UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________
 FORM 10-K
________________________________________________________
ý    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
 For the fiscal year ended December 31, 2017
or
¨    TRANSITION REPORT PUSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
 For the transition period from ____ to ____
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 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 Securities Exchange Act of 1934 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 (§ 232.405 of this chapter) 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 (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of 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, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company”in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer
o
 
Accelerated filer
ý

 
Non-accelerated filer
o
 
Smaller reporting company
o
 
 
 
 
 
 
 
 
 
Emerging growth company
o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  ý
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was $476,690,130 as of June 30, 2017 (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 NASDAQ Global Select Market. 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 February 23, 2018, 15,042,764 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 2, 2018, 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, 2017
 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 Stockholder Matters and Issuer Purchases of Equity Securities
6.
Selected Financial Data
7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations:
 
 
Overview and Executive Summary
 
Key Developments
 
Financial Condition
 
Results of Operations
 
Off-Balance Sheet Arrangements
 
Contractual Obligations
 
Critical Accounting Estimates
7A.
Quantitative and Qualitative Disclosures About Market Risk
 
8.
Financial Statements and Supplementary Data
9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9A.
Controls and Procedures
9B.
Other Information
Part III
 
 
 
10.
Directors, Executive Officers and Corporate Governance
11.
Executive Compensation
12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
13.
Certain Relationships and Related Transactions, and Director Independence
14.
Principal Accountant Fees and Services
Part IV
 
 
 
15.
Exhibits, Financial Statement Schedules
16.
Form 10-K Summary
 
 
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. We use words such as “anticipate,” “guidance,” “assumptions,” “projects,” “estimates,” “expects,” “continues,” “intends,” “plans,” “believes,” “forecasts,” “future,” “potential,” “may,” “possible,” “could” and variations of such words or similar expressions to identify forward-looking statements. 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: 

risks related to recently completed acquisitions, including our ability to realize their expected benefits;
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;
plans, objectives, expectations and intentions contained in this report that are not historical;
our ability to execute our business plan in volatile and depressed commodity price environments;
the 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, NGLs 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;
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;
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;
potential adverse effects of the completed Chapter 11, or bankruptcy, proceedings on our liquidity, results of operations, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from bankruptcy;
our post-bankruptcy capital structure and the adoption of Fresh Start Accounting (as defined herein), 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;
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;
the impact and costs associated with litigation or other legal matters; and
other factors set forth in our periodic filings with the Securities and Exchange Commission, or SEC, including the risks set forth in Part I, Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2017.
Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. 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.
EBITDAX. A measure of profitability utilized in the oil and gas industry representing earnings before interest, income taxes, depreciation, depletion, amortization and exploration expenses. EBITDAX is not a defined term or measure in generally accepted accounting principles, or GAAP (see below).
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.
LLS. Light Louisiana Sweet, a crude oil pricing index reference.
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.

2



NYMEX. New York Mercantile 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.
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 percent 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 percent 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. Under appropriate circumstances, undeveloped acreage may not be subject to expiration if properly held by production, as that term is defined above.
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.
We were incorporated in the Commonwealth of Virginia in 1882. Our common stock is publicly traded 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.
Current Operations
We lease a highly contiguous position of approximately 73,400 net acres (as of December 31, 2017) in the core liquids-rich area or “volatile oil window” of the Eagle Ford in Gonzales, Lavaca, Fayette and Dewitt Counties in Texas, which we believe contains a substantial number of drilling locations that will support a multi-year drilling inventory.
In 2017, our total production was comprised of 73 percent crude oil, 14 percent NGLs and 13 percent natural gas. Crude oil accounted for 88 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, 2017, our total proved reserves were approximately 73 MMBOE, of which 44 percent were proved developed reserves and 77 percent were crude oil. Approximately 97 percent of our reserves were located in South Texas and 42 percent were proved developed reserves. As of December 31, 2017, we had 500 gross (332.9 net) productive wells, approximately 80 percent of which we operate, and owned approximately 124,000 gross (90,000 net) acres of leasehold and royalty interests, approximately 18 percent of which were undeveloped. Over 90 percent of our undeveloped acreage in South Texas is HBP and includes a substantial number of undrilled locations. During 2017, we drilled and completed 29 gross (16.9 net) wells, all in the Eagle Ford. For a more detailed discussion of our production, reserves, drilling activities, wells and acreage, see Part I, Item 2, “Properties.”
In September 2017, we completed an acquisition of oil and gas assets, including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas from Devon Energy Corporation, or Devon. On March 1, 2018, we completed the acquisition of certain oil and gas assets from Hunt Oil Company, or Hunt, including oil and gas leases covering approximately 9,700 net acres located primarily in Gonzalez and Lavaca Counties, Texas. With such acquisitions, we have an approximate 83,100 core net acreage position in South Texas with approximately 93 percent HBP, substantially all of which is operated by us. For a more detailed discussion of these acquisitions, see “Key Developments” included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 5 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
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 Emergence Date.
On the Emergence 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 our bankruptcy proceedings, our emergence from bankruptcy and Fresh Start Accounting, see Note 4 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”

4



Business Strategy
Our goal is to enhance long-term shareholder value. We intend to pursue the following business strategies:
Grow reserves, production and cash flow by exploiting our liquids rich resource base. We believe our extensive inventory of drilling locations in the Eagle Ford, combined with our operating expertise, will enable us to continue to deliver accretive production, reserves and cash flow growth and create shareholder value. We intend to selectively develop our acreage base in an effort to maximize its value and resource potential. We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs will allow us to efficiently develop our core area and to allocate capital to maximize the value of our resource base.
Operate our properties as a low-cost producer. We believe our concentrated acreage position in the Eagle Ford and our experience as an operator of virtually all of our properties following completion of our recent oil and gas asset acquisitions enables us to apply optimized drilling and completion techniques, reduce operating costs and achieve economies of scale that will improve returns on capital investments. Operating control allows us to better manage timing and risk as well as the cost of infrastructure, drilling and ongoing operations. We generally drill multiple wells from a single pad, which reduces facilities costs and surface impact while also reducing unit costs and improving cycle time.
Utilize extensive acquisition and technical expertise to strategically grow our core acreage position. We continuously evaluate resource development opportunities. To date, our management and technical teams have completed numerous acquisitions, and we expect to continue to identify and opportunistically lease or acquire additional acreage and producing assets to add to our multi-year drilling inventory.
Maintain financial discipline. We intend to maintain a conservative financial position to allow us to develop our drilling, exploitation and exploration activities. Consistent with our disciplined approach to financial management, we have an active commodity hedging program that seeks to hedge a meaningful portion of our expected oil production, reducing our exposure to downside commodity price fluctuations and enabling us to protect cash flows and maintain liquidity to fund our capital program and investment opportunities. We plan to hedge a substantial portion of our anticipated crude oil production for 2018 and will expand additional hedging for the next several years on an opportunistic basis.
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 that provide us with 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 us with gas lift, gathering, compression and transportation services for a substantial portion of our natural gas production in the South Texas region until 2039.
Natural gas processing contracts. We have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas, encompassing our entire operating regions in South Texas and the Mid-Continent. We have two agreements attributable to the South Texas region that are evergreen in term with either party having the right to terminate with 30-days notice to the counterparty. We also have an agreement in place for the Mid-Continent region that extends through November 2019.
Drilling and Completion. From time to time we enter into drilling, completion and materials contracts in the ordinary course of business to ensure availability of rigs, frac crews and materials to satisfy our development program. As of December 31, 2017, there were no drilling, completion or materials agreements with terms that extended beyond one year.
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, 2017, approximately 86 percent of our consolidated product revenues were attributable to three customers: Phillips 66 Company; BP Products North America Inc. and Shell Trading (US) Company.
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 crude 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.

