amended Gathering and Transportation Agreements
In August 2016, the Bankruptcy Court approved a settlement with Republic Midstream and Republic Midstream Marketing, LLC, or Republic Marketing, and, together with Republic Midstream, Republic, and authorized the assumption of certain amended agreements with Republic, or the Amended Agreements. We paid Republic $0.3 million in connection with the settlement which is included in “Reorganization items, net” in our Consolidated Statements of Operations.
Under the terms of the Amended Agreements, Republic is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford, or Dedication Area, via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party. The amended gathering agreement reduced our minimum volume commitment from 15,000 to 8,000 barrels of oil per day. The term of the amended gathering agreement runs through 2041, with the term of the minimum volume commitment extended from 10 to 15 years.
Under the amended marketing agreement, we have a 10-year commitment to sell 8,000 barrels per day of crude oil to Republic, or any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline.
Cost Reduction Initiatives
We took significant measures in 2016 to significantly reduce our drilling, operating and support costs. In conjunction with our reorganization through bankruptcy, we renegotiated a number of contracts with vendors and service providers to bring costs in line with current market conditions.
Other initiatives include reductions in force and, at the corporate level, we have also undertaken significant staff reductions. In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In 2016, we reduced our total employee headcount by 53 employees. We paid a total of $2.1 million, including $1.4 million in severance and termination benefits and $0.7 million in retention bonuses during the year ended December 31, 2016.
Commodity Hedging Program
Shortly after the Petition Date, we hedged a substantial portion of our future crude oil production through the end of 2019 in accordance with the Plan. Our weighted-average hedge prices are approximately $48.62 per barrel for 2017, $49.12 per barrel for 2018 and $49.90 per barrel for 2019. We are currently unhedged with respect to natural gas production.
Stock Listing
In connection with our reorganization and emergence from bankruptcy, all of our Predecessor common stock that formally traded under the symbol “PVA,” was canceled, extinguished and discharged. On November 15, 2016, our New Common Stock was listed on the OTCQX U.S. Premier market under the symbol “PVAC.” Prior to such time, there was no established trading market for the New Common Stock. On December 28, 2016, the New Common Stock was listed and began trading on the Nasdaq under the symbol “PVAC.”

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Financial Condition
Liquidity
Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. The Credit Facility provides us with up to $200 million in borrowing commitments. The initial borrowing base under the Credit Facility is $128 million. As of March 10, 2016, we had outstanding borrowings and letters of credit of $30 million $0.8 million, respectively, resulting in $97.2 million of availability under the Credit Facility .
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. The level of our hedging activity and duration of the instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.
In order to mitigate this volatility, we entered into a series of new derivatives contracts in May 2016 and hedged a substantial portion of our future crude oil production through the end of 2019. Our weighted-average hedge prices are $48.62 per barrel for 2017, $49.12 per barrel for 2018 and $49.90 per barrel for 2019. Our natural gas hedges expired in 2015 and we currently are and expect to remain unhedged with respect to natural gas as well as NGL production.
Capital Resources
Under our business plan for 2017, we currently anticipate capital expenditures to total between $120 million and $140 million with approximately 90 percent of capital being directed to drilling and completions on our Eagle Ford acreage. We plan to fund our 2017 capital spending with cash from operating activities and borrowings under the Credit Facility. Based upon current price and production expectations for 2017, we believe that our cash from operating activities and borrowings under our Credit Facility will be sufficient to fund our operations through year-end 2017; however, future cash flows are subject to a number of variables and significant additional capital expenditures may be required to more fully develop our properties. Our 2017 capital expenditure budget does not allocate any funds for acquisitions. For a detailed analysis of our historical capital expenditures, see the “Cash Flows” discussion that follows.
Cash on Hand and Cash From Operating Activities. As of March 10, 2017, we had approximately $6 million of cash on hand. For additional information and an analysis of our historical cash from operating activities, see the “Cash Flows” discussion that follows. In addition and as discussed further above, we have actively managed our exposure to commodity price fluctuations, which impacts our cash from operating activities, by hedging the commodity price risk for a portion of our expected production.
Credit Facility Borrowings. We initially borrowed $75.4 million under the Credit Facility on the Effective Date. Since that time we have paid down $45.4 million, net of new borrowings through March 10, 2017. For additional information regarding the terms and covenants under the Credit Facility, see the “Capitalization” discussion that follows.
The following table summarizes our borrowing activity under the Credit Facility for the periods presented:
 
Borrowings Outstanding
 
 
 
Weighted-
Average
 
Maximum
 
Weighted-
Average Rate
Successor period for the three months ended December 31, 2016
$
39,335

 
$
54,350

 
3.7430
%
Successor period from September 12, 2016 to December 31, 2016
$
44,616

 
$
75,350

 
3.8940
%
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. For additional information and an analysis of our historical proceeds from sales of assets, see the “Cash Flows” discussion that follows.
Capital Market Transactions. From time-to-time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities.

