Clean Air Act. Our operations are subject to the Clean Air Act, or the CAA, and comparable state and local requirements. In 1990, the U.S. Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed, and continue to develop, regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Further, stricter requirements could negatively impact our production and operations. ~~For example,~~Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the ~~Texas Commission on Environmental Quality~~CAA and associated state laws and regulations. In addition, the ~~Railroad Commission~~EPA has developed, and continues to develop, stringent regulations governing emissions of ~~Texas have been evaluating possible additional regulation of~~toxic air emissions in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actionspollutants at ~~the local, state and federal levels.~~specified sources.

InOn April 17, 2012, the EPA issued ~~new~~final rules ~~subjecting certain~~to subject oil and gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. ~~These~~The EPA rules ~~restrict volatile organic compound emissions from three subcategories~~include NSPS standards for completions of hydraulically fractured ~~and refractured~~natural gas wells, ~~for which well completion operations are conducted. These regulations also establish specific requirements regarding emissions from production related wet seal and reciprocating~~ compressors, ~~pneumatic~~ controllers, ~~and~~dehydrators, storage ~~vessels. In September 2015, the EPA proposed expanding the 2012 NSPS to create additional methane standards for new compressor stations,~~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 gas industry as well ~~sites.~~as source determination standards for determining when oil and gas sources should be aggregated for CAA permitting and compliance purposes. The ~~proposed~~ NSPS ~~would limit~~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 ~~during well completions, impose new leak detection,~~monitoring requirements, pneumatic pump standards and ~~ongoing survey, repair,~~closed vent system certification requirements in the 2016 NSPS rule for the oil and ~~recordkeeping requirements.~~

gas industry while it reconsiders these aspects of the rule. The proposal is still under consideration. More recently, in September 2018, the EPA ~~has also released new draft control guidance for reducing volatile organic compound~~proposed targeted improvements to the rule, including amendments to the rule’s fugitive emissions monitoring requirements, and expects to “significantly reduce” the regulatory burden of the rule in doing so. 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 ~~sources~~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 ~~ozone non-attainment areas.~~of these requirements set forth in its Venting and Flaring Rule until January 2019, and in September 2018, the BLM proposed a revised rule which would scale back the waste-prevention requirements of the 2016 rule. Environmental groups sued in federal district court a day later to challenge the legality of aspects of the revised rule, and the outcome of this litigation is currently uncertain. These rules have required changes to our operations, including the installation of new equipment to control emissions. The EPA ~~acknowledged that some of its recommendations mirror the requirements found~~had announced in ~~the proposed NSPS~~2016 an intent to impose methane emission standards for ~~new sources and that, if adopted by states, these recommendations would apply to both new and~~ existing sources, but the agency was sued by multiple states for failing to implement these standards following the agency’s withdrawal of ~~volatile organic compounds~~information collection requests for oil and gas facilities. These rules would result in ~~ozone non-attainment areas. If~~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 ~~rules are adopted as proposed~~oil and ~~the guidance remains unchanged, they would impose new~~gas industry remain a possibility and could result in increased compliance costs on our operations.

In ~~addition, in~~ November 2015, the EPA ~~also~~ revised the existing National Ambient Air Quality Standards for ground level ozone to make the standard more stringent. ~~Certain~~The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas ~~of the country previously~~ in ~~compliance with the various National Ambient Air Quality Standards, including areas where~~which we operate ~~may be reclassified~~have been classified 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,~~may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Generally, it will take the states several years to develop compliance plans for their non-attainment areas. If the areas where we operate are reclassified as non-attainment areas, such reclassifications may make it more difficult to construct new or modified sources of air pollution in those areas. A number of states have also filed or joined suits to challenge the EPA’s new standard in court. While we are not able to determine the extent to which this new standard will impact our business at this time, it ~~does have~~has the potential to have a material impact on our operations and cost structure.

In June 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. ~~We are currently researching the effect these new rules will have on our business, but generally expect them to add to the cost and expense of our operations.~~

There have been recent claims asserted that individual wells and other facilities should be “aggregated” together and their collective emissions considered in determining whether major source permitting requirements apply under the CAA. Based on several recent court decisions striking down agency determinations and guidance, the EPA may only make these decisions based on physical proximity and is precluded from considering functional relationships between the facilities. In September 2015, the EPA proposed a rule with two options for defining a “source.” The EPA’s “preferred” option would codify the current approach whereby only sources that “are contiguous or are located within a short distance of one another”-a quarter mile-would be considered “adjacent” and thus a “single source.” The EPA’s second proposed option would allow sources located more than a quarter mile away if it they are “functionally interrelated” to the source, for example through a physical connection, such as a pipeline between equipment. If the EPA adopts the “functionally interrelated” test, it would introduce uncertainty into the permitting process and could require more lengthy and costly permitting processes and more expensive emission controls.

Greenhouse Gas Emissions. 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 ~~greenhouse gas, or~~ GHG emissions. OnMost 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 ~~28, 2010,~~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.

In August 2015, the EPA 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, which has not been finalized. In August 2018, the EPA proposed the Affordable Clean Energy rule (ACE) as a replacement to the 2015 regulations. ACE primarily addresses onsite efficiency improvements for power plants and does not require generation-shifting to low- or zero-emitting energy sources. The EPA’s proposals will be subject to public comment or legal challenge, and as such we cannot predict at this time what impact the rulemakings will have on the demand for oil and gas production and our operations.

The EPA has issued the “Final Mandatory Reporting of Greenhouse Gases” Rule ~~or the Reporting Rule, requiring all stationary sources that emit more than 25,000 tons~~and a series of ~~GHGs per year~~revisions to ~~collect~~it, which requires operators of oil and ~~report to the EPA data regarding such emissions. The Reporting Rule establishes a new comprehensive scheme, which began in 2011, requiring operators of~~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. On November 9, 2010, the EPA issued final rules applying these regulations to the oil and gas source category, including oil and gas production, natural gas processing, transmission, distribution and storage facilities (Subpart W). In October 2015, the EPA released a final rule adding reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. In January 2016, the EPA proposed additional changes to the reporting requirements under the program. These rules do not require control of GHGs. However, the EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits.

In addition, in 2009, the EPA issued a final rule known as the EPA’s Endangerment Finding, which found that current and projected concentrations of six key GHGs in the atmosphere threaten public health and the environment, as well as the welfare of current and future generations. Legal challenges to these findings have been asserted, and the U.S. Congress is considering legislation to delay or repeal the EPA’s actions, but we cannot predict the outcome of this litigation or these efforts. The EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. These rules were subject to judicial challenge, but on June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit rejected challenges to the tailoring rule and other EPA rules relating to the regulation of GHGs under the CAA.

Starting July 1, 2011, the EPA required facilities that must already obtain New Source Review permits for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year. On March 27, 2012, the EPA issued its proposed NSPS for carbon dioxide emissions standard from new and modified power plants and held public hearings on the rule in May 2012 and accepted written comments until June 25, 2012. In its June 2013 Climate Action Plan, the Obama Administration announced its intent to issue regulations under Section 111(b) and Section 111(d) of the CAA to set NSPS for both new and existing power plants by June 2015. The Climate Action Plan also directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and natural gas industry.

In August 2015, the EPA issued its final Clean Power Plan rules establishing carbon pollution standards for power plants. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan, and has also proposed a federal compliance plan to implement the Clean Power Plan in the event that approvable state plans are not submitted. Judicial challenges have been be filed, which seek a stay of the implementation of the rules. Electricity generated by natural gas often results in lower CO₂ emission rates than other forms of fossil fuels. Depending on the method of implementation selected by the states, and if implementation is not stayed pending resolution of the legal challenges, the Clean Power Plan could increase the demand for natural gas-generated electricity.

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

~~In addition to regulatory programs aimed at reducing CO~~₂ ~~emissions, the EPA has also proposed regulating the emission of methane, which is also considered to be a GHG, from~~ the oil and gas ~~sector through~~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 ~~NSPS program. As a result of this continued regulatory focus, future~~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. Moreover, the U.S. Fish and Wildlife Service continues its six-year effort to make listing decisions and critical habitat designations where necessary for over 250 species before the end of the agency’s 2017 fiscal year, as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. The presence of any protected species or the final designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse effect on our ability to develop and produce our reserves.

National Environmental Policy Act. Oil and 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 gas projects.

Employees and Labor Relations

We had a total of ~~112~~95 employees as of December 31, ~~2015.~~2018. 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.

Available Information

Our internet address is http://www.pennvirginia.com. We make available free of charge on or through our website our Corporate Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics, Audit Committee Charter, Compensation and Benefits Committee Charter and Nominating and Governance Committee Charter, and we will provide copies of such documents to any shareholder who so requests. We also make available free of charge on or through our website our Annual ~~Report~~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,~~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.~~flows in the future. If any of the following risks actually occur, our business, financial condition, results of operations and cash flows could suffer and the trading price of our common stock could decline.

~~We have a significant amount of indebtedness, and there is substantial doubt about our ability to continue as a going concern.~~Risk Factors Associated with the Merger

As of December 31, 2015, we had an aggregate amount of approximately $1.2 billion of debt outstanding. We will be required to pay interest on our senior notes in the amount of $87.6 million in 2016, including $10.9 million in April 2016 and $32.9 million in May 2016. Our ability to make those payments is severely in doubt. In 2015, we incurred a loss from operations of $1.6 billion, including an impairment charge of $1.4 billion. As of March 11, 2016, we had only $32.3 million in cash and cash equivalents. Pursuant to the Eleventh Amendment to the Revolver dated as of March 15, 2016, or the Eleventh Amendment, the commitments under the Revolver were reduced to $171.8 million, which is equal to our currently outstanding loans ($170 million) and issued letters of credit ($1.8 million) under the Revolver. Because we do not have any unused commitment capacity, we will not be able to draw on the Revolver to pay our second quarter interest payments on our senior notes or for any other purpose. Furthermore, we are required, at the time of borrowing and as a condition to borrowing, to make certain representations to our lenders. We may not currently be able to make these representations, nor is it likely that we will be able to do so in the future unless we can restructure our debt obligations. There can be no assurance that we will obtain shareholder approval for the Merger or that the Merger will be able to restructure our debt obligations. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or to otherwise extend the maturity dates, and to cure any potential defaults under the agreements governing such debt, there isconsummated.

There can be no assurance that ~~any particular action or actions with respect to refinancing existing indebtedness, extending~~ the ~~maturity of existing indebtedness or curing potential defaults in our debt agreements~~Merger will be ~~sufficient.~~

~~Moreover,~~consummated and our ~~lenders may~~shareholders will receive the merger consideration. The completion of the Merger is subject to various closing conditions and termination rights (including if the Merger is not consummated by April 30, 2019). In addition to other conditions that are beyond our control, the Merger is subject to approval by the holders of more than two-thirds of the outstanding Company common shares, the approval by the holders of a majority of the outstanding Denbury common shares of an amendment to the certificate of incorporation to increase the number of authorized Denbury common shares, and the approval of the issuance of Denbury common shares in the ~~future exercise their right~~Merger by the holders of a majority of the Denbury common shares represented in person or by proxy at a meeting of Denbury shareholders held to ~~redetermine~~vote on such matters. We cannot guarantee that the closing conditions set forth in the Merger Agreement will be satisfied or, even if satisfied, that no event of termination will take place. The completion of the Merger is not assured and is subject to risks, including the risk that the approval of our ~~$275 million borrowing base under~~shareholders or Denbury’s stockholders is not obtained. Activist shareholders may increase the ~~Revolver. Pursuant~~risk that the requisite votes are not obtained. In that regard, one shareholder of the Company (Mangrove Partners) has engaged in a public campaign to prevent shareholder approval of the Merger, which campaign includes a preliminary proxy statement filed on January 17, 2019, that solicits votes in opposition to the ~~Eleventh Amendment, any~~Merger. Other Company shareholders or Denbury stockholders could oppose the proposals for approval of the Merger. Any such redetermination will not occur until after May 15, 2016. If our borrowing base is redetermined below the amount of our outstanding borrowings, a deficiency will result, and any deficiency must be repaid within 60 days. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”

The consolidated financial statements included in this Annual Report on Form 10‑K have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.

The audit report we received with respect to our year-end 2015 consolidated financial statements contains an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” The Revolver requires us to deliver audited, consolidated financial statements without a “going concern” or like qualification or exception. As a result, we are in default under the Revolver. Our failure to obtain relief from this requirement under the Revolvercampaign could result in ~~an acceleration~~substantial costs and divert each company’s respective management’s and directors’ attention and resources from each company’s respective business. Moreover, the Merger Agreement contains conditions, some of ~~all~~which are beyond our control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Merger not occurring.

Because the exchange ratio in the Merger Agreement is fixed and because the market price of Denbury common stock will fluctuate prior to the completion of the Merger, our ~~outstanding debt obligations.~~shareholders cannot be sure of the market value of the Denbury common stock they will receive as Merger consideration relative to the value of the cash and shares of common stock they exchange at the closing.