5



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, frac fleets, sand and other equipment and materials necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Such materials, 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 and regulations that govern oil and gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. These laws, rules and regulations may, among other things:
require the acquisition of various permits before drilling commences;
require notice to stakeholders of proposed and ongoing operations;
require the installation of expensive pollution control equipment;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
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. Violations and liabilities with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and cash flows. In certain instances, citizens or citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws or to challenge our ability to receive environmental permits that we need to operate. 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, 2017, we have recorded asset retirement obligations of $3.3 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. Federal, state or local administrative decisions, developments in the federal or state court systems or other governmental or judicial actions may influence the interpretation or enforcement of environmental laws and regulations and may thereby increase compliance costs. Environmental regulations have historically become more stringent over time, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation.

6



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. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. 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. States also have environmental cleanup laws analogous to CERCLA, including Texas.
RCRA. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup 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. For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production-related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have an adverse effect on our results of operations and financial position. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes if such wastes have hazardous characteristics.
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 imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs, and certain other damages arising from a spill. As such, a violation of the OPA has the potential to adversely affect our business, financial condition, results of operations and cash flows.
Clean Water Act. The Federal Water Pollution Control Act, or the Clean Water Act, and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into regulated waters, such as waters of the United States. The discharge of pollutants, including dredge or fill materials in regulated wetlands, into regulated waters or wetlands without a permit issued by the EPA, the U.S. 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. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate courts. In January 2018, the Supreme Court ruled that district courts have jurisdiction over challenges to the rule. Litigation surrounding this rule is ongoing, and EPA has instituted rulemakings to both delay the effective date of this rule and repeal the rule.
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. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

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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. The Underground Injection Well Program requires that we obtain permits from the EPA or delegated state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages, and personal injuries. 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 commercially feasible without the use of hydraulic fracturing.
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 has 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. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.
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

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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. In June 2017, the EPA proposed a two year stay of the fugitive emissions monitoring requirements, pneumatic pump standards and closed vent system certification requirements in the 2016 NSPS rule for the oil and gas industry while it reconsiders these aspects of the rule. The proposal is still under consideration. The U.S. Bureau of Land Management, or BLM, finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. The BLM adopted final rules in January 2017; operators generally had one year from the January 2017 effective date of the rule to come into compliance with the rule’s requirements. However, in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, pending administrate review of the rule. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA had 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 would 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 with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.
Greenhouse Gas Emissions. In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases,” or GHGs, present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources.
Both in the United States and worldwide, there is increasing attention being paid to the issue of climate change and the contributing effect of 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. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
On August 3, 2015, the EPA also issued new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this rule, nationwide carbon dioxide emissions would be reduced by approximately 30 percent from 2005 levels by 2030 with a flexible interim goal. Several industry groups and states challenged the rule. On February 9, 2016, the U.S. Supreme Court stayed the implementation of this rule pending judicial review. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations. The EPA’s proposal will be subject to public comment and likely legal challenge, and as such we cannot predict at this time what impact the rulemaking will have on the demand for oil and natural gas production and our operations.

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The EPA also 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. Many states have established GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. 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. 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.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the U.S. Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment of the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of some of our oil and natural gas projects.
Employees and Labor Relations
We had a total of 80 employees as of December 31, 2017. We hire independent contractors on an as needed basis. We consider our current employee relations to be favorable. We and our employees are not subject to any collective bargaining agreements.

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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 Reports 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. The information contained on, or connected to, our website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we furnish or file with the SEC. We intend for our website to serve as a means of public dissemination of information for purposes of Regulation FD.
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.
Prices for crude oil, NGLs and natural gas 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;
political and economic events that directly or indirectly impact the relative strength or weakness of the United States dollar, on which crude oil prices are benchmarked globally, against foreign currencies;
risks related to the concentration of our operations in the Eagle Ford Shale field in South Texas;
speculation by investors in oil and gas;
the availability, proximity and capacity of gathering, processing, refining and transportation facilities;
the cost and availability of products and personnel needed for us to produce oil and natural gas;
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.
Exploration and development drilling are high-risk activities with many uncertainties and may not result in commercially productive reserves.
Our future financial condition and results of operations depend on the success of our exploration and production activities. Oil and gas drilling and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil or natural gas production. 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;
the use of multi-well pad drilling that requires the drilling of all of the wells on a pad until any one of the pad’s wells can be brought into production;
reductions in oil, natural gas and NGL prices;
elevated pressure or irregularities in geologic formations;

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loss of title or other title related issues;
equipment failures or accidents;
costs, shortages or delays in the availability of drilling rigs, crews, equipment and materials;
shortages in experienced labor;
crude oil, NGLs or natural gas gathering, transportation and processing availability
restrictions or limitations;
surface access restrictions;
delays imposed by or resulting from compliance with regulatory requirements, including any hydraulic fracturing regulations and other applicable regulations, and the failure to secure or delays in securing necessary regulatory approvals and permits;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
limited availability of financing at acceptable terms;
limitations in the market for crude oil, natural gas and NGLs;
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, materials (including sand) and other equipment and related services. The availability of drilling rigs, frac crews, materials (including sand) 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. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. 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. Furthermore, the cost of drilling, completing, equipping and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economical than forecasted. 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 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 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 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 wells within such project area.

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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. Shortages of drilling rigs, frac crews, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, 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.
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.
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.
The ability to attract and retain key personnel is critical to the success of our business and may be challenging.
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of the volatility of our business. 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 2017, approximately 86 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.