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Cash Flows
The following table summarizes our cash flows for the periods presented:
 
Successor
 
 
Predecessor
 
September 13
 
 
January 1
 
 
 
Through
 
 
Through
 
Year Ended
 
December 31,
 
 
September 12,
 
December 31,
 
2016
 
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
 


Operating cash flows, net of working capital changes
$
31,068

 
 
$
34,731

 
$
130,293

Commodity derivative settlements received, net:
 
 
 
 
 
 
Crude oil
384

 
 
48,008

 
137,488

Natural gas

 
 

 
681

Interest payments, net of amounts capitalized
(598
)
 
 
(4,148
)
 
(86,226
)
Income taxes received, net
7

 
 
35

 
714

Drilling rig termination costs paid

 
 

 
(6,636
)
Strategic, financial and bankruptcy-related advisory fees and costs paid
(648
)
 
 
(46,606
)
 
(3,693
)
Return of remaining professional fee escrow
756

 
 

 

Restructuring and exit costs paid
(195
)
 
 
(1,773
)
 
(3,318
)
Net cash provided by operating activities
30,774

 
 
30,247

 
169,303

Cash flows from investing activities
 

 
 
 

 
 

Capital expenditures
(4,812
)
 
 
(15,359
)
 
(364,844
)
Proceeds from sales of assets, net

 
 
224

 
85,189

Other, net
(104
)
 
 
1,186

 

Net cash used in investing activities
(4,916
)
 
 
(13,949
)
 
(279,655
)
Cash flows from financing activities
 

 
 
 

 
 

(Repayments) proceeds from credit facility borrowings, net
(50,350
)
 
 
(43,771
)
 
135,000

Debt issuance costs paid

 
 
(3,011
)
 
(744
)
Proceeds from rights offering, net

 
 
49,943

 

Dividends paid on preferred stock

 
 

 
(18,201
)
Other, net
(161
)
 
 

 

Net cash (used in) provided by financing activities
(50,511
)
 
 
3,161

 
116,055

Net (decrease) increase in cash and cash equivalents
$
(24,653
)
 
 
$
19,459

 
$
5,703

Cash Flows From Operating Activities. The Successor period, which represents the period from September 13, 2016 through December 31, 2016, included ordinary course cash receipts and disbursements for product revenues and joint venture billing collections, net of payments for royalties, lease operating expenses, gathering, processing and transportation expenses, severance taxes and general and administrative expenses. We also received net derivative proceeds for three months, as well as the return of remaining funds, after allowed payments were disbursed to various professional firms, from the professional fee escrow that was established on the Effective Date. The Successor period includes interest payments, net of amounts capitalized, on the Credit Facility, payments for bankruptcy-related professional and advisory fees paid directly by us exclusive of the professional fee escrow and severance, termination and other retention bonuses paid to employees after the Effective Date.
The Predecessor period during 2016 represents January 1 through September 12, 2016 as compared to a full calendar year in 2015. Aggregate average commodity prices declined during the Predecessor period in 2016 compared to the Predecessor period in 2015. In addition, production declined due primarily to: (i) the shorter time period in the 2016 period, (ii) the suspension of our Eagle Ford drilling program in February 2016, (iii) natural production declines and (iv) the sale of our East Texas assets in August 2015 and certain other properties in the Eagle Ford and Mid-Continent regions in October 2015. The combined effect of these factors contributed to the substantial reduction in the realized cash receipts in the Predecessor period ended September 12, 2016 when compared to 2015. During the 2016 Predecessor period, we incurred and paid substantially higher professional fees and other costs associated with our consideration of strategic financing alternatives and our bankruptcy proceedings. In addition, we received lower settlements from derivatives during the 2016 period due primarily to: (i) lower spreads between hedged and realized prices on our post-petition derivatives through the Effective Date, (ii) lower overall crude oil volumes hedged, (iii) the early termination in 2016 of our entire pre-petition portfolio of derivative contracts, most of the proceeds from which were provided directly to the RBL lenders to pay down borrowings under the RBL, and (iv)

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the expiration of our natural gas hedges in 2015. This overall decline in operating cash flows was partially offset by: (i) the suspension of interest payments on the Senior Notes in connection with the bankruptcy proceedings, (ii) higher working capital utilization during 2015 as we paid down a substantial level of accounts payable and accrued expenses in 2015, (iii) higher payments in 2015 for the release of operated drilling rigs and (iv) required prepayments for certain oilfield services in 2015 due to the deterioration in our credit standing at that time.
Cash Flows From Investing Activities. As illustrated in the tables below, our cash payments for capital expenditures were substantially lower during the 2016 Successor and Predecessor periods compared to 2015 due primarily to the suspension of our capital program in February 2016. The drilling program was not resumed until November of 2016 in the Successor period. Furthermore, the 2016 Predecessor period includes substantially lower settlements of accrued capital charges from the prior year-end period.
The following table sets forth costs related to our capital expenditure program for the periods presented:
 
Successor
 
 
Predecessor
 
September 13
 
 
January 1
 
 
 
Through
 
 
Through
 
Year Ended
 
December 31,
 
 
September 12,
 
December 31,
 
2016
 
 
2016
 
2015
Oil and gas:
 
 
 
 
 
 

Drilling and completion
$
4,839

 
 
$
3,696

 
$
284,225

Lease acquisitions and other land-related costs
93

 
 
58

 
16,052

Geological and geophysical (seismic) costs
567

 
 
(16
)
 
828

Pipeline, gathering facilities and other equipment
(46
)
 
 
375

 
3,884

 
5,453

 
 
4,113

 
304,989

Other – Corporate

 
 

 
562

Total capital program costs
$
5,453

 
 
$
4,113

 
$
305,551

The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures as reported in our Consolidated Statements of Cash Flows for the periods presented:
 
Successor
 
 
Predecessor
 
September 13
 
 
January 1
 
 
 
Through
 
 
Through
 
Year Ended
 
December 31,
 
 
September 12,
 
December 31,
 
2016
 
 
2016
 
2015
Total capital program costs
$
5,453