Under the ~~Revolver, we are required~~terms of the Merger Agreement, our shareholders will receive the Merger Consideration, consisting of a combination of 12.4 shares of Denbury common stock and $25.86 of cash for each share of Company common stock, subject to ~~deliver audited, consolidated financial statements without~~election of the Company shareholders to receive either all cash, all stock or a ~~“going concern” or like qualification or exception.~~mix of stock and cash, in each case subject to proration. Based on the closing price of Denbury common stock on October 26, 2018, the Merger Consideration represented consideration to each Company shareholder of $79.80 per share. The ~~audit report prepared by our auditors with respect~~exchange ratio for the Merger Consideration is fixed, and there will be no adjustment to the ~~financial statements~~Merger Consideration for changes in ~~this Annual Report on Form 10-K includes an explanatory paragraph expressing substantial doubt as to~~the market price of Denbury’s common stock or our ability to continue as a “going concern.” Therefore, we are in default under the Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default under the Revolver until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.” If we do not obtain a waiver or other suitable relief from the lenders under the Revolvercommon stock prior to the ~~expiration~~completion of the ~~extension,~~Merger.

If the Merger is completed, there will ~~exist an event~~be a time lapse between the date of ~~default under~~signing of the ~~Revolver.~~

Merger Agreement and the date on which our shareholders who are entitled to receive the Merger Consideration actually receive the Merger Consideration. The market value of shares of Denbury’s common stock and our common stock has fluctuated and may continue to fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices, regulatory considerations, and the market’s assessment of Denbury’s business and the Merger. Such factors are difficult to predict and in many cases may be beyond the control of Denbury and us. The actual value of any Merger Consideration received by our shareholders at the completion of the Merger will depend on the market value of the shares of Denbury common stock at that time. This market value may differ, possibly materially, from the market value of shares of Denbury common stock at the time the Merger Agreement was entered into or at any other time. The market value of shares of Denbury Common Stock has declined from $4.35 per share on the trade date immediately prior to the public announcement of the Merger to $2.14 per share on February 22, 2019, and the market value of the Company common stock per share has decreased from $67.39 to $56.24 in the same period. If ~~an event~~the trading price of ~~default occurs under~~Denbury common stock at the ~~Revolver,~~closing of the ~~lenders could accelerate~~Merger is less than the ~~loans outstanding under~~trading price of Denbury common stock on the ~~Revolver. In addition,~~date that the Merger Agreement was signed, particularly if the lenders under the Revolver accelerate the loans outstanding under the Revolver, there will also be cross-defaults under the indentures related to our 7.25% Senior Notes due 2019, or the 2019 Senior Notes, and our 8.5% Senior Notes due 2020, or the 2020 Senior Notes. If these cross-defaults occurred, the holderstrading price of the ~~2019 Senior Notes or~~Company common stock increases, then the ~~2020 Senior Notes~~market value of the Merger Consideration will be less than contemplated at the time the Merger Agreement was signed. This could ~~accelerate those notes.~~

If our lenders or our noteholders accelerate the payment of amounts outstanding under the Revolver, the 2019 Senior Notes or the 2020 Senior Notes, respectively, we do not currently have sufficient liquidity to repay such indebtedness and would need additional sources of capital to do so. We could attemptmake it more difficult to obtain ~~additional sources~~shareholder approval of ~~capital~~and complete the Merger.

Even if Denbury and the Company complete the Merger, Denbury may fail to realize all of the anticipated benefits of the Merger.

Even if we complete the Merger, the combined company may not realize the benefits and guidance provided by either Denbury or us, including due to factors beyond the control of the combined company’s management. The success of the Merger will depend, in part, on Denbury’s ability to realize the anticipated financial benefits from ~~asset sales, public or private issuances~~combining Denbury’s and the Company’s businesses, including synergies. The anticipated financial benefits of ~~debt, equity or equity-linked securities, debt for equity swaps, or any combination thereof. However, we cannot provide any assurances that we will~~the Merger may not be ~~successful in obtaining capital from such transactions on acceptable terms,~~realized fully or at all, ~~and if~~may take longer to realize than expected or could have other adverse effects that neither we fail to obtain sufficient additional capital to repay the outstanding indebtedness and provide sufficient liquidity to meet our operating needs, it may be necessary for us to seek protection from creditors under Chapter 11nor Denbury currently foresee. Some of the ~~United States Bankruptcy Code, or Chapter 11.~~

Ifassumptions that we ~~cannot obtain sufficient capital when needed, we will not be able to continue with our historical business strategy.~~

~~Our business strategy has historically included maintaining a portfolio~~have made, such as the achievement 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~~synergies, may not be ~~able~~realized. The integration process may, for each of Denbury and the Company, result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. There could be potential unknown liabilities and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence.

The Merger involves numerous operational, strategic, financial, accounting, legal, tax and other risks, potential liabilities associated with the acquired businesses, and uncertainties related to ~~obtain financing~~design, operation and integration of the Company’s internal control over financial reporting. Difficulties in ~~sufficient amounts~~integrating the Company into Denbury may result in the combined company performing differently than expected, in operational challenges or ~~on acceptable terms when needed, which~~in the failure to realize anticipated expense-related efficiencies. Denbury’s and the Company’s existing businesses could ~~adversely affect our operating results and prospects. If we cannot raise~~also be negatively impacted by the ~~capital required to implement our historical business strategy, we~~Merger. Potential difficulties that may be ~~required~~encountered in the integration process include, among other factors:

the inability to ~~curtail~~successfully integrate the businesses of the Company into Denbury in a manner that permits the combined company to achieve the full financial benefits anticipated from the Merger;

complexities associated with managing the larger, more complex, integrated business;

not realizing anticipated synergies;

integrating personnel from the two companies and the loss of key employees;

potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Merger;

integrating relationships with customers, vendors and business partners;

performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the Merger and integrating the Company’s operations into Denbury; and

the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.

We will incur significant transaction and Merger-related costs in connection with the Merger, which ~~could adversely affect our financial condition and results of operations.~~

~~Unless we can obtain relief from our lenders, we will also~~may be in ~~breach~~excess of ~~certain financial covenants under the Revolver during 2016.~~

Our ability to borrow under the Revolver is subject to compliance with certain financial covenants, including leverage and current ratios. While we were in compliance with the leverage covenant at December 31, 2015, based on our current operating forecast and capital structure, we do not believe that we will be able to comply with the leverage covenant during the next twelve months. Furthermore, we classified all of our debt as current as of December 31, 2015, which resulted in a breach of the current ratio covenant under the Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default under the Revolver, together with certain other defaults, will not become events of default until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.” If we do not obtain a waiver or other suitable relief from the lenders under the Revolver prior to expiration of the extension, there will exist an event of default under the Revolver. Even if we obtain such a waiver or other relief, we still believe we cannot comply with the leverage covenant during the next twelve months. If we cannot obtain from our lenders a waiver of such potential breach or an amendment of the leverage covenant, our breach would constitute an event of default that could result in an acceleration of substantially all of our outstanding indebtedness. We would not have sufficient capital to satisfy these obligations.

We may seek protection from our creditors under Chapter 11 or an involuntary petition for bankruptcy may be filed against us, either of which could have a material adverse impact on our business, financial condition, results of operations, and cash flows and could place our shareholders at significant risk of losing all of their investment in our shares.those anticipated by us.

We have ~~engaged~~incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the Merger, obtaining shareholder approval (including responding to any activist shareholders) and combining the operations of the two companies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the Merger and include, among others, employee retention costs, fees paid to financial, legal and ~~legal~~accounting advisors, severance and benefit costs and filing fees.

We will also incur transaction fees and costs related to ~~assist us~~formulating and implementing integration plans, including facilities and systems consolidation costs and employment-related costs. We will continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in ~~among~~the Merger and the integration of the two companies’ businesses. Although we expect that the elimination of duplicative costs, as well as the realization of other ~~things, analyzing various strategic alternatives~~efficiencies related to ~~address our liquidity~~the integration of the businesses, should allow Denbury and ~~capital structure, including strategic~~the Company to offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all. The costs described above, as well as other unanticipated costs and refinancing alternatives to restructure our indebtedness in private transactions. However, if our attempts are unsuccessful or we are unable to complete such a restructuring on satisfactory terms, we may choose to pursue a filing under Chapter 11.

~~Seeking bankruptcy court protection~~expenses, could have a material adverse effect on ~~our business,~~the financial condition and operating results of ~~operations~~Denbury following the completion of the Merger. Many of these costs will be borne by us even if the Merger is not completed.

Completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party.

The completion of the Merger may trigger change in control or other provisions in certain agreements to which we are a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and ~~liquidity. For as long as~~remedies under the agreements, potentially terminating the agreements or seeking monetary damages. Even if we are able to negotiate waivers, the counterparties may require a ~~Chapter 11 proceeding continued,~~fee for such waivers or seek to renegotiate the agreements on terms less favorable to us.

The Merger Agreement limits our ~~senior management would~~ability to pursue alternatives to the Merger.

The Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our shareholders than the Merger, or may result in a potential competing acquirer of the Company proposing to pay a lower per share price to acquire the Company than it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our board, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction. Even upon termination of the Merger Agreement under certain circumstances relating to the exercise of fiduciary duties by our board, we may be required to ~~spend a significant amount~~pay Denbury fees and expenses, which may further deter counterparties to any potential alternative transaction.

Failure to complete the Merger could negatively impact the price of time and effort dealing with the reorganization instead of focusing on our business operations. Bankruptcy court protection also could make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our customers and suppliers might lose confidence in our ability to reorganize our business successfully and could seek to establish alternative commercial relationships.

Additionally, all of our indebtedness is senior to the existing common stock in our capital structure. As a result, we believe that seeking bankruptcy court protection under a Chapter 11 proceeding could cause the shares ~~of our existing common stock to be canceled, resulting in a limited recovery, if any, for shareholders~~ of our common stock, ~~and would place shareholders of~~as well as our ~~common stock at significant risk of losing all of their investment in our shares.~~

~~Our substantial indebtedness, liquidity issues and potential to seek restructuring transactions may have a material adverse effect on our business and operations.~~

~~Our substantial indebtedness, liquidity issues and efforts to negotiate restructuring transactions may result in uncertainty about our business and cause, among other things:~~

~~third parties to lose confidence in our ability to explore and produce oil and natural gas, resulting in a significant decline in our revenues, profitability and cash flow;~~

~~difficulty retaining, attracting or replacing key employees;~~

~~employees to be distracted from performance of their duties or more easily attracted to other career opportunities;~~

~~our suppliers, vendors, hedge counterparties and service providers to renegotiate the terms of our agreements, terminate their relationship with us or require financial assurances from us.~~

Continued depressed commodity prices have hurt our profitability, financial condition and ability to service our debt as a result of which we have taken several steps to conserve capital which could further adversely affect our businessfuture businesses and financial ~~condition.~~results.

~~Our revenues, operating results, cash flows, profitability, growth rate, value~~The Merger Agreement contains a number of ~~oil and gas properties and ability~~conditions that must be satisfied or waived prior to service debt depend heavily on prevailing market prices for crude oil, NGLs and natural gas. Average monthly WTI crude oil and natural gas prices have decreased approximately 75 percent and 53 percent from June 2014 to January 2016. These decreases have led us to take steps to conserve capital by, among other things, suspending our drilling operations, completing reductions in force and extending the ~~time for payment~~completion of ~~our service providers. While we intend to resume drilling in 2016, there~~the Merger. There can be no assurance that all of the conditions to the completion of the Merger will be so satisfied or waived. If these conditions are not satisfied or waived, we will be unable to complete the Merger. If the Merger is not completed for any reason, including the failure to receive the required approval of our shareholders or Denbury’s stockholders, our businesses and financial results may be adversely affected, including as follows:

we may experience negative reactions from the financial markets, including negative impacts on the market price of our common stock;

the manner in which customers, vendors, business partners and other third parties perceive the Company may be negatively impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the marketplace more broadly;

we may experience negative reactions from employees; and

we will have ~~adequate capital~~expended time and resources that could otherwise have been spent on our existing businesses and the pursuit of other opportunities that could have been beneficial to ~~do so. Likewise, while we intend~~the Company, and our ongoing business and financial results may be adversely affected.

In addition to ~~pay all amounts due to~~the above risks, if the Merger Agreement is terminated and our ~~service providers, there can~~board seeks an alternative transaction, our shareholders cannot be ~~no assurance~~certain that we will be able to ~~do so or that~~find a party willing to engage in a transaction on more attractive terms than the Merger. If the Merger Agreement is terminated under specified circumstances, we may be required to pay Denbury a $45 million termination fee.

We will be subject to business uncertainties while the Merger is pending, which could adversely affect our ~~service providers will not decline to work for us or take action against us for non-payment. Furthermore,~~businesses.

Uncertainty about the ~~lag in operations~~effect of the Merger on employees and ~~reductions in force which we have completed could~~customers may have an adverse effect on the Company. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter and could cause customers and others that deal with us to seek to change their existing business relationships with us. Employee retention at the Company may be particularly challenging during the pendency of the Merger, as employees may experience uncertainty about their roles. In addition, the Merger Agreement restricts us from entering into certain corporate transactions, entering into material contracts, changing our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Denbury, and generally requires us to continue our operations in the ordinary course of business, until completion of the Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Merger.