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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 percent 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, and undeveloped reserves may not ultimately be converted into proved producing reserves.
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 relating to crude oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent on many variables and, therefore, changes often occur as these variables evolve and commodity prices fluctuate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the estimated quantities and present value of our reserves.
Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil, NGL and natural gas prices and other factors, many of which are beyond our control.
At December 31, 2017, approximately 56 percent of our estimated proved reserves were proved undeveloped, compared to 47 percent at December 31, 2016. 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. Our reserve data assumes that we can and will make these significant expenditures to develop our reserves and conduct these drilling operations successfully. These assumptions, however, may not prove correct, and our estimated costs may not be accurate, development may not occur as scheduled and actual results may not occur as estimated.
The reserve estimation standards under SEC rules 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. Accordingly, our reserve report at December 31, 2017 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $663 million. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write-off these reserves. During the year ended December 31, 2017, we wrote-off 4.7 MMBOE of proved undeveloped reserves because they are no longer expected to be developed within five years of their initial recording. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our securities.
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

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decrease by 10%, our standardized measure and PV-10 would have decreased to approximately $443 million and $457 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 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 inability to recover the carrying value of our investments, it does not impact our cash flows from operating activities.
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.
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. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms. 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.

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Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.
Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.
Our initial technical reviews of properties we acquire are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well and environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with acquired properties, and such risks and liabilities could have a material adverse effect on its results of operations and financial condition.
We may incur losses as a result of title deficiencies.
We purchase working and revenue interests in the oil and gas leasehold interests upon which we will perform our exploration activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, in all instances, we forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. Even then, the cost of performing detailed title work can be expensive. We may choose to forgo detailed title examination by title lawyers on a portion of the mineral leases that we place in a drilling unit or conduct less title work than we have traditionally performed. As is customary in our industry, we generally rely upon the judgment of oil and gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. We, in some cases, perform curative work to correct deficiencies in the marketability or adequacy of the title to us. The work might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, the amount paid for affected oil and gas leases can be generally lost and the target area can become undrillable. The failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. Our industry is highly competitive and we may not be able to compete effectively.
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, greater access to capital, 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.
Over 90 percent of our production, revenues and capital expenditures for 2017 were attributable to the Eagle Ford Shale in South Texas, making us vulnerable to risks associated with operating in one geographic area. 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 regional supply and demand factors, 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,

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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. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash flows.
We emerged from bankruptcy in September 2016, which could adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our 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 obtain credit and raise capital on terms acceptable to us or at all;
our ability to attract and retain customers may be negatively impacted;
risks related to 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.
Upon our emergence from bankruptcy, we adopted Fresh Start Accounting and the full cost method of accounting for oil and gas properties. Accordingly, our financial condition and results of operations after September 2016 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 Emergence 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, 4 and 8 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”
We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.
We had $277 million of outstanding debt at December 31, 2017, including $77 million under the Credit Agreement as amended, or the Credit Facility, and $200 million, excluding unamortized discount and issuance costs, under the $200 million Second Lien Credit Agreement, or the Second Lien Facility.
As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, which will reduce the amount we will have available to fund our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business. We may incur substantially more debt in the future.
Any increase in our level of indebtedness could have adverse effects on our financial condition and results of operations, including imposing additional cash requirements on us in order to support interest payments, increasing our vulnerability to adverse changes in general economic and industry conditions and limiting our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes.
The borrowing base under our credit facility may be reduced in the future if commodity prices decline.
The borrowing base under the Credit Facility, was $237.5 million as of December 31, 2017 and $340 million as of March 1, 2018. Our borrowing base is redetermined at least twice each year and is scheduled to next be redetermined in October 2018. 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.

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The Credit Facility and the Second Lien Facility have restrictive covenants that could limit our financial flexibility.
The Credit Facility and Second Lien Facility contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under the Credit Facility is subject to compliance with certain financial covenants, including leverage, interest coverage and current ratios.
The Credit Facility and the Second Lien Facility include 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 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, financial condition or cash flows. 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 or other environmental, health or safety impacts, 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. No assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities or result in a material increase in the costs of production, development, exploration or processing operations. 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.

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Any of these risks could result in substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. In addition, under certain circumstances, we may be liable for environmental damage caused by previous owners or operators of properties that we own, lease or operate. As a result, we may incur substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.
If we experience any problems with well stimulation and completion activities, such as hydraulic fracturing, our ability to explore for and produce oil or natural gas may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations as a result of:
delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements, which may include limitations on hydraulic fracturing or the discharge of GHGs;
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.”
Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.

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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 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 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.
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 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 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 achieve more predictable cash flows and 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 commodity 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 counterparty to a derivatives instrument fails to perform under the contract; or
a sudden, unexpected event materially impacts commodity prices.
In addition, we may enter into derivative instruments that 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.

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The adoption of derivatives legislation and implementing rules could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC, to promulgate rules and regulations implementing the Dodd-Frank Act. While some of these rules have been finalized, some have not been finalized. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; however, this initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has subsequently issued proposals for new rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions, though these rules have not been finalized.
While the CFTC has designated certain interest rate swaps and credit default swaps subject to mandatory clearing, the CFTC has not yet proposed rules subjecting any other classes of swaps, including physical commodity swaps, to mandatory clearing. The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted.
When fully implemented, the Dodd-Frank Act and any new regulations could increase the operational and transactional cost of derivatives contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize and restructure our existing derivatives contracts and affect the number and/or creditworthiness of available counterparties. If we reduces our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
In addition, we may transact with counterparties based in the European Union, Canada or other jurisdictions which, like the U.S., are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and impose operational and transactional costs on our derivatives activities.
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. As disclosed in Note 11 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,” we have substantial NOL carryforwards. 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 percent shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than 50 percent 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, 2017, 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. In addition, due to the recently enacted budget reconciliation act commonly referred to as the Tax Cut and Jobs Act, or TCJA, U.S. NOLs generated on or after January 1, 2018 could be limited to 80 percent of taxable income.
Recently enacted legislation will affect our tax position, and one day, certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated. Additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.
In December 2017, Congress enacted the TCJA. The law made significant changes to U.S. federal income tax laws, including reducing the corporate income tax rate to 21%, repeal of the corporate alternative minimum tax, or AMT, partially limiting the deductibility of interest expense and NOLs, eliminating the deduction for certain U.S. production activities, and allowing the immediate deduction of certain new investments in lieu of depreciation expense over time. Most of these new laws go into effect for tax years beginning after December 31, 2017. We are still evaluating the impact generated after December 31, 2017 of the TCJA to us. Notwithstanding the reduction in the corporate income tax rate and repeal of the corporate AMT, we cannot yet conclude that the overall impact of the TCJA to us is positive. The TCJA could adversely affect our business, operating results, financial condition and cash flows, as well as the value of an investment in our common stock.
In recent years, lawmakers and Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to: (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these changes were not included in the TCJA, it is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes are ever made, as well as any similar changes in state law, it could eliminate or postpone

21



certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition, results of operations and cash flows.
Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our crude oil, NGLs and natural gas.
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 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, results of operations and cash flows 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.
Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows.
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.
The market price of our common stock is subject to volatility.
The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading of our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our relatively 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, by significant shareholders, officers or directors could materially and adversely affect the market price of our common stock.