We may be a target of securities class action and derivative lawsuits that could result in substantial costs and may delay or prevent the Merger from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. For example, on February 25, 2019, a shareholder of the Company filed a lawsuit against us, the members of our board, Denbury and the other entities involved in the Merger in the U.S. District Court for the Southern District of Texas, Houston Division. The plaintiff alleges that the registration statement filed by the defendants omitted material information with respect to the Merger, which renders such registration statement false and misleading, and is seeking, among other things, injunctive relief to prohibit the completion of the Merger and monetary damages in the form of plaintiff's costs to bring the lawsuit. Even if the lawsuits are without merit, such as the recently filed lawsuit described in the preceding sentence, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our ~~continuing~~liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, then that injunction may delay or prevent the Merger from being completed, which may adversely affect our and Denbury’s business, financial position and results of operation.

Uncertainties associated with the Merger may cause a loss of management personnel and other key employees, ~~making it difficult for~~which could adversely affect the future business and operations of the combined company.

We and Denbury are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plans. Each company’s success until the Merger and the combined company’s success after the Merger will depend in part upon the ability of us and Denbury to retain key management personnel and other key employees. Current and prospective employees of Denbury and the Company may experience uncertainty about their ~~services.~~roles within the combined company following the Merger, which may have an adverse effect on the ability of each of us and Denbury to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees of Denbury and the Company to the same extent that we and Denbury have previously been able to attract or retain their own employees.

Risk Factors Associated with our General Business

Prices for crude oil, NGLs and natural gas ~~prices~~ are dependent on many factors that are beyond our control.

Prices for crude oil, NGLs and natural gas are dependent on many factors that are beyond our control, including:

domestic and foreign supplies of crude oil, NGLs and natural gas;

domestic and foreign consumer demand for crude oil, NGLs and natural gas;

political and economic conditions in oil or gas producing regions;

the ~~ability of~~extent to which the members of the Organization of Petroleum Exporting Countries and other oil 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;

the effect of energy conservation efforts;

shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas and NGLs so as to minimize emissions of carbon dioxide and methane GHGs;

volatility and trading patterns in the commodity-futures markets;

technological advances affecting energy ~~consumption;~~consumption and energy supply;

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, cost, 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 gas;

weather conditions; and

domestic and foreign governmental relations, regulation and ~~taxation.~~taxation, including limits on the United States’ ability to export crude oil.

~~Our~~Oil and natural gas prices continued to be volatile in 2018. For example, the NYMEX oil prices in 2018 ranged from a high of $60.42 to a low of $42.53 per Bbl and the NYMEX natural gas prices in 2018 ranged from a high of $3.72 to a low of $2.56 per MMBtu. Further, the NYMEX oil prices and NYMEX natural gas prices reached highs of approximately $57 per Bbl and $3.60 per MMBtu, respectively, during the period from January 1, 2019, to February 22, 2019. It is impossible to predict future ~~performance depends~~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 ~~ability to find or acquire additional~~business, financial position, results of operations, cash flows and borrowing capacity, the quantities of oil and gas reserves that ~~are~~we can economically ~~recoverable.~~

~~Unless we successfully replace~~produce, the quantity of estimated proved reserves that ~~we produce,~~may be attributed to our ~~reserves will decline, eventually resulting in a decrease in oil~~properties and ~~gas production and lower revenues and cash flows from operating activities. We must make substantial~~our ability to fund our capital expenditures to find, acquire, develop and produce oil and gas reserves. Because of significantly low commodity prices, we may not be able to make the necessary capital investments to maintain or expand our oil and gas reserves with our cash flows from operating activities. Because of our financial and liquidity positions, external sources of capital are limited.program.

~~Our common stock has been delisted from the NYSE and will not be listed on any other national securities exchange in the near future.~~

We received notice from the NYSE that trading of our common stock was suspended at the opening of business on January 12, 2016, and the NYSE filed with the SEC to remove our common stock from listing and registration on the NYSE. As a result, our common stock now trades in the OTC Pink market under the ticker symbol “PVAH.” Securities traded in the OTC Pink market generally have significantly less liquidity than securities traded on a national securities exchange, due to factors such as the reduced number of investors that will consider investing in the securities, the reduced number of market makers in the securities, and the reduced number of securities analysts that follow such securities. As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all. Because of the limited market and generally low volume of trading in our common stock that could occur, the share price of our common stock could be more likely to be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the market’s perception of our business, and announcements made by us, our competitors or parties with whom we have business relationships. The lack of liquidity in our common stock may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future.

Exploration and development drilling 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~~exploration and production activities are subject to numerous risks beyond our control, including the risk that nodrilling will not result in commercially ~~productive~~viable oil orand gas ~~reserves will be found.~~production. The costs of drilling, completing and operating wells are often substantial and uncertain, and drilling and completion operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our ~~control. These factors include:~~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;

risks associated with drilling horizontal wells and extended lateral lengths, such as deviating from the desired drilling zone or not running casing or tools consistently through the wellbore, particularly as lateral lengths get longer;

fracture stimulation accidents or failures;

reductions in oil, natural gas and NGL prices;

elevated pressure or irregularities in geologic formations;

loss of title ~~problems;~~or other title related issues;

equipment failures or accidents;

costs, shortages or delays in the availability of drilling rigs, frac fleets, crews, equipment and materials;

shortages in experienced labor;

crude oil, NGLs or natural gas gathering, transportation, processing, storage and export facility 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, contractual and third-party approvals and ~~permits, including delays due to potential hydraulic fracturing regulations;~~permits;

political events, public protests, civil disturbances, terrorist acts or cyber attacks;

environmental hazards, such as natural gas leaks, oil and produced water 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.~~conditions; and

~~The prevailing prices~~actions by third-party operators of crude oil, NGLs and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. The availability of drilling rigs and equipment can vary significantly from region to region at any particular time. Although land drilling rigs can be moved from one region to another in response to changes in levels of demand, an undersupply of rigs in any region may result in drilling delays and higher drilling costs for the rigs that are available in that region.our properties.

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. The type curves we use in our development plans from time to time are only estimates of performance of the acreage we might develop and actual production can differ materially. 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 ~~wells~~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~~and we cannot be sure that our overall drilling success rate or our drilling success rate within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our business, financial condition, results of operations and cash flows. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. Although we have identified numerous potential drilling locations, we may not be able to economically produce oil or ~~natural~~ gas from all of them.

~~We are exposed to the credit risk of our customers,~~Multi-well pad drilling and ~~nonpayment or nonperformance by these parties would reduce our cash flows.~~

We are subject to risk from loss resulting from our customers’ nonperformance or nonpayment. We depend on a limited number of customers for a significant portion of revenues. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly affect our overall credit risk. Recently, many of our customers’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financingproject development may result in ~~a significant reduction~~volatility in our customers’ liquidity and ability to make payments or perform on their obligations to us. In 2015, approximately 64 percent of our total consolidated product revenues resulted from three of our customers. Any nonpayment or nonperformance by our customers would reduce our cash flows.operating results.

We ~~participate~~utilize multi-well pad drilling and project development where practical. Project development may involve more than one multi-well pad being drilled and completed at one time in a relatively confined area. Wells drilled on a pad or in a project may not be brought into production until all wells on the pad or project are drilled and completed. Problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi-well pad drilling and project development can cause delays in the scheduled commencement of production, or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing as well as declines in oil and natural gas prices. Further, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi-well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.

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 ~~with third parties~~ and ~~these third parties~~permits on reasonable terms for the prospects.

Although we have identified numerous drilling prospects, we may not be able to ~~fulfill their commitments to~~lease or drill those prospects within our ~~projects.~~

~~We frequently own less than 100%~~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 ~~the working interest in the~~commercially productive oil ~~and~~or gas ~~leases on which~~or that 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 notwill be able to ~~fulfill their joint venture obligations. Some~~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 ~~partners have experienced liquidity and cash flow problems. These problems have led and may lead our partners~~area or with respect to ~~continue to attempt to delay the pace of~~prospects wells within such project development in order to preserve cash. A partner may be unable or unwilling to pay its share of project costs. In some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial condition, results of operations and cash flows.

~~Our business and prospects for future success depend to a significant extent upon the continued service and performance of our management team.~~

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

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~~The unavailability, high cost or shortage of drilling ~~and completion operations on properties we operate.~~rigs, frac crews, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

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, ~~natural gas liquids~~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.

Moreover, the oil and 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, including geologists, geophysicists, engineers and other professionals. 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. 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 completion delays and higher well costs in that region.

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.

Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. 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.

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 adequately or 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.

14We 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 2018, approximately 69 percent of our total consolidated product revenues resulted from three of our customers. Any nonpayment or nonperformance by our customers would reduce our cash flows.

We participate in oil and gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.

We frequently own less than 100 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 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.~~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 factors and assumptions, including assumptions ~~required by the SEC~~ relating to crude oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, development costs and workover and remedial costs, the quantity, quality and interpretation of relevant data, 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 inherently uncertain, therefore, changes often occur as these variables evolve and commodity prices fluctuate. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Any material inaccuracies in these reserve estimates, cash flow estimates or underlying assumptions could materially affect the estimated quantities and present value of our reserves.

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

At December 31, ~~2015,~~2018, approximately 2562 percent of our estimated proved reserves were proved undeveloped, compared to 6056 percent at December 31, ~~2014.~~2017. Estimation of proved undeveloped reserves and proved developed non-producing reserves is based on volumetric calculations and adjacent reserve performance data. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. ~~Production revenues from proved developed non-producing reserves will not be realized until sometime in the future. The~~Our reserve data assumes that we can and will make these significant ~~capital~~ expenditures to develop our ~~reserves. Although we have prepared estimates of our~~ reserves and ~~the costs associated with~~conduct these ~~reserves in accordance with industry standards, 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. ~~We experienced negative revisions~~Accordingly, our reserve report at December 31, 2018, includes estimates of ~~45.6~~total future development costs over the next five years associated with our proved undeveloped reserves of approximately $1,175 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, 2018, we wrote-off 21.1 MMBOE ~~in 2015 due~~of proved undeveloped reserves because they are no longer expected to ~~fewer locations, lower EURs~~be developed within five years of their initial recording. Any such write-offs of our reserves could reduce our ability to borrow money and ~~lower prices compared to year-end 2014.~~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 decrease by 10%, our standardized measure and PV-10 would have decreased to approximately $1,325.7 million and $1,444.4 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 ~~impairment losses~~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 ~~impairment losses on certain properties~~a write-down that would further decrease reported earnings.

~~GAAP requires that the carrying value~~

The full cost method of accounting for oil and gas properties ~~be reviewed on a periodic basis for possible impairment. An impairment charge is recognized when~~under GAAP requires that at the ~~carrying value~~end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is ~~greater than~~limited to the ~~undiscounted~~sum of the estimated discounted future net ~~cash flows attributable to~~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 ~~property.~~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, ~~impairments~~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 ~~impair~~write down the value of certain of our oil and gas properties and related assets. We ~~recorded an impairment charge of approximately $1.4 billion during 2015. We~~ could experience additional ~~impairments~~write-downs in the future. ~~While an impairment charge reflects~~

If we cannot obtain sufficient capital when needed, we will not be able to continue with our business strategy.

The oil and gas industry is capital intensive. We incur and expect to continue to incur substantial capital expenditures for the acquisition, exploration and development of oil and gas reserves. We incurred approximately $533 million in acquisition, exploration and development costs during the year ended December 31, 2018. We intend to finance our future capital expenditures, other than significant acquisitions, through cash flow from operations and, if necessary, through borrowings under our credit facility. However, our cash flow from operations and access to capital are subject to a number of variables, including: (i) the volume of oil and gas we are able to produce from existing wells, (ii) our ability to ~~recover~~transport our oil and gas to market, (iii) the ~~carrying value~~prices at which our commodities are sold, (iv) the costs of producing oil and gas, (v) global credit and securities markets, (vi) the ability and willingness of lenders and investors to provide capital and the cost of the capital, (vii) our ~~investments, it does~~ability to acquire, locate and produce new reserves and (viii) our proved reserves.

We may not ~~impact our~~generate expected cash flows ~~from operating activities.~~

~~We have limited control over the activities on properties we do not operate.~~

In 2015, other companies operated approximately 15 percent of our net production. Our success in properties operated by others will depend upon a number of factors outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells, selection of technology and maintenance of safety and environmental standards. Wemay have limited ability to ~~influence~~obtain the capital necessary to sustain our operations at current or ~~control~~anticipated levels. A decline in cash flow from operations or our financing needs may require us to revise our capital program or alter or increase our capitalization substantially through the ~~operation~~issuance of debt or ~~future development~~equity securities. The issuance of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these propertiesadditional equity securities could have a ~~material adverse~~dilutive effect on the ~~realization~~value of our ~~targeted returns~~common stock. Additional borrowings under our credit facility or ~~lead~~the issuance of additional debt securities will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to ~~unexpected~~use cash flow to fund working capital, capital expenditures and acquisitions. In the future, ~~costs.~~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.

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.~~liabilities and the effect on our liquidity or financial leverage of using available cash or debt to finance acquisitions. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and the assumption of potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. A customary review of subject properties will not necessarily reveal all existing or potential problems.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties if they have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and systems, ~~and~~ that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results, and may cause us to not be able to realize any or all of the anticipated benefits of the acquisitions.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

Our initial technical reviews of properties we acquire are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well and environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with acquired properties, or discover unknown liabilities after the acquisition, and such risks and liabilities could have a material adverse effect on its results of operations and financial condition.

We ~~are~~may incur losses as a ~~relatively small company~~result of title deficiencies.

We purchase working and ~~therefore may not be able to compete effectively.~~

~~Compared to many of our competitors~~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, financial condition and cash flows. Title insurance covering mineral leaseholds is not generally available and, in all instances, we forgo 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 ~~are~~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.

As a small ~~company.~~ company, we face unique difficulties competing in the larger market.

We operate in a highly competitive environment for acquiring properties, marketing oil and gas and securing trained personnel, and we may 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. Those companies may be able to pay more for productive oil and gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Also, there is substantial competition for capital available for investment in the oil and gas industry. Our limited size has placed us at a disadvantage with respect to funding our capital and operating costs, and means that we are more vulnerable to commodity price volatility and overall industry cycles, are less able to absorb the burden of changes in laws and regulations, and that poor results in any single exploration, development or production play can have a disproportionately negative impact on us.

We also compete for people, including experienced geologists, geophysicists, engineers and other professionals. Our limited size has placed us at a disadvantage with respect to attracting and retaining management and other professionals with the technical abilities necessary to successfully operate our business.

Our lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with operating primarily in one major contiguous area.

~~Our current business is focused primarily~~All of our operations are in the Eagle Ford Shale in South ~~Texas.~~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, adverse weather conditions, water shortages or other drought related 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 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 $521 million of outstanding debt at December 31, 2018, including $321 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.

Our indebtedness and any increase in our level of indebtedness could have adverse effects on our financial condition, results of operations and cash flows, including (i) imposing additional cash requirements on us in order to support interest payments, which reduces the amount we have available to fund our operations and other business activities, (ii) increasing the risk that we may default on our debt obligations, (iii) increasing our vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in our business, (iv) limiting our ability to engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes and (v) limiting our flexibility in planning for or reacting to changes in our business and industry in which we operate. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are out of our control.

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 $450 million as of December 31, 2018. Our borrowing base is redetermined at least twice each year and is scheduled to next be redetermined in April 2019. If crude oil, NGL or natural gas prices decline, the borrowing base under the Credit Facility may be reduced. As a result, we may be unable to obtain funding under the Credit Facility. If funding is not available when or in the amounts needed, or is available only on unfavorable terms, it might adversely affect our development plan and our ability to make new acquisitions, each of which could have a material adverse effect on our production, financial condition, results of operations and cash flows.

The Credit Facility 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 ~~financial condition.~~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.~~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;~~pressures or structures;

pipeline ruptures or spills;

mechanical difficulties, such as stuck oilfield drilling and service tools;

uncontrollable flows of oil, natural gas or well fluids;

migration of fracturing fluids into surrounding groundwater;

spills or releases of fracturing fluids including from trucks sometimes used to deliver these materials;

spills or releases of brine or other produced water that may go off-site;

subsurface conditions that prevent us from (i) stimulating the planned number of stages, (ii) accessing the entirety of the wellbore with our tools during completion or (iii) removing all fracturing-related materials from the wellbore to allow production to begin;

environmental hazards such as natural gas leaks, oil or produced water spills and discharges of toxic gases; and

natural disasters and other adverse weather conditions, terrorism, vandalism and physical, electronic and cyber security breaches.

Any of these risks could result in substantial losses resulting from injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damages, ~~clean-up~~clean up responsibilities, regulatory investigations and penalties, loss of well location, acreage, expected production and related reserves 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.~~scarce, and we may face difficulty disposing of produced water gathered from drilling and production activities.

The availability of water is crucial to conduct hydraulic fracturing. A significant amount of water is necessary for drilling and completing each well with hydraulic ~~fracturing in Texas.~~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.

~~Our production may not satisfy the minimum gross volume requirements under~~ If we are unable to obtain water to use in our ~~gathering agreements with Republic Midstream, LLC, or Republic, and, as a result,~~operations from local sources, we may be ~~required~~unable to ~~make deficiency payments.~~economically produce oil and gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

We have entered into a gathering agreement with Republic that requires us to provide a minimum delivery commitment of 15,000 gross BOPD of crude oil. The commitment is for a 10 year term beginning once the system has been constructed and is operational, currently expected in the first half of 2016. Although our production and reserves are currently sufficient to fulfill the delivery commitment under the agreement, future oil production may not be sufficient to meet the minimum volume requirements. If we do not purchase volumes in the market or make other arrangements to satisfy the commitments, we would be required to make deficiency payments that total $1.75 per undelivered Bbl.

~~Laws~~

Climate change legislation, laws and regulations restricting emissions of greenhouse gases or legal or other action taken by public or private entities related to climate change 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~~began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. For example, the EPA ~~implemented~~issued rules requiring annual reporting of GHG emissions from specified large GHG emission sources in the United States for emissions occurring after January 1, 2010. In October 2015 the EPA released a final rule adding reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.

Moreover, the Obama administration has announced in its Climate Action Plan that it intends to adopt additional regulations to reduce emissions of GHGs in the coming years, likely including further restrictions on emissions of methane from oil and gas operations. More specifically, the EPA issued its final Clean Power Plan rules in August 2015 that establish carbon pollution standards for power plants, and has proposed New Source Performance Standards, or NSPS, to reducerestricting methane emissions from ~~the oil~~hydraulically fractured and refractured gas ~~industry. In addition, the U.S.~~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.”

While Congress has from time to time considered ~~adopting~~ legislation to reduce emissions of GHGs, ~~and almost one-half~~there has not been significant activity in the form of ~~the states have already taken legal measures~~adopted legislation to reduce emissions of GHGs ~~primarily through~~in recent years. In the ~~planned development~~absence of Congressional action, many states have established rules aimed at reducing GHG emissions, including 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. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission ~~inventories and/~~reduction goal. In the future, the United States may also choose to adhere to international agreements targeting GHG reductions. The adoption of legislation or ~~regional GHG cap-and-trade programs. See Item 1, “Business – Government Regulation~~regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and ~~Environmental Matters.”~~operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, results of operations and cash flows. Reduced demand for the oil and gas that we produce could also have the effect of lowering the value of our reserves.

In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our financial condition, results of operations and cash flows. For a more complete discussion of environmental laws and regulations intended to address climate change and their impact on our business and operations, ~~please~~ see Part I, Item 1, “Business – - Environmental Regulation –- Climate ~~Change.~~Change.”

18There have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Federal state and ~~state~~local legislation and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or ~~delays.~~delays and adversely affect our production.

~~The practice of hydraulic fracturing has come under increased scrutiny by the environmental community.~~ Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into ~~prospective~~ rock formations to stimulate oil and gas production. We routinely use ~~this completion technique on all of our~~hydraulic fracturing to complete wells. The EPA ~~is studying~~released the final results of its comprehensive research study on the potential ~~environmental~~adverse impacts ofthat hydraulic fracturing ~~and its potential impact on drinking water resources. The EPA released a draft report in June 2015, which stated that EPA had not found evidence of widespread, systemic impacts~~may have on drinking water resources ~~from~~in December 2016. The EPA concluded that hydraulic fracturing ~~operations. This report has not yet been finalized,~~activities can impact drinking water resources under some circumstances, including large volume spills and ~~the EPA’s ultimate conclusions may be impacted by recent comments from the EPA’s Science Advisory Board regarding the sufficiency~~inadequate mechanical integrity of ~~the data underlying some~~wells. The results of the EPA’s ~~conclusions.~~study could spur action towards federal legislation and regulation of hydraulic fracturing or similar production operations. In ~~May 2014,~~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. The EPA has also issued final regulations under the CAA establishing performance standards, including standards for the capture of VOCs and methane released during hydraulic fracturing; an ~~advance~~advanced notice of proposed rulemaking ~~relating~~under the Toxic Substances Control Act to require companies to disclose information regarding the ~~collection of information on various~~ chemicals ~~and mixtures~~ used in hydraulic ~~fracturing. The EPA has issued~~fracturing; and final rules ~~under~~in June 2016 to prohibit the ~~CAA that subject oil and natural gas production, processing, transmission, and storage~~discharge of wastewater from hydraulic fracturing operations to ~~regulation under the NSPS~~publicly owned wastewater treatment plants. In addition, a number of states and ~~National Emission Standards for Hazardous Air Pollutants,~~local regulatory authorities are considering or ~~NESHAP, programs. The EPA has proposed additional NSPS regulations~~have implemented more stringent regulatory requirements applicable to hydraulic

fracturing, including bans/moratoria on drilling that effectively prohibit further production of ~~volatile organic compound and methane emissions from the~~ oil and gas ~~industry,~~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, and the RRC has ~~released draft guidance~~also adopted rules governing well casing, cementing and other standards for ensuring that ~~could potentially extend~~hydraulic fracturing operations do not contaminate nearby water resources. Moreover, the legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such ~~requirements to existing oil and gas sources in ozone non-attainment areas.~~

disposal activities. 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 ~~regulators are also considering additional requirements related~~wells in an effort to reduce seismic ~~safety for hydraulic fracturing activities. In addition, some states and local governments have enacted legislation or adopted regulations, and the~~activity. A 2015 U.S. ~~Congress and other states are considering enacting legislation or adopting regulations,~~Geological Survey report identified areas of increased rates of induced seismicity that could ~~impose more stringent permitting, disclosure, monitoring,~~be attributed to fluid injection or oil and gas extraction. Another consequence of seismic events may be lawsuits alleging that disposal well ~~construction~~operations have caused damage to neighboring properties or otherwise violated state and ~~water use requirements on hydraulic fracturing operations.~~

~~Individually or collectively, such new legislation or regulation~~federal rules regulating waste disposal. These developments could result in ~~increased compliance~~additional regulation and operating costs, delays or additional operating restrictions. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. While we do not believe that compliance with such requirements will have a material adverse effect on our operations, these requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations, any of which could be significant.

If the use of injection wells by us. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil, natural gas and natural gas liquids activities utilizing injection wells for produced water disposal.

The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing ~~is limited, prohibited or subjected~~process could make it more difficult to ~~further regulation, these requirements could delay or effectively prevent the extraction of~~complete oil and gas ~~from formations~~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 ~~would not be economically viable without the use of hydraulic fracturing. This~~ could ~~have a material adverse effect on~~adversely affect our business ~~financial condition,~~and results of ~~operations and cash flows.~~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 ~~two~~three years or less. While intended to reduce the effects of volatile crude oil, NGL and natural gas prices, such transactions may limit our potential gains if crude oil, NGL or natural gas prices were to rise over the price established by the hedging arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how ~~crude oil, NGL or natural gas~~commodity prices fluctuate in the ~~future.~~future, which could have the effect of reducing our net income.

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

our production is less than expected;

there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

the ~~counterparties~~counterparty to ~~our futures contracts fail~~a derivatives instrument fails to perform under the ~~contracts;~~contract; or

a sudden, unexpected event materially impacts ~~crude oil, NGL or natural gas~~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.

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 or implemented, and it is not possible at this time to predict when this will be accomplished. 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 for bona fide hedging transactions, though these rules have not been finalized and the impact of those provisions on us is uncertain at this time.

While the CFTC has designated certain interest rate swaps and credit default swaps subject to mandatory clearing, and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules subjecting any other classes of swaps, including physical commodity swaps, to mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If our swaps do not qualify for the commercial end-user exception from mandatory clearing, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or our ability to hedge may be impacted. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time.

In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to be exempt from such requirements for the mandatory exchange of margin for uncleared swaps, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. Further, if we do not qualify for an exemption and are required to post collateral for our swaps, it could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows.

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 reduce 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%5 percent shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than ~~50%~~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, ~~2015,~~2018, 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, U.S. NOLs generated on or after January 1, 2018, can be limited to 80 percent of taxable income. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.

~~Future legislation may result in the elimination of certain U.S.~~Certain federal income tax deductions currently available with respect to oil and ~~natural~~ gas exploration and ~~production. Additionally, future federal or~~development may be eliminated. Additional state ~~legislation may impose new or increased~~ taxes ~~or fees~~ on oil and ~~natural~~ gas ~~extraction.~~extraction may be imposed, as a result of future legislation.

~~Potential legislation, if enacted into law, could make~~In recent years, lawmakers and Treasury have proposed certain significant changes to U.S. ~~federal and state income~~ tax laws ~~including the elimination of certain key U.S. federal income tax incentives currently available~~applicable to oil and gas ~~exploration and production~~ companies. These changes include, but are not limited ~~to,~~to: (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; ~~(iii) the elimination of the deduction for certain U. S. production activities~~ and ~~(iv)~~(iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether ~~these or similar~~any such changes will be enacted ~~and,~~or if enacted, ~~how soon any~~when such changes could ~~become~~be effective. ~~The passage of this legislation or~~If such proposed changes are ever made, as well as any ~~other~~ similar changes in ~~U.S. federal income and~~ state ~~income tax laws~~law, it could eliminate or postpone 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, ~~and~~ results of ~~operations.~~ operations and cash flows.

Additionally, future legislation could be enacted that increases the taxes ~~states impose~~or fees imposed on oil and ~~natural~~ gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government for Fiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced and imported petroleum products. The fee would be phased in evenly over five years beginning October 1, 2016. The adoption of this, or similar proposals, wouldAny 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 ~~oil.~~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 ~~in the future~~ allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, ~~and~~ results of operations and cash flows could be adversely affected.