22



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.
Because we have no plans to pay dividends on or repurchase our common stock, investors must look solely to stock appreciation for a return on their investment in us.
We do not anticipate paying any cash dividends on or repurchasing our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends or repurchase of our common stock will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions and other considerations that our board of directors deems relevant. Covenants contained in the Credit Facility and the Second Lien Facility restrict the payment of dividends and share repurchases. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.
Item 1B
Unresolved Staff Comments
None.
Item 2
 Properties
As of December 31, 2017, our primary oil and gas assets were located in Gonzales, Lavaca, Fayette and Dewitt 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.

23



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
2017 (Successor)
 

 
 
 
 

 
 

 
 

 
 

Developed
 
 
 
 
 
 

 
 
 
 
Producing
22.4

 
4.9

 
27.2

 
31.8

 
 
 
 
Non-producing

 

 

 

 
 
 
 
 
22.4

 
4.9

 
27.2

 
31.8

 
 
 
 
Undeveloped
33.4

 
4.0

 
20.1

 
40.8

 
 
 
 
 
55.8

 
8.9

 
47.3

 
72.6

 
$
590.5

 
$
609.0

 
 
 
 
 
 
 
 
 
 
 
 
Price measurement used 2
$51.34/Bbl

 
$18.48/Bbl

 
$2.98/MMBtu

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
_____________________________________________
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 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 - $50.06, $40.97 and $45.78 each per Bbl, NGLs - $18.02, $11.82 and $13.15 each per Bbl and natural gas - $2.89, $2.40 and $2.59 each per MMBtu, for December 31, 2017, 2016 and 2015, 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, 2017:
 
 
Proved
 
% of Total
Proved
 
% Proved
Region
 
Reserves
 
Reserves
 
Developed
 
 
(MMBOE)
 
 

 
 

South Texas
 
70.2

 
97
%
 
42
%
Mid-Continent
 
2.4

 
3
%
 
100
%
 
 
72.6

 
100
%
 
44
%
A discussion and analysis of the changes in our total proved reserves is provided in “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” included in Part II, Item 8, “Financial Statements and Supplementary Data.”

24



Proved Undeveloped Reserves
The proved undeveloped reserves included in our reserve estimates relate to wells that are forecasted to be drilled within the next five years. The following 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, 2017:
 
Crude Oil
 
NGLs
 
Natural Gas
 
Oil Equivalents
 
(MMBbl)
 
(MMBbl)
 
(Bcf)
 
(MMBOE)
Proved undeveloped reserves at beginning of year
18.9

 
2.4

 
11.8

 
23.3

Revisions of previous estimates
(4.2
)
 
(1.0
)
 
(4.4
)
 
(5.9
)
Extensions and discoveries
22.3

 
3.0

 
15.0

 
27.7

Purchase of reserves
0.3

 
0.1

 
0.1

 
0.5

Conversion to proved developed reserves
(3.9
)
 
(0.5
)
 
(2.4
)
 
(4.8
)
Proved undeveloped reserves at end of year
33.4

 
4.0

 
20.1

 
40.8

In 2017, our proved undeveloped reserves increased by 17.5 MMBOE. We experienced negative revisions of 5.9 MMBOE including: (i) 4.7 MMBOE due to the loss of certain locations resulting from changes in the timing and drilling locations attributable to our development plans and (ii) 1.3 MMBOE due to reduced treatable lateral lengths in certain locations due primarily to reconfiguration of the planned drilling units partially offset by 0.1 MMBOE of other changes. Extensions and discoveries of 27.7 MMBOE are entirely attributable to our expanded development plan for the Eagle Ford including adding a third rig to our drilling program and the corresponding increase in the number of new drilling locations that we are planning to drill in the next five years. We acquired 0.5 MMBOE, as measured on the closing date of the transaction, in connection with the Devon Acquisition. In addition, we converted 4.8 MMBOE from proved undeveloped to proved developed reserves in the Eagle Ford. During 2017, we incurred capital expenditures of $74.9 million attributable to 25 gross (14.2 net) wells in connection with the conversion of proved undeveloped reserves to proved developed reserves. While we resumed our drilling program in November 2016, we did not turn any new wells to sales until February 2017 and we operated with only two rigs and limited completion service through the first half of 2017. Accordingly, our conversion rate for proved undeveloped reserves is anticipated to accelerate modestly from the actual rate achieved for 2017.
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 “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, 2018, 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, 2017 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, Engineering is primarily responsible for overseeing the preparation of the reserve estimate by DeGolyer and MacNaughton, Inc. Our Vice President, 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.

25



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, which were sold in 2015 as “Divested properties.” The sale of those operations represented a complete divestiture 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 and the Granite Wash in Oklahoma.
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
 
 
Year Ended
 
September 13 Through
 
 
January 1 Through
 
Year Ended
 
 
December 31,
 
December 31,
 
 
September 12
 
December 31,
Region
 
2017
 
2016
 
 
2016
 
2015
 
 
(MBOE) 
 
 
(MBOE) 
South Texas
 
3,487

 
937

 
 
3,071

 
6,903

Mid-Continent and other 1
 
292

 
103

 
 
276

 
460

Divested properties 2
 

 

 
 

 
560

 
 
3,779

 
1,040

 
 
3,346

 
7,923

 
 
 
 
 
 
 
 
 
 
 
 
Average Daily Production
 
 
Successor
 
 
Predecessor
 
 
Year Ended
 
September 13 Through
 
 
January 1 Through
 
Year Ended
 
 
December 31,
 
December 31,
 
 
September 12
 
December 31,
Region
 
2017
 
2016
 
 
2016
 
2015
 
 
(BOEPD) 
 
 
(BOEPD) 
South Texas
 
9,553

 
8,518

 
 
11,996

 
18,913

Mid-Continent and other 1
 
800

 
936

 
 
1,085

 
1,260

Divested properties 2
 

 

 
 

 
2,150

 
 
10,353

 
9,454

 
 
13,081

 
22,323

_____________________________________________
1 Includes total production and average daily production of approximately 10 MBOE (48 BOEPD) and 22 MBOE (60 BOEPD) for 2016 and 2015, respectively, attributable to our then 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 (1,806 BOEPD) in 2015. 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 (344 BOEPD) in 2015.
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
 
 
Year Ended
 
September 13 Through
 
 
January 1 Through
 
Year Ended
 
 
December 31,
 
December 31,
 
 
September 12
 
December 31,
 
 
2017
 
2016
 
 
2016
 
2015
Average prices:
 
 
 
 
 
 
 
 
 
Crude oil ($ per Bbl)
 
$
50.96

 
$
46.63

 
 
$
35.21

 
$
44.81

NGLs ($ per Bbl)
 
$
19.25

 
$
16.51

 
 
$
11.38

 
$
12.24

Natural gas ($ per Mcf)
 
$
2.89

 
$
2.81

 
 
$
2.06

 
$
2.62

Aggregate ($ per BOE)
 
$
42.20

 
$
37.17

 
 
$
27.99

 
$
33.19

Average production and lifting cost ($ per BOE):
 
 
 
 
 
 
 
 
 
Lease operating
 
$
5.76

 
$
5.13

 
 
$
4.67

 
$
5.36

Gathering processing and transportation
 
2.84

 
2.93

 
 
3.96

 
3.01

 
 
$
8.60

 
$
8.06

 
 
$
8.63

 
$
8.37


26



Significant Fields
Our properties in the Eagle Ford in South Texas, which contain primarily crude oil reserves, represented approximately 97 percent of our total equivalent proved reserves as of December 31, 2017.
The following table sets forth certain information with respect to this field for the periods presented:
 
Successor
 
 
Predecessor
 
Year Ended
 
September 13 Through
 
 
January 1 Through
 
Year Ended
 
December 31,
 
December 31,
 
 
September 12
 
December 31,
 
2017
 
2016
 
 
2016
 
2015
Production: 1
 
 
 

 
 
 

 
 

Crude oil (MBbl)
2,716

 
695

 
 
2,265

 
4,733

NGLs (MBbl)
418

 
130

 
 
449

 
1,169

Natural gas (MMcf)
2,120

 
674

 
 
2,141

 
6,011

Total (MBOE)
3,487

 
937

 
 
3,071

 
6,903

Percent of total company production
92
%
 
90
%
 
 
92
%
 
87
%
Average prices:
 
 
 
 
 
 
 
 
Crude oil ($ per Bbl)
$
51.08

 
$
46.73

 
 
$
35.24

 
$
44.73

NGLs ($ per Bbl)
$
18.13

 
$
14.82

 
 
$
10.34

 
$
11.03

Natural gas ($ per Mcf)
$
2.95

 
$
2.79

 
 
$
2.05

 
$
2.64

Aggregate ($ per BOE)
$
43.74

 
$
38.71

 
 
$
28.94

 
$
34.84

Average production and lifting cost ($ per BOE): 2
 
 
 
 
 
 
 
 
Lease operating
$
5.79

 
$
5.39

 
 
$
4.58

 
$
5.04

Gathering processing and transportation
2.49

 
2.58

 
 
3.50

 
2.66

 
$
8.28

 
$
7.97

 
 
$
8.08

 
$
7.70

_____________________________________________
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, 2017, 2016 and 2015, 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. 
 
2017
 
2016
 
2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development
 

 
 

 
 

 
 

 
 

 
 

Productive
29

 
16.9

 
5

 
2.9

 
61

 
38.6

Dry well 1
1

 
0.7

 

 

 

 

Total
30

 
17.6

 
5

 
2.9

 
61

 
38.6

 
 
 
 
 
 
 
 
 
 
 
 
Wells in progress at end of year 2
11

 
8.2

 
5

 
2.6

 
4

 
2.3

_____________________________________________
1 Represents the Zebra Hunter 05H well in the northern portion of our Eagle Ford acreage.
2 Includes ten gross (7.4 net) wells completing or waiting on completion and one gross (0.8 net) well being drilled as of December 31, 2017.
Present Activities
As of December 31, 2017, we had 11 gross (8.2 net) wells in progress, all of which were located in the Eagle Ford in South Texas. As of February 23, 2018, seven gross (5.4 net) wells were completed, three gross (2.0 net) wells were completing or waiting on completion and one gross (0.8 net) well was the first well drilled on a three-well pad and will be prepared for completion with the other two wells upon drilling to total depth for this pad.
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

27



through 2031 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 that agreement. In 2016, following the suspension of our drilling program, we incurred charges for 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, 2017:
 
 
Primarily Oil
 
Primarily Natural Gas
 
Total
Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
South Texas
 
402

 
289.2

 
1

 
1.0

 
403

 
290.2

Mid-Continent
 
2

 
1.6

 
95

 
41.1

 
97

 
42.7

 
 
404

 
290.8

 
96

 
42.1

 
500

 
332.9

Of the total wells presented in the table above, we are the operator of 399 gross (367 oil and 32 gas) and 297.4 net (277.1 oil and 20.3 gas) wells. In addition to the above working interest wells, we own royalty interests in 19 gross wells.
Acreage
The following table sets forth by region our developed and undeveloped acreage as of December 31, 2017 (in thousands):
 
 
Developed 
 
Undeveloped 
 
Total 
Region
 
Gross 
 
Net 
 
Gross 
 
Net 
 
Gross 
 
Net 
South Texas
 
90.6

 
66.7

 
7.8

 
6.7

 
98.4

 
73.4

Mid-Continent and other
 
15.6

 
7.4

 
9.7

 
9.5

 
25.3

 
16.9

 
 
106.2

 
74.1

 
17.5

 
16.2

 
123.7

 
90.3

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 is HBP. As of December 31, 2017, 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
 
2018
 
2019
 
2020
 
Thereafter
South Texas
 
2.7
 
0.8
 
3.1
 
0.1
Mid-Continent and other
 
0.0
 
9.5
 
0.0
 
0.0
We anticipate paying options to extend a substantial portion of the acreage scheduled to expire in South Texas in 2018. We do not believe that the remaining scheduled expirations of our undeveloped acreage in South Texas will substantially affect our ability or plans to conduct our exploration and development activities. In February 2018, we sold the our undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana that was scheduled to expire in 2019.
Item 3
Legal Proceedings
On May 12, 2016, or 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 United States Bankruptcy Court for the Eastern District of Virginia.
On August 11, 2016, the Bankruptcy Court confirmed the 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 and emergence.
On February 7, 2017, a former shareholder of the Company filed a Complaint against us in the Bankruptcy Court requesting that the Bankruptcy Court set aside its prior order confirming the Plan, previously confirmed on August 11, 2016, or provide other equitable relief or damages. We filed a motion to dismiss the proceeding which was granted by the Bankruptcy Court on July 21, 2017. The former shareholder filed a notice of appeal to the U.S. District Court for the Eastern District of Virginia on July 27, 2017. As reflected by the Bankruptcy Court’s ruling, we believe this matter is without merit and will defend confirmation of the Plan.  Absent a reversal or modification of the Bankruptcy Court’s decision, this matter has no impact on the order confirming the Plan.
See Note 15 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 threatened to be brought against us, under the various environmental protection statutes to which we are subject.
Item 4
Mine Safety Disclosures
Not applicable.