A ~~cyber~~cybersecurity 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 ~~not to be sufficient,~~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. These cybersecurity threat actors are becoming more sophisticated and coordinated in their attempts to access a company’s information technology systems and data, including the information technology systems of cloud providers and third parties with which a company conducts business. 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. A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including but not limited to, the following:

Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;

A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;

A cyber attack on third-party gathering, pipeline, or other transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;

A cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market;

A cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

A cyber attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;

A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and

A cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.

Additionally, certain cyber incidents may remain undetected for an extended period. 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. Furthermore, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

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; and

our ability to attract and retain customers may be negatively impacted.

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.”

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 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 and the full cost method of accounting for oil and gas properties, 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. The pending

Merger may also cause volatility in the trading of our common stock. 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.

Our business and the trading prices of our securities could be negatively affected as a result of actions of so-called “activist” shareholders, and such activism could impact the trading value of our securities.

Shareholders may from time to time attempt to effect changes, engage in proxy solicitations or advance shareholder proposals. Activist shareholders may make strategic proposals, suggestions or requested changes concerning our operations, strategy, management, assets or other matters. If we become the subject of activity by activist shareholders, responding to such actions could be costly and time-consuming, diverting the attention of our management and employees. Furthermore, activist campaigns can create perceived uncertainties as to our future direction, strategy, or leadership and may result in the loss of potential business opportunities and cause our stock price to experience periods of volatility.

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, or the perception that these sales could occur, 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

We have received no written SEC staff comments regarding our periodic or current reports under the Exchange Act that were issued 180 days or more preceding the end of our 2015 fiscal year and remain unresolved.None.


Item 2	Properties

As of December 31, ~~2015,~~2018, our ~~primary~~ oil and gas assets ~~are~~were located in Gonzales, Lavaca, Fayette and ~~Lavaca~~Dewitt Counties in South ~~Texas and Washita and Custer Counties in Western Oklahoma.~~Texas.

Facilities

~~All of our~~Our corporate headquarters and field office facilities are leased and we believe that ~~our facilities~~they 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.

Summary of Oil and Gas Reserves

Proved Reserves

The following tables summarize certain information regarding our estimated proved reserves as of December 31 for each of the years presented:

Crude Oil NGLs
Natural
Gas

Oil
Equivalents

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

Developed

Producing 19.6
6.1
36.8
31.8
$ 325.6
$ 325.6
Non-producing 0.6
0.1
0.4
0.8
4.3
4.3
20.2
6.2
37.2
32.6
329.9
329.9
Undeveloped 9.3
1.0
5.0
11.1
(6.6 ) (6.6 )
29.5
7.2
42.2
43.7
$ 323.3
$ 323.3

Price measurement used ¹
$45.78/Bbl
$13.15/Bbl
$2.70/MMBtu

2014

Developed
Producing 21.8
7.4
77.9
42.1
$ 794.9
$ 989.9
Non-producing 0.3
0.7
16.6
3.8
8.6
10.7
22.1
8.1
94.5
45.9
803.5
1,000.6
Undeveloped 47.0
11.1
64.7
68.9
378.9
471.9
69.0
19.2
159.2
114.8
$ 1,182.4
$ 1,472.5

Price measurement used ¹
$92.91/Bbl
$25.49/Bbl
$4.32/MMBtu

2013
Developed
Producing 19.0
7.5
146.5
50.9
$ 701.7
$ 953.1
Non-producing 0.3
1.0
16.7
4.1
7.3
9.9
19.3
8.5
163.2
55.0
709.0
963.0
Undeveloped 41.4
13.4
158.9
81.3
554.8
753.6
60.7
21.9
322.1
136.3
$ 1,263.8
$ 1,716.6

Price measurement used ¹
$103.11/Bbl
$31.10/Bbl
$3.47/MMBtu

~~___________________~~



	Crude Oil	NGLs	Natural Gas	Oil Equivalents	Standardized Measure		PV10 ¹
	(MMBbl)	(MMBbl)	(Bcf)	(MMBOE)	$ in millions		$ in millions
2018
Developed			��
Producing	35.2	6.3	31.8	46.8
Non-producing	—	—	—	—
	35.2	6.3	31.8	46.8
Undeveloped	54.5	11.7	59.7	76.2
	89.7	18.0	91.5	123.0	$	1,623.9	$	1,769.4

Price measurement used	$65.56/Bbl	$23.60/Bbl	$3.10/MMBtu

2017
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	$51.34/Bbl	$18.48/Bbl	$2.98/MMBtu

2016
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	$42.75/Bbl	$12.33/Bbl	$2.48/MMBtu

¹~~Crude~~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 did not include any income tax effect. Accordingly, our PV10 and Standardized Measure values were equivalent as of that date. 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 ~~natural~~ gas ~~prices were based on average (beginning of month basis) sales prices per Bbl~~properties as well as evaluating properties for potential purchases and ~~MMBtu. The representative prices of crude oil~~sales.

A discussion and ~~natural gas were adjusted for basis differentials to arrive at the appropriate net price. NGL prices were estimated as a percentage~~analysis of the ~~base crude oil price.~~

~~All of~~changes in our ~~reserves are located in the continental United States. The following table sets forth by region the estimated quantities of~~total proved reserves is provided in “Supplemental Information on Oil and ~~the percentages thereof that are represented by proved developed reserves as of December 31, 2015:~~

Proved
% of Total
Proved
% Proved
Region Reserves Reserves Developed
(MMBOE)

South Texas 40.1
92 % 72 %
Mid-Continent and other ¹
3.6
8 % 100 %
43.7
100 % 75 %

~~___________________~~

¹Gas Producing Activities (Unaudited)~~Includes approximately 0.1 MMBOE attributable to our three active Marcellus Shale wells.~~” included in Part II, Item 8, “Financial Statements and Supplementary Data.”

Proved Undeveloped Reserves

The proved undeveloped reserves included in our reserve estimates relate to wells that are forecasted to be drilled within the next ~~three years, assuming availability of capital.~~five years. The following ~~tables set~~table sets forth the changes in our proved undeveloped reserves during the year ended December 31, ~~2015 and the total proved undeveloped reserves as of December 31, 2015 by region:~~2018:


	Crude Oil		NGLs		Natural Gas		Oil Equivalents		Crude Oil		NGLs		Natural Gas		Oil Equivalents
	(MMBbl)		(MMBbl)		(Bcf)		(MMBOE)		(MMBbl)		(MMBbl)		(Bcf)		(MMBOE)
Proved undeveloped reserves at beginning of year	47.0		11.1		64.7		68.9		33.4		4.0		20.1		40.8
Revisions of previous estimates	(30.8	)	(7.9	)	(41.4	)	(45.6	)	(13.9	)	(1.4	)	(7.2	)	(16.5	)
Extensions, discoveries and other additions	1.2		0.1		0.6		1.4
Sale of reserves in place	(1.5	)	(0.4	)	(9.5	)	(3.5	)
Extensions and discoveries									42.0		10.4		52.7		61.1
Purchase of reserves									3.7		0.2		1.2		4.1
Conversion to proved developed reserves	(6.6	)	(1.9	)	(9.4	)	(10.1	)	(10.7	)	(1.4	)	(7.1	)	(13.3	)
Proved undeveloped reserves at end of year	9.3		1.0		5.0		11.1		54.5		11.8		59.7		76.2

South Texas	9.3		1.0		5.0		11.1
Mid-Continent and other	—		—		—		—
	9.3		1.0		5.0		11.1

In ~~2015,~~2018, our proved undeveloped reserves ~~decreased~~increased by ~~57.8~~35.4 MMBOE. WeThe overall increase over our proved undeveloped reserves at the end of 2017 is due primarily to a significant shift in our development plans from the northwest portion of our acreage position in the Eagle Ford to the southeast region. The performance of our wells drilled in the southeast region in the first half of the year was the impetus to our redirecting of resources and replication, to the extent practical, of our drilling and completion design techniques for the second half of 2018. Of the 53 gross wells we drilled in 2018, 19 gross wells were not proved undeveloped locations at the end of 2017. Accordingly, our five-year drilling plan is currently heavily weighted to the southeast region.

The shift in focus is reflected in the changes as follows: we experienced net negative revisions of ~~45.6~~16.5 MMBOE including: (i) 21.1 MMBOE due to ~~fewer~~the loss of certain locations ~~lower EURs~~resulting from changes in the drilling locations and ~~lower prices compared to year-end 2014. Extensions, discoveries and other additions of 1.4 MMBOE were~~timing attributable to our development ~~activities~~plans as discussed above partially offset by (ii) 4.1 MMBOE due to improved treatable lateral lengths in ~~Eagle Ford.~~certain locations due primarily to reconfiguration of the planned drilling units and (iii) 0.5 MMBOE of other changes, primarily price-related. Extensions and discoveries of 61.1 MMBOE are substantially attributable to geographical shift in our development plan, greater utilization of extended reach laterals, increasing the length of such laterals, higher EUR estimates per lateral foot and higher net revenue interests due to the Hunt Acquisition. We ~~sold our Haynesville Shale and Cotton Valley assets~~acquired 4.1 MMBOE in ~~East Texas as well as certain non-core Eagle Ford properties resulting in decreases of 2.0 MMBOE and 1.5 MMBOE.~~connection with the Hunt Acquisition. In addition, we converted ~~10.1~~13.3 MMBOE from proved undeveloped to proved developed reserves in the Eagle Ford. During ~~2015,~~2018, we incurred capital expenditures of ~~approximately $222.6~~$204.2 million attributable to 34 gross (28.7 net) wells in connection with the conversion of proved undeveloped reserves to proved developed reserves. While our conversion rate for proved undeveloped reserves improved to 33 percent in 2018 from 21 percent in 2017, it was nonetheless impacted by the aforementioned shift in the focus of the development plan during 2018.

Preparation of Reserves Estimates and Internal Controls

The proved reserve estimates were prepared by DeGolyer and MacNaughton, Inc., our independent third party petroleum engineers. For additional information regarding estimates of proved reserves and other information about our oil and gas reserves, see ~~the~~ “Supplemental Information on Oil and Gas Producing Activities (Unaudited)” in our Notes to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data” and the report of DeGolyer and MacNaughton, Inc., dated ~~February 3, 2016,~~January 28, 2019, which is included as an Exhibit to this Annual Report on Form 10-K. We did not file any reports during the year ended December 31, ~~2015~~2018 with any federal authority or agency with respect to our estimate of oil and gas reserves.

Our policies and practices regarding the recording of reserves are structured to objectively and accurately estimate our oil and gas reserve quantities and present values in compliance with the SEC’s regulations and GAAP. Our Vice President, ~~Operations &~~ Engineering is primarily responsible for overseeing the preparation of the reserve estimate by DeGolyer and MacNaughton, Inc. Our Vice President, ~~Operations &~~ Engineering has over 30 years of industry experience in the estimation and evaluation of reserve information, holds a B.S. degree in Petroleum Engineering from Texas A&M University and is licensed by the State of Texas as a Professional Engineer. Our internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. For additional information about the risks inherent in our estimates of proved reserves, see Part I, Item 1A, “Risk Factors.”

Qualifications of Third Party Petroleum Engineers

The technical person primarily responsible for review of our reserve estimates at DeGolyer and MacNaughton, Inc. meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton, Inc. is an independent firm of petroleum engineers, geologists, geophysicists and ~~petro physicists;~~petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

Oil and Gas Production, Production Prices and Production Costs

In the tables that follow, we have presented our former operations in the ~~Haynesville Shale and Cotton Valley in East Texas and Selma Chalk in Mississippi,~~Mid-Continent, which were sold in ~~2015 and 2014~~2018, as “Divested properties.” The ~~sales~~sale of those operations represented a complete ~~divestitures~~divestiture and we have retained no interests therein. The production associated with our former Marcellus Shale properties through August 2016 is also included within “Divested properties.” Our remaining operations are exclusively represented in the Eagle Ford in South ~~Texas, the Granite Wash in Oklahoma and relatively minor operations in the Marcellus Shale in Pennsylvania.~~Texas.