28



Part II
 Item 5
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
In connection with our reorganization and emergence from bankruptcy, our common stock was initially listed on the OTCQX U.S. Premier Market under the symbol “PVAC” on November 15, 2016. Prior to such time, there was no established trading market for our common stock. On December 28, 2016, our 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 our common stock since November 15, 2016:
 
 
 
 
Sales Price
Quarter Ended
 
 
 
High
 
Low
December 31, 2017
 
 
 
$
43.29

 
$
32.99

September 30, 2017
 
 
 
$
40.50

 
$
33.44

June 30, 2017
 
 
 
$
50.00

 
$
31.00

March 31, 2017
 
 
 
$
61.97

 
$
41.40

December 31, 2016
 
 
 
$
50.00

 
$
34.75

Equity Holders
As of February 23, 2018, there were 109 record holders of our common stock.
Dividends
We have not paid nor do we intend in the foreseeable future to pay any cash dividends on our common stock. Furthermore, we are restricted from paying dividends under the Credit Facility and the Second Lien Facility.
Securities Authorized for Issuance Under Equity Compensation Plans
See Part III, Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and Note 17 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” for information regarding shares of common stock authorized for issuance under our stock compensation plans.
Issuer Purchases of Equity Securities
We did not repurchase any shares of our common stock in the fourth quarter of 2017.

29



Performance Graph
The following graph compares our cumulative total shareholder return with the cumulative total return of the Standard & Poor’s 600 Oil & Gas Exploration and Production Index and the Standard & Poor’s SmallCap 600 Index for the period from November 15, 2016 (the date that our common shares became publicly tradable) through December 31, 2017. As of December 31, 2017, there were five exploration and production companies in the Standard & Poor’s 600 Oil & Gas Exploration and Production Index: Bill Barrett Corporation, Carrizo Oil & Gas, Inc., Denbury Resources Inc., PDC Energy, Inc. and SRC Energy Inc. The graph assumes $100 is invested on November 15, 2016 in us and each index at November 15, 2016 closing prices.
a2017perfgraph.jpg

The following table represents the actual data points for the dates indicated on the graph above:
 
 
November 15,
 
December 31,
 
 
2016
 
2016
 
2017
Penn Virginia Corporation
 
$
100.00

 
$
120.62

 
$
96.27

S&P SmallCap 600 Index
 
$
100.00

 
$
116.34

 
$
131.74

S&P 600 Oil & Gas Exploration & Production Index
 
$
100.00

 
$
122.91

 
$
86.71



30



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.”
 
(in thousands, except per share amounts, production and reserves)
 
Successor
 
 
Predecessor
 
Year
 
September 13
 
 
January 1
 
 
 
 
 
 
 
Ended
 
Through
 
 
Through
 
 
 
 
 
 
 
December 31,
 
December 31,
 
 
September 12,
 
Year Ended December 31,
 
2017
 
2016
 
 
2016
 
2015
 
2014
 
2013
Statements of Operations and Other Data:
 
 
 
 
 
 

 
 

 
 

 
 

Revenues
$
160,054

 
$
39,003

 
 
$
94,310

 
$
305,298

 
$
636,773

 
$
431,468

Operating income (loss )1
$
51,811

 
$
11,391

 
 
$
(20,856
)
 
$
(1,565,041
)
 
$
(615,985
)
 
$
(92,046
)
Net income (loss) 2
$
32,662

 
$
(5,296
)
 
 
$
1,054,602

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

 
$

 
 
$
5,972

 
$
22,789

 
$
17,148

 
$
6,900

Income (loss) attributable to common shareholders 2
$
32,662

 
$
(5,296
)
 
 
$
1,048,630

 
$
(1,605,750
)
 
$
(430,996
)
 
$
(149,970
)
Income (loss) per common share, basic
$
2.18

 
$
(0.35
)
 
 
$
11.91

 
$
(21.81
)
 
$
(6.26
)
 
$
(2.41
)
Income (loss) per common share, diluted
$
2.17

 
$
(0.35
)
 
 
$
8.50

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

 
 

 
 

Basic
14,996

 
14,992

 
 
88,013

 
73,639

 
68,887

 
62,335

Diluted
15,063

 
14,992

 
 
124,087

 
73,639

 
68,887

 
62,335

Dividends declared per share
$

 
$

 
 
$

 
$

 
$

 
$

Cash provided by operating activities
$
81,710

 
$
30,774

 
 
$
30,247

 
$
169,303

 
$
282,724

 
$
261,512

Cash paid for capital expenditures
$
115,687

 
$
4,812

 
 
$
15,359

 
$
364,844

 
$
774,139

 
$
504,203

 
 
 
 
 
 
 
 
 
 
 
 
 
Total production (MBOE)
3,779

 
1,039

 
 
3,346

 
7,923

 
7,934

 
6,824

 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
September 12,
 
December 31,
Balance Sheet and Other Data:
2017
 
2016
 
 
2016
 
2015
 
2014
 
2013
Property and equipment, net
$
529,059

 
$
247,473

 
 
$
253,510

 
$
344,395

 
$
1,825,098

 
$
2,237,304

Total assets
$
629,597

 
$
291,686

 
 
$
333,974

 
$
517,725

 
$
2,201,810

 
$
2,472,830

Total debt
$
265,267

 
$
25,000

 
 
$
75,350

 
$
1,224,383

 
$
1,085,429

 
$
1,252,808

Shareholders’ equity (deficit)
$
221,639

 
$
185,548

 
 
$
190,895

 
$
(915,121
)
 
$
675,817

 
$
788,804

 
 
 
 
 
 
 
 
 
 
 
 
 
Actual shares outstanding at period-end
15,019

 
14,992

 
 
14,992

 
81,253

 
71,569

 
65,307

Proved reserves as of December 31,(MMBOE)
73

 
49

 
 
N/A

 
44

 
115

 
136

_____________________________________________
1 Operating loss for 2015, 2014 and 2013 included impairment charges of $1.4 billion, $791.8 million and $132.2 million, respectively.
2 
Net income (loss) and Income (loss) attributable to common shareholders for the period of January 1 through September 12, 2016 includes reorganization items attributable to our bankruptcy proceedings of $1.1 billion.
3 
Excludes inducements paid for the conversion of preferred stock of $4.3 million in 2014.