Oil and Gas Production by Region

The following tables set forth by region our total production and average daily production for the periods presented:

Total Production
for the Year Ended December 31,
Region 2015 2014 2013

(MBOE)
South Texas ¹
6,995
5,913
4,091
Mid-Continent and other ²
479
765
962
Divested properties ³
449
1,256
1,771

7,923
7,934
6,824

Average Daily Production
for the Year Ended December 31,
Region 2015 2014 2013
(BOEPD)
South Texas ¹
19,165
16,201
11,208
Mid-Continent and other ²
1,311
2,096
2,636
Divested properties ³
1,847
3,441
4,852
22,323
21,738
18,696



	Total Production
	Successor			Predecessor
			September 13 Through	January 1 Through
	Year Ended December 31,		December 31,	September 12
Region	2018	2017	2016	2016
	(MBOE)			(MBOE)
South Texas	7,780	3,487	937	3,071
Divested properties ¹	165	292	103	276
	7,944	3,779	1,039	3,346

	Average Daily Production
	Successor			Predecessor
			September 13 Through	January 1 Through
	Year Ended December 31,		December 31,	September 12
Region	2018	2017	2016	2016
	(BOEPD)			(BOEPD)
South Texas	21,314	9,553	8,515	11,995
Divested properties ¹	451	800	934	1,076
	21,765	10,353	9,449	13,071

¹~~Includes~~Represents total production and average daily production of our former Mid-Continent operations for all periods presented and approximately 9210 MBOE ~~(303 BOEPD), 96 MBOE (264 BOEPD) and 33 MBOE (90~~(48 BOEPD) for ~~2015, 2014 and 2013, respectively, attributable to certain non-core Eagle Ford properties that we sold in October 2015.~~

²Includes total production and average daily production of approximately 19 MBOE (61 BOEPD), 22 MBOE (61 BOEPD) and 29 MBOE (81 BOEPD) for 2015, 2014 and 2013, respectively, attributable to certain Mid-Continent properties that we sold in October 2015. Also includes total production and average daily production of approximately 22 MBOE (60 BOEPD), 24 MBOE (66 BOEPD) and 25 MBOE (67 BOEPD) for 2015, 2014 and 2013, respectively,2016 attributable to our ~~three~~then active Marcellus Shale wells.

³We sold all of our properties in the Haynesville Shale and Cotton Valley in East Texas in August 2015, which represented total production and average daily production of approximately 449 MBOE (1,847 BOEPD), 844 MBOE (2,311 BOEPD) and 1,020 MBOE (2,794 BOEPD) in 2015, 2014 and 2013, respectively. We sold all of our properties in the Selma Chalk in Mississippi in July 2014, which represented annual production and average daily production of approximately 412 MBOE (1,946 BOEPD) and 751 MBOE (2,058 BOEPD) in 2014 and 2013.

Production Prices and Production Costs

The following table sets forth the average sales prices per unit of volume and our average production costs, not including ad valorem and production/severance taxes, per unit of production for the periods presented:


							Successor						Predecessor
											September 13 Through		January 1 Through
	Year Ended December 31,						Year Ended December 31,				December 31,		September 12
	2015		2014		2013		2018		2017		2016		2016
Average prices:
Crude oil ($ per Bbl)	$	44.81	$	91.50	$	101.13	$	66.23	$	50.96	$	46.68	$	35.21
NGLs ($ per Bbl)	$	12.24	$	31.14	$	31.30	$	20.99	$	19.25	$	16.56	$	11.37
Natural gas ($ per Mcf)	$	2.62	$	4.44	$	3.64	$	3.08	$	2.89	$	2.81	$	2.06
Aggregate ($ per BOE)	$	33.19	$	64.64	$	63.11	$	55.33	$	42.20	$	37.19	$	27.99
Average production and lifting cost ($ per BOE):
Lease operating	$	5.36	$	6.09	$	5.20	$	4.52	$	5.76	$	5.13	$	4.67
Gathering processing and transportation	3.01		2.31		1.88		2.34		2.84		2.93		3.96
	$	8.37	$	8.40	$	7.08	$	6.86	$	8.60	$	8.06	$	8.63

Significant Fields

Our properties in the Eagle Ford in South Texas, which contain primarily crude oil reserves, represented ~~approximately 92 percent~~all of our total equivalent proved ~~reserve quantities~~reserves as of December 31, ~~2015.~~2018.

The following table sets forth certain information with respect to this field for the periods presented:

Year Ended December 31,
2015 2014 2013
Production:

Crude oil (MBbl) 4,817
4,450
3,197
NGLs (MBbl) 1,170
773
478
Natural gas (MMcf) 6,026
4,070
2,406
Total (MBOE) 6,991
5,901
4,077
Percent of total company production 88 % 74 % 60 %
Average prices:
Crude oil ($ per Bbl) $ 44.79
$ 90.57
$ 101.55
NGLs ($ per Bbl) $ 11.04
$ 25.23
$ 26.68
Natural gas ($ per Mcf) $ 2.64
$ 4.20
$ 3.52
Aggregate ($ per BOE) $ 34.98
$ 74.49
$ 84.85
Average production and lifting cost ($ per BOE)¹:

Lease operating $ 5.04
$ 5.36
$ 4.30
Gathering processing and transportation 2.66
1.76
1.08
$ 7.70
$ 7.12
$ 5.38

~~______________~~

¹~~Excludes production/severance and ad valorem taxes.~~



	Successor									Predecessor
							September 13 Through			January 1 Through
	Year Ended December 31,						December 31,			September 12
	2018			2017			2016			2016
Production:
Crude oil (MBbl)	6,050			2,716			695			2,265
NGLs (MBbl)	944			418			130			449
Natural gas (MMcf)	4,713			2,120			674			2,141
Total (MBOE)	7,780			3,487			937			3,071
Percent of total company production	98		%	92		%	90		%	92		%
Average prices:
Crude oil ($ per Bbl)	$	66.24		$	51.08		$	46.73		$	35.24
NGLs ($ per Bbl)	$	21.10		$	18.13		$	14.82		$	10.34
Natural gas ($ per Mcf)	$	3.16		$	2.95		$	2.79		$	2.05
Aggregate ($ per BOE)	$	55.99		$	43.74		$	38.71		$	28.94
Average production and lifting cost ($ per BOE):
Lease operating	$	4.47		$	5.79		$	5.39		$	4.58
Gathering processing and transportation	2.27			2.49			2.58			3.50
	$	6.74		$	8.28		$	7.97		$	8.08

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, ~~2015, 2014~~2018, 2017 and ~~2013,~~2016, respectively, and wells that were in progress at the end of each year. There were no exploratory wells drilled in any of the years presented. The number of wells drilled refers to the number of wells completed at any time during the year, regardless of when drilling was initiated.

2015 2014 2013
Gross Net Gross Net Gross Net
Development

Productive 61
38.6
83
50.8
58
34.1
Dry well —
—
1
0.8
—
—
Under evaluation —
—
—
—
1
0.5

Total 61
38.6
84
51.6
59
34.6

Wells in progress at end of year¹
4
2.3
28
14.3
16
11.5



	2018		2017		2016
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	53	45.5	29	16.9	5	2.9
Dry well ¹	—	—	1	0.7	—	—
Total	53	45.5	30	17.6	5	2.9

Wells in progress at end of year ²	11	10.2	11	8.2	5	2.6

~~___________~~¹Represents the Zebra Hunter 05H well in the northern portion of our Eagle Ford acreage.

¹²Includes two gross ~~(1.7~~(2.0 net) wells completing, ~~one~~four gross ~~(0.3~~(3.8 net) ~~well~~wells waiting on completion and ~~one~~five gross ~~(0.3~~(4.4 net) ~~well~~wells being drilled as of December 31, ~~2015.~~2018.

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

2015 2014 2013
Region Gross Net Gross Net Gross Net
South Texas 61
38.6
84
51.6
57
34.1
Mid-Continent and other —
—
—
—
2
0.5
61
38.6
84
51.6
59
34.6

Present Activities

As of December 31, ~~2015,~~2018, we had ~~four~~11 gross ~~(2.3~~(10.2 net) wells in ~~progress, all of which were located in the Eagle Ford in South Texas.~~progress. As of ~~March 4, 2016, all~~February 22, 2019, four gross (4.0 net) wells were completing and six gross (5.4 net) wells were in process of ~~these wells had been successfully completed and were producing.~~being drilled by three operated rigs.

Delivery Commitments

We generally sell our oil, NGL and natural gas products using short-term floating price physical and spot market contracts. We have commitments to provide minimum deliveries of crude oil of ~~15,000~~8,000 BOPD (gross) in our South Texas region ~~for a period of ten years~~through 2031 under a gathering ~~agreement~~and transportation agreements with Republic Midstream, LLC, or ~~Republic. This commitment is for a 10 year term beginning once the system has been constructed and is operational, currently expected in the first half of 2016. Although, our~~Republic Midstream. Our production and reserves are currently sufficient to fulfill the current 8,000 BOPD delivery commitment under these agreements. In 2016, following the ~~agreement, future oil production may not be sufficient to meet the minimum volume requirements. If~~suspension of our drilling program, we ~~do not purchase volumes in the market or make other arrangements to satisfy the commitments, we would be required to make deficiency payments that total $1.75 per undelivered Bbl.~~

~~We also have a contractual obligation~~incurred charges for ~~certain firm transportation capacity in the Appalachian region that expires in 2022 and,~~deficiencies of $0.4 million as a result of ~~the sale of~~ our ~~natural gas assets in West Virginia, Kentucky and Virginia in 2012, we no longer have production~~inability to satisfy ~~this commitment. While we sell~~the 15,000 BOPD delivery commitment under such agreements prior to their August 2016 amendments in connection with our unused firm transportation to the extent possible, we recognized an obligation in 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract. The undiscounted amount payable on an annual basis for the each of the next five years is $2.7 million and a combined amount of $4.6 million is expected to be payable for 2021 through expiration in 2022.emergence from bankruptcy.

Productive Wells

The following table sets forth ~~by region the~~our productive wells in which we had a working interest as of December 31, ~~2015:~~2018:

Primarily Oil Primarily Natural Gas Total
Region Gross Net Gross Net Gross Net
South Texas ¹
332
209.7
—
—
332
209.7
Mid-Continent and other 2
1.5
98
43.5
100
45.0
334
211.2
98
43.5
432
254.7

¹~~Includes wells in the Austin Chalk.~~

Primarily Oil

Primarily Natural Gas

Total

Gross

Net

Gross

Net

Gross

Net

Total productive wells

458

375.5

2.0

460

377.5

Of the total wells presented in the table above, we are the operator of ~~333~~448 gross ~~(299~~(446 oil and 34two natural gas) and ~~220~~375.6 net ~~(198.3~~(373.6 oil and ~~21.7~~2.0 natural gas) wells. In addition to the above working interest wells, we own overriding royalty interests in 913 gross wells.

Acreage

The following table sets forth ~~by region~~ our developed and undeveloped acreage as of December 31, ~~2015~~2018 (in thousands):

Developed Undeveloped Total
Region Gross Net Gross Net Gross Net
South Texas 75.6
48.3
61.4
51.7
137.0
100.0
Mid-Continent and other 16.9
8.4
12.0
11.9
28.9
20.3
92.5
56.7
73.4
63.6
165.9
120.3

Developed

Undeveloped

Total

Gross

Net

Gross

Net

Gross

Net

Total acreage

89.9

76.9

8.3

7.3

98.2

84.2

The primary terms of our leases generally range from three to five years and we do not have any concessions. As of December 31, ~~2015,~~2018, our net undeveloped acreage is scheduled to expire as shown in the table below, unless the primary lease terms are, where appropriate, extended, HBP or otherwise changed:

2016 2017 2018 Thereafter
Percent of gross undeveloped acreage 43 % 35 % 8 % 14 %
Percent of net undeveloped acreage 45 % 31 % 6 % 18 %



	2019	2020	2021	Thereafter
Expirations by year	0.7	5.5	0.9	0.2

We anticipate paying options to extend a substantial portion of the acreage scheduled to expire in 2019. We do not believe that the remaining scheduled ~~expiration~~expirations of our undeveloped acreage will substantially affect our ability or plans to conduct our exploration and development activities.


Item 3	Legal Proceedings

On May 12, 2016, 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. On November 20, 2018, the Bankruptcy Court issued a final decree to close the case. See Note 144 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data,” for a more detailed discussion of our ~~legal contingencies.~~bankruptcy proceedings and emergence.

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 ~~contemplated~~threatened to be brought against us, under the various environmental protection statutes to which we are subject.


Item 4	Mine Safety Disclosures

Not applicable.

Part II


Item 5	Market for Registrant’s Common Equity, Related ~~Shareholder~~Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

~~On January 13,~~Since December 28, 2016, our common stock ~~began trading~~has been listed and traded on the ~~OTC Pink~~Nasdaq under the symbol ~~“PVAH.” Prior to being suspended from trading on January 12, 2016, our common stock was traded on the NYSE under the symbol “PVA.~~“PVAC.”

~~The high and low sales prices (composite transactions) related to each fiscal quarter in 2015 and 2014, as reported by the NYSE, were as follows:~~

Sales Price
Quarter Ended High Low
December 31, 2015 $ 1.23
$ 0.26
September 30, 2015 $ 4.39
$ 0.53
June 30, 2015 $ 8.03
$ 3.87
March 31, 2015 $ 7.91
$ 4.55
December 31, 2014 $ 12.89
$ 4.32
September 30, 2014 $ 17.20
$ 11.53
June 30, 2014 $ 18.20
$ 13.54
March 31, 2014 $ 18.04
$ 8.91

Equity Holders

As of February ~~26, 2016,~~19, 2019, there were ~~366~~91 record holders ~~and 16,483 beneficial owners (held in street name)~~ of our common stock.

Dividends

We have not ~~in the last three fiscal years,~~paid nor do we intend in the foreseeable future to pay any cash dividends on our common stock. ~~Additionally, pursuant to the Eleventh Amendment,~~Furthermore, we are ~~no longer permitted to make payments of~~restricted from paying dividends ~~on our common stock.~~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 ~~Shareholder~~Stockholder Matters” and Note 1617 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 ~~2015.~~2018.

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

Performance Graph

The following graph compares our ~~five-year~~ cumulative total shareholder return ~~(assuming reinvestment of dividends)~~ with the cumulative total return of the Standard & Poor’s 600 Oil & Gas Exploration &and Production Index and the Standard & Poor’s ~~Small Cap~~SmallCap 600 ~~Index.~~Index for the period from November 15, 2016 (the date that our common shares became publicly tradeable) through December 31, 2018. As of December 31, ~~2015,~~2018, there were nine exploration and production companies in the Standard & Poor’s 600 Oil & Gas Exploration &and Production Index: ~~Bill Barret Corporation,~~ Bonanza Creek Energy ~~Inc,~~Inc., Carrizo Oil & Gas, Inc., ~~Contango Oil & Gas Company, Northern Oil & Gas,~~Denbury Resources Inc., Gulfport Energy Corporation, Highpoint Resources Corporation, Laredo Petroleum Inc., PDC Energy Inc., ~~Rex~~Ring Energy ~~Corporation, Stone~~Inc. and SRC Energy ~~Corporation and Synergy Resources Corporation.~~Inc. The graph assumes $100 is invested on ~~January 1, 2011~~November 15, 2016 in us and each index at ~~December 31, 2010~~November 15, 2016 closing prices.

The following table represents the actual data points for the dates indicated on the graph above:


	December 31,										November 15,		December 31,
	2011		2012		2013		2014		2015		2016		2016		2017		2018
Penn Virginia Corporation	$	32.23	$	27.45	$	58.70	$	41.58	$	1.87	$	100.00	$	120.62	$	96.27	$	133.05
S&P Small Cap 600 Index	$	101.02	$	117.51	$	166.05	$	175.61	$	172.15
S&P SmallCap 600 Index											$	100.00	$	116.34	$	131.74	$	120.56
S&P 600 Oil & Gas Exploration & Production Index	$	94.15	$	85.10	$	119.34	$	73.06	$	41.52	$	100.00	$	115.64	$	81.84	$	45.36


Item 6	Selected Financial Data

The following selected historical financial and operating information was derived from our Consolidated Financial ~~Statements as of and for each of the five years ended December 31, 2015.~~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.”

2015 2014 2013 2012 2011
(in thousands, except per share amounts)
Statements of Operations Data:

Revenues $ 305,298
$ 636,773
$ 431,468
$ 317,149
$ 306,005
Operating loss ¹
$ (1,565,041 ) $ (615,985 ) $ (92,046 ) $ (147,091 ) $ (155,419 )
Net income (loss) $ (1,582,961 ) $ (409,592 ) $ (143,070 ) $ (104,589 ) $ (132,915 )
Preferred stock dividends ²
$ 22,789
$ 17,148
$ 6,900
$ 1,687
$ —
Loss attributable to common shareholders $ (1,605,750 ) $ (430,996 ) $ (149,970 ) $ (106,276 ) $ (132,915 )
Common Stock Data:

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

Basic 73,639
68,887
62,335
47,919
45,784
Diluted 73,639
68,887
62,335
47,919
45,784
Actual shares outstanding at year-end 81,253
71,569
65,307
55,117
45,714
Dividends declared per share of common stock $ —
$ —
$ —
$ 0.113
$ 0.225
Market value at year-end $ 0.30
$ 6.68
$ 9.43
$ 4.41
$ 5.29
Number of shareholders 16,849
18,306
11,335
7,656
6,787
Preferred Stock Data ³:

Actual shares outstanding at year-end:
Series A 3,915
7,945
11,500
11,500
—
Series B 27,551
32,500
—
—
—
Dividends declared per share of preferred stock ⁴:

Series A $ 300.00
$ 600.00
$ 600.00
$ 146.67
$ —
Series B $ 300.00
$ 348.33
$ —
$ —
$ —
Balance Sheet and Other Financial Data:

Property and equipment, net $ 344,395
$ 1,825,098
$ 2,237,304
$ 1,723,359
$ 1,777,575
Total assets ⁵
$ 517,725
$ 2,201,810
$ 2,472,830
$ 1,831,733
$ 1,929,819
Total debt ⁵
$ 1,224,383
$ 1,085,429
$ 1,252,808
$ 583,503
$ 684,073
Shareholders’ equity (deficit) $ (915,121 ) $ 675,817
$ 788,804
$ 895,116
$ 846,309
Cash provided by operating activities $ 169,303
$ 282,724
$ 261,512
$ 241,458
$ 144,741
Cash paid for capital expenditures $ 364,844
$ 774,139
$ 504,203
$ 370,907
$ 445,623
Other Statistical Data:

Total production (MBOE) 7,923
7,934
6,824
6,513
7,759
Proved reserves (MMBOE) 44
115
136
113
147



	(in thousands, except per share amounts, production and reserves)
	Successor							Predecessor
					September 13			January 1
	Year Ended				Through			Through			Year Ended
	December 31,				December 31,			September 12,			December 31,
	2018		2017		2016			2016			2015			2014
Statements of Operations and Other Data:
Revenues	$	440,832	$	160,054	$	39,003		$	94,310		$	305,298		$	636,773
Operating income (loss)^{1, 2}	$	208,755	$	51,872	$	11,413		$	(20,867	)	$	(1,564,976	)	$	(615,920	)
Net income (loss) ³	$	224,785	$	32,662	$	(5,296	)	$	1,054,602		$	(1,582,961	)	$	(409,592	)
Preferred stock dividends ⁴	$	—	$	—	$	—		$	5,972		$	22,789		$	17,148
Income (loss) attributable to common shareholders	$	224,785	$	32,662	$	(5,296	)	$	1,048,630		$	(1,605,750	)	$	(430,996	)
Income (loss) per common share, basic	$	14.93	$	2.18	$	(0.35	)	$	11.91		$	(21.81	)	$	(6.26	)
Income (loss) per common share, diluted	$	14.70	$	2.17	$	(0.35	)	$	8.50		$	(21.81	)	$	(6.26	)
Weighted-average shares outstanding:
Basic	15,059		14,996		14,992			88,013			73,639			68,887
Diluted	15,292		15,063		14,992			124,087			73,639			68,887
Dividends declared per share	$	—	$	—	$	—		$	—		$	—		$	—
Cash provided by operating activities	$	272,132	$	81,710	$	30,774		$	30,247		$	169,303		$	282,724
Cash paid for capital expenditures	$	430,592	$	115,687	$	4,812		$	15,359		$	364,844		$	774,139

Total production (MBOE)	7,944		3,779		1,039			3,346			7,923			7,934

	December 31,							September 12,			December 31,
Balance Sheet and Other Data:	2018		2017		2016			2016			2015			2014
Property and equipment, net	$	927,994	$	529,059	$	247,473		$	253,510		$	344,395		$	1,825,098
Total assets	$	1,068,954	$	629,597	$	291,686		$	333,974		$	517,725		$	2,201,810
Total debt	$	511,375	$	265,267	$	25,000		$	75,350		$	1,224,383		$	1,085,429
Shareholders’ equity (deficit)	$	447,355	$	221,639	$	185,548		$	190,895		$	(915,121	)	$	675,817

Actual shares outstanding at period-end	15,081		15,019		14,992			14,992			81,253			71,569
Proved reserves as of December 31,(MMBOE)	123		73		49			N/A			44			115

¹ Operating loss for 2015 ~~2014, 2013, 2012~~ and ~~2011~~2014 included impairment charges of $1.4 billion ~~$791.8 million, $132.2 million, $104.5 million~~ and ~~$104.7~~$791.8 million, respectively.

~~Includes accumulated preferred stock dividends~~

Operating income (loss) for all periods prior to 2018 reflects the retrospective application of ~~$10.7~~Accounting Standards Update 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU 2017-07. See “Overview and Executive Summary” included in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 to our Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”


³	Net income (loss) and Income (loss) attributable to common shareholders for the year ended December 31, 2018 and the period of January 1 through September 12, 2016 includes reorganization items attributable to our bankruptcy proceedings of $3.3 million ~~for 2015 as described in footnote~~ and $1.1 billion, respectively.


^{4 below.}	Excludes inducements paid for the conversion of preferred stock of $4.3 million in 2014.

³ Outstanding preferred stock is in the form of depositary shares representing a 1/100th ownership interest in a share of either our 6% Series A Convertible Perpetual Preferred Stock, or Series A Preferred Stock, or our 6% Series B Convertible Perpetual Preferred Stock, or Series B Preferred Stock, as applicable. Each share of the Series A Preferred Stock and B Preferred Stock has a liquidation preference of $10,000 per share or $100 per depositary share.


⁴	In September 2015, we suspended our quarterly dividends on the Series A Preferred Stock and the Series B Preferred Stock. The suspension resulted in the accumulation of dividends for the quarterly periods ended September 30, 2015 and December 31, 2015 of $1.7 million for the Series A Preferred Stock and $9.0 million for the Series B Preferred Stock.

⁵

Total assets and total debt have been adjusted downward from the prior year presentation by $24.6 million, $28.2 million, $11.3 million and $13.2 million as of December 31, 2014, 2013, 2012 and 2011, respectively, due the adoption in 2015 of ASU No. 2015–03, ~~Simplifying the Presentation of Debt Issuance Costs~~, or ASU 2015–03 on a retrospective basis. ASU 2015–03 requires that debt issuance costs, which were previously presented as assets, be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. In addition, total assets were further reduced by $0.1 million and $6.1 million as of December 31. 2014 and 2013 due to the adoption in 2015 of ASU 2015–17, ~~Balance Sheet Classification of Deferred Taxes, which requires the combination of all deferred income tax assets and liabilities to be presented as a single noncurrent amount.~~


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 Gonzales, Lavaca, Fayette and DeWitt Counties in South Texas.

Presentation of Financial Information and Changes in Accounting Principles

Emergence from Bankruptcy

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.

Adoption of New Accounting Standards

As discussed in further detail in Notes 2 and 6 to the Consolidated Financial Statements, we have adopted two new accounting standards: Accounting Standards Codification Topic 606, Revenues from Contracts with Customers, or ASC Topic 606, and ASU 2017–07, effective January 1, 2018. The adoption of these standards impacts the presentation and comparability of (i) NGL product revenues and Gathering, processing and transportation, or GPT, expense; and (ii) General and administrative, or G&A, expenses and Other income (expense), net. We ~~also have less significant operations in Oklahoma, primarily~~adopted ASC Topic 606 utilizing the cumulative effect transition method. Accordingly, our NGL revenues and GPT expense for the year ended December 31, 2017 are not comparable to the 2018 presentation of these items. Our discussion and analysis of these items in the ~~Granite Wash.~~Results of Operations that follow address the effects of changes directly attributable to the adoption of ASC Topic 606. We adopted ASU 2017–07 utilizing the modified retrospective method. Accordingly, certain retiree benefits costs that were previously reported as a component of G&A are being reported as a component of Other, net (expenses), as required by ASU 2017–07, for all periods presented.

~~The majority of our Eagle Ford wells were drilled by us between 2011~~Industry Environment and ~~2015. As commodity~~Recent Operating and Financial Highlights

Crude oil prices ~~began their precipitous decline~~continued rising in the second half of ~~2014, we reduced our capital program while exploiting our most productive drilling locations, attempting~~2017 throughout the first half of 2018 and then declined precipitously in the fall of 2018. Global economic conditions as well as domestic supply are anticipated to maintain downward pressure on crude oil prices for the near term. Despite these challenges, we continue to benefit from the proximity of our operating region to the Gulf Coast markets whereby we sell substantially all of our crude oil production based on the Light Louisiana Sweet, or LLS, price index. The LLS index has exceeded that of the West Texas Intermediate, or WTI, price index, providing us with a ~~consistent level~~strong revenue stream compared to certain of ~~period-to-period growth~~our domestic peers and competitors located at a greater distance from the Gulf Coast markets. Subsequent to ~~offset natural~~2016, domestic production ~~declines and securing our most strategic acreage through the drillbit.~~

~~We began 2015 with eight drilling rigs operating~~has increased, including that in the broader Eagle ~~Ford. All~~Ford region in which we operate. This environment has expanded opportunities in our principal operating region. In addition, there has been a consolidation of holdings within the Eagle Ford, including our own, through recent acquisitions. Collectively, these ~~rigs were initially contracted in 2014 or earlier~~and other factors have led, at times, ~~when (i)~~to higher pricing for certain oilfield products and services, including drilling services. At this time we do not anticipate any significant declines in such costs for 2019.

The following summarizes certain key operating and financial highlights for the ~~spot price~~three months ended December 31, 2018 with comparison to the three months ended September 30, 2018 as presented in the table that follows. The year-over-year highlights for 2018 and 2017 are addressed in further detail in the discussions for Financial Condition and Results of Operations that follow.

Production increased approximately 12 percent to 2,363 MBOE, from 2,108 MBOE due primarily to incremental production from the 10 gross (8.9 net) wells turned to sales during the quarter, the majority of which were turned to sales in the first month of the quarter.

Product revenues decreased approximately two percent to $124.6 million from $126.8 million due primarily to approximately $18.0 million of which relates to 14 percent and three percent lower crude oil ~~was substantially~~and NGL pricing, partially offset by $14.7 million due to the effect of higher overall production volume, and ~~(ii) we were executing our business plans~~$1.1 million from 26 percent higher natural gas pricing.