31



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, 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.
While crude oil prices began 2017 in the $53 per Bbl range, they declined through the late winter and throughout the summer before climbing back and ending the year at approximately $60 per Bbl. With the improved pricing environment domestic production has increased including that in the broader Eagle Ford region in which we operate. This environment has expanded opportunities in our principal operating region. Furthermore, many exploration and production companies that experienced financial difficulties similar to us during 2015 to 2016 time frame have restructured and refocused their financial resources and operating plans to capitalize on current opportunities. As a result, pricing for certain oilfield products and services, including drilling and completion services, have increased in the past several months.
As discussed in further detail in Note 4 to our Consolidated Financial Statements, we have adopted and applied Fresh Start Accounting as a result of our emergence from bankruptcy in 2016. 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 the 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 enhance 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.
The following summarizes certain key operating and financial highlights for the three months ended December 31, 2017 with comparison to the three months ended September 30, 2017. The year-over-year highlights for 2017 and 2016 are addressed in further detail in the discussions for Financial Condition and Results of Operations that follow.
Production increased approximately 31 percent to 1,135 MBOE, from 864 MBOE .
Product revenues increased approximately 58 percent to $54.1 million from $34.3 million due primarily to the aforementioned increase in production as well as higher pricing for crude oil and NGLs partially offset by lower natural gas prices.
Production and lifting costs increased on an absolute basis to $9.5 million from $7.6 million, but decreased on a per unit basis to $8.35 per BOE, from $8.85 per BOE due primarily to lower maintenance costs as well as the effect of the increase in production volume.
Production and ad valorem taxes increased on an absolute and per unit basis to $3.0 million and $2.68 per BOE from $1.7 million and $1.93 per BOE, respectively, due primarily to higher production volume and product pricing.
General and administrative expenses decreased on an absolute and per unit basis to $3.5 million and $3.05 per BOE from $7.0 million and $8.04 per BOE, respectively, due primarily to transaction costs associated with the Devon Acquisition and costs incurred to complete an upgrade of our ERP system, both of which were incurred in the third quarter of 2017, as well as the effect of higher production volume.
Our DD&A increased to $17.1 million, or $15.07 per BOE from $10.7 million, or $12.33 per BOE due primarily to the increase in capitalized costs for oil and gas properties resulting from the Devon Acquisition and our expanded capital program as well as the effect of higher production volume.
Our operating income increased to $21.2 million for the three months ended December 31, 2017 compared to $7.5 million for the three months ended September 30, 2017 due the combined impact of the matters noted above.


32



The following table sets forth certain historical summary operating and financial statistics for the periods presented: 
 
(in thousands except per unit measurements, production, wells and reserves)
 
Successor
 
 
Predecessor
 
Year Ended
 
September 13 Through
 
 
January 1 Through
 
Year Ended
 
December 31,
 
December 31,
 
 
September 12,
 
December 31,
 
2017
 
2016
 
 
2016
 
2015
Total production (MBOE)
3,779

 
1,039

 
 
3,346

 
7,923

Average daily production (BOEPD)
10,353

 
9,449

 
 
13,071

 
22,476

Crude oil production (MBbl)
2,764

 
710

 
 
2,311

 
4,923

Crude oil production as a percent of total
73
%
 
68
%
 
 
69
%
 
62
%
Product revenues
$
159,469

 
$
38,654

 
 
$
93,649

 
$
262,980

Crude oil revenues
$
140,886

 
$
33,157

 
 
$
81,377

 
$
220,596

Crude oil revenues as a percent of total
88
%
 
86
%
 
 
87
%
 
84
%
Realized prices:
 
 
 
 
 
 
 
 
Crude oil ($ per Bbl)
$
50.96

 
$
46.68

 
 
$
35.21

 
$
44.81

NGL ($ per Bbl)
$
19.25

 
$
16.56

 
 
$
11.37

 
$
12.24

Natural gas ($ per Mcf)
$
2.89

 
$
2.81

 
 
$
2.06

 
$
2.62

Aggregate ($ per BOE)
$
42.20

 
$
37.19

 
 
$
27.99

 
$
33.18

Prices, adjusted for derivatives::
 
 
 
 
 
 
 
 
Crude oil ($ per Bbl)
$
49.69

 
$
47.17

 
 
$
55.98

 
$
72.74

Natural gas ($ per Mcf)
$
2.89

 
$
2.81

 
 
$
2.06

 
$
2.69

Aggregate ($ per BOE)
$
41.27

 
$
37.56

 
 
$
42.33

 
$
50.63

Production and lifting costs ($ per BOE):
 
 
 
 
 
 
 
 
Lease operating
$
5.76

 
$
5.13

 
 
$
4.67

 
$
5.36

Gathering, processing and transportation
$
2.84

 
$
2.93

 
 
$
3.96

 
$
3.01

Production and ad valorem taxes ($ per BOE)
$
2.33

 
$
2.40

 
 
$
1.04

 
$
2.06

General and administrative ($ per BOE) 1
$
4.83

 
$
4.90

 
 
$
11.64

 
$
5.47

Depreciation, depletion and amortization ($ per BOE) 2
$
12.87

 
$
11.21

 
 
$
10.04

 
$
42.22

Cash provided by operating activities 3
$
81,710

 
$
30,774

 
 
$
30,247

 
$
169,303

Cash paid for capital expenditures
$
115,687

 
$
4,812

 
 
$
15,359

 
$
364,844

Cash and cash equivalents at end of period
$
11,017

 
$
6,761

 
 
$
31,414

 
$
11,955

Debt outstanding, net of discount and issue costs, at end of period
$
265,267

 
$
25,000

 
 
$
75,350

 
$
1,224,383

Credit available under credit facility at end of period 4
$
159,745

 
$
102,233

 
 
$
51,883

 
$

Net development wells drilled and completed
16.9

 

 
 
2.9

 
38.6

Proved reserves at the end of the period (MMBOE)
73

 
49

 
 
N/A

 
44

_____________________________________________
1 Includes equity-classified share-based compensation, liability-classified share-based compensation and significant special charges, including acquisition transaction costs, 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 $1.35, $6.98 and $1.39 for the year ended December 31, 2017, the Predecessor period in 2016 and the year ended December 31, 2015, respectively.
2 
Determined using the full cost method for the Successor periods and the successful efforts method for the Predecessor periods.
3 
Includes cash paid for derivative settlements of $3.5 million for 2017 and cash received for derivative settlements of $0.4 million, $48.0 million and $138.2 million for the Successor period in 2016, the Predecessor period in 2016 and 2015, respectively.
4 
As of December 31, 2015, we were unable to draw on our pre-petition credit facility, or RBL.

33



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:
Acquisition of Producing Properties
Hunt Acquisition
In December 2017, we entered into a purchase and sale agreement with Hunt to acquire certain oil and gas assets in the Eagle Ford Shale, primarily in Gonzales and Lavaca Counties, Texas for $86.0 million in cash, subject to adjustments, or the Hunt Acquisition. The Hunt Acquisition has an effective date of October 1, 2017 and closed on March 1, 2018. We funded the Hunt Acquisition with borrowings under the Credit Facility. The Hunt Acquisition expands our core net leasehold position by approximately 9,700 net acres, substantially all of which is held by production, in the northwestern portion of our Eagle Ford acreage. As a result of the Hunt Acquisition we are the operator of substantially all of our Eagle Ford acreage.
Devon Acquisition
In July 2017, we entered into a purchase and sale agreement, or the Purchase Agreement, with Devon, to acquire all of Devon’s right, title and interest in and to certain oil and gas assets, or the Devon Properties, including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas for consideration of $205 million in cash, subject to adjustment, or the Devon Acquisition. Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account, or the Escrow Account. The Devon Acquisition has an effective date of March 1, 2017 and closed on September 29, 2017, at which time we paid cash consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. In November 2017, we acquired additional working interests in the Devon Properties for $0.7 million from parties that had tag-along rights to sell their interests under the Purchase Agreement.
The final settlement of the Devon Acquisition together with the tag-along rights acquisition, occurred in February 2018 at which time $2.5 million in cash was transferred from the Escrow Account to Devon representing final adjustments for the period from the effective date of the acquisition through the closing date and the curing of title defects for certain properties. As of December 31, 2017, there was $3.2 million remaining in the Escrow Account, which is included as a component of noncurrent “Other assets” on our Consolidated Balance Sheet. Of this total, $2.5 million was transferred as described above and the remaining $0.7 million was distributed to us in February 2018.
Amendments to Credit Facility and Borrowing Base Redetermination
On March 1, 2018, we entered into an amendment to our Credit Facility that increased our borrowing base by $102.5 million to $340 million from $237.5 million pursuant to the Spring redetermination and the Hunt Acquisition.
Previously, in September 2017 and in connection with the closing of the Second Lien Facility (discussed below), the Credit Facility was amended to, among other things, increase the borrowing base to its year-end 2017 level of $237.5 million, provide for the entry into the Second Lien Facility, the borrowings thereunder, the granting of liens to secure the obligations thereunder and other related modifications.
Second Lien Facility
In September 2017, we entered into the Second Lien Facility. We received net proceeds of $187.8 million from the Second Lien Facility net of an original issue discount, or OID, of $4.0 million and issue costs of $8.2 million. The proceeds from the Second Lien Facility were used to fund the Devon Acquisition and related fees and expenses. The Second Lien Facility was issued at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.89%. The initial interest rate on the Second Lien Facility as described above was based on the three-month LIBOR rate in effect on the date the Second Lien Facility was entered into. As of March 1, 2018, the interest rate was 8.65%. The maturity date under the Second Lien Facility is September 29, 2022.

34



Production, Capital and Development Plans
Total production for the quarter and year ended December 31, 2017 was 1,135 MBOE and 3,779 MBOE, or 12,340 BOEPD and 10,353 BOEPD, with approximately 74 percent and 73 percent, or 845 MBbls and 2,764 MBbls, of production from crude oil, 13 percent and 14 percent from NGLs and 13 percent and 13 percent from natural gas, respectively. Production from our Eagle Ford operations during these periods was 1,067 MBOE and 3,487 MBOE, or 11,594 BOEPD and 9,553 BOEPD, respectively. Approximately 78 percent of our Eagle Ford production for each of the periods was from crude oil, 12 percent was from NGLs and 10 percent was from natural gas, respectively. Production from our Eagle Ford operations was approximately 94 percent and 92 percent of total Company production during the quarter and year ended December 31, 2017, respectively.
We drilled and turned nine and 29 gross (5.3 and 16.9 net) Eagle Ford wells to sales during the quarter and year ended December 31, 2017, respectively.
Based on our business plan, we anticipate total capital expenditures for 2018 to total between $320 and $360 million with approximately 95 percent of capital being directed to drilling and completions in the Eagle Ford.
Commodity Hedging Program
As of February 23, 2018, we have hedged a substantial portion of our estimated future crude oil production through the end of 2020. For 2018, we have 6,227 BOPD with a weighted-average WTI-based swap price of $50.70 per barrel and 2,500 BOPD with a weighted-average LLS-based swap price of $55.18 per barrel. For 2019, we have 4,915 BOPD with a weighted-average WTI-based swap price of $52.12 per barrel and 2,500 BOPD with a weighted-average LLS-based swap price of $51.30 per barrel. For 2020, we have 4,000 BOPD with a weighted-average WTI-based swap price of $52.67 per barrel. We are currently unhedged with respect to NGL and natural gas production.
Changes to Executive Management and Board of Directors
Effective August 15, 2017, our board of directors appointed John Brooks as our President and Chief Executive Officer and as a member of our board of directors. Furthermore, effective January 19, 2018, the Board increased the size of the Board to seven members and elected Mr. David Geenberg and Mr. Michael Hanna as members of the Board to fill the newly created vacancies. Additionally, effective February 28, 2018, Mr. Harry Quarls resigned from his position as a director and Executive Chairman of the Company, and the Board was reduced to six members. The Company is actively engaged in finding a new independent board member to serve as chairman of the board of directors of the Company. Until the Company can find such replacement, Darin G. Holderness and David Geenberg will serve as co-chairmen of the board.


35



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, as recently amended, provides us with up to $340 million in borrowing commitments. The current borrowing base under the Credit Facility is also $340 million. As of March 1, 2018, we had $164.2 million of availability under the Credit Facility, which reflects borrowings of $78.0 million drawn on March 1, 2018 to substantially fund the Hunt Acquisition.
Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for 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 financial 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 derivative contracts hedging a substantial portion of our estimated future crude oil production through the end of 2020.
Our business plan contemplates capital expenditures in excess of our projected cash from operating activities for 2018. Subject to the variability of commodity prices and production that impacts our cash from operating activities, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our 2018 capital program with cash from operating activities and borrowings under the Credit Facility.
Capital Resources
Under our business plan for 2018, we currently anticipate capital expenditures, excluding acquisitions, to total between $320 million and $360 million with approximately 95 percent of capital being directed to drilling and completions on our Eagle Ford acreage. We plan to fund our 2018 capital spending with cash from operating activities and borrowings under the Credit Facility. Based upon current price and production expectations for 2018, we believe that our cash from operating activities and borrowings under our Credit Facility will be sufficient to fund our operations through year-end 2018; 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. 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 December 31, 2017, we had approximately $11 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.
Credit Facility Borrowings. During 2017, we borrowed $52 million, net of repayments, under the Credit Facility. 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
Three months ended December 31, 2017
$
61,457

 
$
77,000

 
 
4.53
%
Year ended December 31, 2017
$
41,840

 
$
77,000

 
 
4.29
%
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.

36



Cash Flows
The following table summarizes our cash flows for the periods presented:
 
Successor
 
 
Predecessor
 
Year
 
September 13
 
 
January 1
 
Ended
 
Through
 
 
Through
 
December 31,
 
December 31,
 
 
September 12,
 
2017
 
2016
 
 
2016
Cash flows from operating activities
 
 
 
 
 


Operating cash flows, net of working capital changes
$
91,365

 
$
31,068

 
 
$
34,914

Crude oil derivative settlements (paid) received, net
(3,511
)
 
384

 
 
48,008

Interest payments, net of amounts capitalized
(4,102
)
 
(598
)
 
 
(4,331
)
Income tax refunds

 
7

 
 
35

Acquisition transaction costs paid
(1,088
)
 

 
 

Strategic and financial advisory fees paid

 

 
 
(18,036
)
Reorganization items paid
(1,269
)
 
(648
)
 
 
(28,570
)
Return of professional fee escrow
315

 
756

 
 

Restructuring and exit costs paid

 
(195
)
 
 
(1,773
)
Net cash provided by operating activities
81,710

 
30,774

 
 
30,247

Cash flows from investing activities
 

 
 

 
 
 

Acquisitions, net
(200,849
)