Production and lifting costs, which include LOE and GPT, increased on an absolute basis to ~~aggressively develop our acquired acreage~~$15.7 million from $14.8 million, but decreased on a per unit basis to $6.65 per BOE, from $7.04 per BOE due primarily to lower surface maintenance costs as well as the effect of the increase in ~~this region. By~~production volume.

Production and ad valorem taxes decreased on an absolute and per unit basis to $6.5 million and $2.75 per BOE from $7.2 million and $3.39 per BOE, respectively, due primarily to lower crude oil and NGL pricing partially offset by the ~~end~~effect of ~~2015, we had reduced our capital program~~higher production volume.

General and administrative expenses increased on an absolute and per unit basis to ~~one operated drilling rig.~~

~~Throughout 2015, we explored strategic alternatives to enhance liquidity, including first~~$8.1 million and ~~second lien financing transactions. In December 2015, a potential first lien financing agreement was terminated. We incurred~~$3.43 per BOE from $6.2 million ~~in professional fees~~ and ~~consulting~~$2.92 per BOE, respectively, due primarily to transaction costs associated with ~~this proposed transaction~~the Merger partially offset by the effect of higher production volume.

Our DD&A increased to $39.6 million, or $16.75 per BOE from $35.0 million, or $16.61 per BOE due primarily to $4.2 million from the effect of higher production volume, as well as $0.4 million attributable to the effect of higher rates, resulting from higher capitalized costs for oil and ~~other financing efforts during 2015.~~gas properties.

~~The continued deterioration~~Our operating income declined to $54.9 million from $64.0 million due to the combined impact of ~~commodity prices as reflected~~the matters noted in the ~~future strip pricing as of December 31, 2015 triggered an impairment of approximately $1.4 billion to our Eagle Ford properties, reducing their carrying value to their estimated fair value.~~bullets above.

The following table sets forth certain historical summary operating and financial statistics for the periods presented:

Year Ended December 31,
2015 2014 2013
Total production (MBOE) 7,923
7,934
6,824
Average daily production (BOEPD) 22,323
21,738
18,696
Crude oil and NGL production (MBbl) 6,304
5,754
4,417
Crude oil and NGL production as a percent of total 80 % 73 % 65 %
Product revenues, as reported $ 262,980
$ 512,882
$ 430,693
Product revenues, adjusted for derivatives $ 401,149
$ 505,458
$ 429,651
Crude oil and NGL revenues as a percent of total, as reported 90 % 89 % 88 %
Realized prices:
Crude oil ($/Bbl) $ 44.81
$ 90.50
$ 101.13
NGL ($/Bbl) $ 12.24
$ 31.14
$ 31.30
Natural gas ($/Mcf) $ 2.62
$ 4.44
$ 3.64
Aggregate ($/BOE) $ 33.19
$ 64.64
$ 63.11
Production and lifting costs ($/BOE):
Lease operating $ 5.36
$ 6.09
$ 5.20
Gathering, processing and transportation $ 3.01
$ 2.31
$ 1.88
Production and ad valorem taxes ($/BOE) $ 2.06
$ 3.53
$ 3.28
General and administrative ($/BOE) ¹
$ 4.99
$ 5.15
$ 6.46
Total operating costs ($/BOE) $ 15.42
$ 17.08
$ 16.82
Depreciation, depletion and amortization ($/BOE) $ 42.22
$ 37.85
$ 35.99
Cash provided by operating activities $ 169,303
$ 282,724
$ 261,512
Cash paid for capital expenditures $ 364,844
$ 774,139
$ 504,203
Cash and cash equivalents at end of period $ 11,955
$ 6,252
$ 23,474
Debt outstanding, net of discount, at end of period $ 1,245,000
$ 1,110,000
$ 1,281,000
Credit available under revolving credit facility at end of period ²
$ —
$ 413,196
$ 191,346
Proved reserves (MMBOE) 44
115
136
Net development wells drilled and completed 38.6
51.6
34.6



	(in thousands except per unit measurements, production, wells and reserves)
	Successor															Predecessor
													September 13			January 1
	Three Months Ended												Through			Through
	December 31,			September 30,			Year Ended December 31,						December 31,			September 12,
	2018			2018			2018			2017			2016			2016
Total production (MBOE)	2,363			2,108			7,944			3,779			1,039			3,346
Average daily production (BOEPD)	25,686			22,912			21,765			10,353			9,449			13,071
Crude oil production (MBbl)	1,818			1,633			6,077			2,764			710			2,311
Crude oil production as a percent of total	77		%	77		%	76		%	73		%	68		%	69		%
Product revenues	$	124,572		$	126,803		$	439,530		$	159,469		$	38,654		$	93,649
Crude oil revenues	$	112,452		$	117,059		$	402,485		$	140,886		$	33,157		$	81,377
Crude oil revenues as a percent of total	90		%	92		%	92		%	88		%	86		%	87		%
Realized prices:
Crude oil ($ per Bbl)	$	61.84		$	71.67		$	66.23		$	50.96		$	46.68		$	35.21
NGL ($ per Bbl) ¹	$	21.79		$	22.41		$	20.99		$	19.25		$	16.56		$	11.37
Natural gas ($ per Mcf)	$	3.80		$	3.02		$	3.08		$	2.89		$	2.81		$	2.06
Aggregate ($ per BOE)	$	52.72		$	60.16		$	55.33		$	42.20		$	37.19		$	27.99
Prices, adjusted for derivatives::
Crude oil ($ per Bbl)	$	54.64		$	62.36		$	58.28		$	49.69		$	47.22		$	55.98
Aggregate ($ per BOE)	$	47.17		$	52.94		$	49.25		$	41.27		$	37.56		$	42.33
Production and lifting costs ($ per BOE):
Lease operating	$	4.21		$	4.70		$	4.52		$	5.76		$	5.13		$	4.67
Gathering, processing and transportation ¹	$	2.44		$	2.34		$	2.34		$	2.84		$	2.93		$	3.96
Production and ad valorem taxes ($ per BOE)	$	2.75		$	3.39		$	2.96		$	2.33		$	2.40		$	1.04
General and administrative ($ per BOE) ²	$	3.43		$	2.92		$	3.28		$	4.82		$	4.88		$	11.64
Depreciation, depletion and amortization ($ per BOE) ³	$	16.75		$	16.61		$	16.11		$	12.87		$	11.21		$	10.04
Capital expenditure program costs ⁴	$	105,099		$	104,589		$	418,951		$	129,827		$	5,454		$	4,113
Cash provided by operating activities ⁵	$	79,227		$	72,487		$	272,132		$	81,710		$	30,774		$	30,247
Cash paid for capital expenditures ⁶	$	107,333		$	121,909		$	430,592		$	115,687		$	4,812		$	15,359
Cash and cash equivalents at end of period	$	17,864		$	8,011		$	17,864		$	11,017		$	6,761		$	31,414
Debt outstanding, net of discount and issue costs, at end of period	$	511,375		$	472,344		$	511,375		$	265,267		$	25,000		$	75,350
Credit available under credit facility at end of period	$	128,600		$	57,100		$	128,600		$	159,745		$	102,233		$	51,883
Net development wells drilled and completed	8.9			9.7			45.5			16.9			—			2.9
Proved reserves at the end of the period (MMBOE)	123			N/A			123			73			49			N/A

¹ Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.57, $0.46 and $0.84 and liability-classified share-based compensation of $(0.09), $0.57 and $0.60 for the years ended December 31, 2015, 2014 and 2013, respectively.


¹	The effects of the adoption of ASC Topic 606, if applied to the three months ended December 31, 2017 and the year ended December 31, 2017, would have resulted in realized prices for NGLs of $19.27 and $16.40 per BOE and GPT of $2.43 and $2.45 per BOE, respectively.

Includes combined amounts of $1.56 and $0.51 per BOE for the three months ended December 31, ~~2015, we were~~2018 and ~~continue~~September 30, 2018, respectively, and $1.11 , $1.36 and $6.98 per BOE for the Successor periods ended December 31, 2018 and 2017 and the Predecessor period in 2016, respectively, attributable to ~~be unable~~equity- and liability-classified share-based compensation and significant special charges, including acquisition, divestiture and strategic transaction costs and strategic and financial advisory costs prior to ~~draw on~~our bankruptcy filing, among others costs, as described in the ~~Revolver (see “Key Developments”~~discussion of “Results of Operations - General and ~~“Financial Condition” sections~~Administrative” that ~~follow).~~follows.


³	Determined using the full cost method for the Successor periods and the successful efforts method for the Predecessor period.


⁴	Includes amounts accrued and excludes capitalized interest and capitalized labor.

⁵

Includes net cash paid for derivative settlements of $13.1 million and $15.2 million for the three months ended December 31, 2018 and September 30, 2018, respectively, and $48.3 million and $3.5 million for the years ended December 31, 2018 and 2017, respectively, and cash received from derivative settlements of $0.4 million and $48.0 million for the Successor and Predecessor periods ended in 2016, respectively. Reflects changes in operating assets and liabilities of $(0.7) million and $(6.1) million for the three months ended December 31, 2018 and September 30, 2018, respectively, and $(2.8) million, $(15.0) million and $7.0 million for the Successor periods ended December 31, 2018, 2017 and 2016 and $35.2 million for the Predecessor period in 2016, respectively.


⁶	Represents actual cash paid for capital expenditures including capitalized interest and capitalized labor.

Key Developments

The following general business developments and corporate actions ~~in 2015 and 2016~~ had or may have a significant impact on our results of operations, financial position and cash flows:

~~Depressed Commodity Prices~~Merger with Denbury

On October 28, 2018, Denbury and ~~Our Hedging Program~~

~~Commodity prices have exhibited significant volatility~~Penn Virginia announced the Merger in which Denbury will acquire Penn Virginia. The consideration to be paid to Penn Virginia shareholders will consist of 12.4 shares of Denbury common stock and ~~continued~~$25.86 of cash for each share of Penn Virginia common stock. Penn Virginia shareholders will be permitted to elect to receive either all cash, all stock or a ~~decline that began~~mix of stock and cash, in ~~mid-2014 and has lasted throughout 2015 and into 2016. Crude oil prices declined from a high of over $105 per barrel~~each case subject to proration, which will result in June 2014 to less than $27 per barrel in February 2016. Natural gas prices faced similar downward pressure in 2015, dropping below $1.70 per MMBtu in December 2015. The deterioration of commodity prices triggered an impairmentthe aggregate issuance by Denbury of approximately ~~$1.4 billion~~191.667 million Denbury shares and payment by Denbury of $400 million in cash. The transaction was unanimously approved by the board of directors of each company, and certain Penn Virginia shareholders holding approximately 15 percent of the outstanding shares signed voting agreements to ~~our Eagle Ford properties. Our crude oil derivatives provided cash settlements~~vote “for” the transaction. The transaction is subject to the approval by the holders of ~~$137.5~~more than two-thirds of the outstanding Company common shares, the approval by the holders of a majority of the outstanding Denbury common shares of an amendment to the certificate of incorporation to increase the number of authorized Denbury common shares, the approval of the issuance of Denbury common shares in the Merger by the holders of a majority of the Denbury common shares represented in person or by proxy at a meeting of Denbury shareholders held to vote on such matter and other customary closing conditions. The special meeting of shareholders to approve the merger is anticipated in April 2019 and closing is anticipated soon thereafter, subject to shareholder approval and certain other conditions. The Merger Agreement contains certain termination rights for both Denbury and the Company, including if the Merger is not consummated by April 30, 2019, and requires Penn Virginia to pay a $45 million ~~during~~termination fee in certain circumstances.

Production and Development Plans

Total production for the quarter and year ended December 31, ~~2015. For 2016,~~2018 was 2,363 MBOE and 7,944, or 25,686 and 21,765 BOEPD, with approximately 77 percent and 76 percent, or 1,818 MBbls and 6,077 MBbls, of production from crude oil, 13 percent from NGLs for each period and 10 percent and 11 percent from natural gas. Production from our Eagle Ford operations during the annual period was 7,780 MBOE or 21,314 BOEPD while all of our production was derived from this region during the fourth quarter of 2018 following the sale of our Mid-Continent operations in July of 2018.

We drilled and turned 10 and 53 gross (8.9 and 45.5 net) Eagle Ford wells to sales during the quarter and year ended December 31, 2018, respectively. Subsequent to December 31, 2018, we ~~have hedged a total~~drilled and turned an additional four gross (2.9 net) wells to sales. As of ~~approximately 6,000 BOPD at a weighted-average swap price~~February 22, 2019, we were in the process of ~~$80.41 per barrel. We expect to remain unhedged~~drilling six gross (5.4 net) wells with ~~respect to natural gas production for the foreseeable future.~~

~~Ongoing Efforts to Refinance the Company~~our three operated drilling rigs and ~~Improve Liquidity~~four gross (4.0 net) wells were completing.

As of December 31, ~~2015,~~2018, we had approximately 98,200 gross (84,200 net) acres in the ~~total outstanding principal amount~~Eagle Ford, net of expirations. Approximately 92 percent of our ~~debt obligations was $1.2 billion. We are continuing to actively explore~~acreage is held by production and evaluate various strategic alternatives to reduce the level of our long-term debt and lower our future cash interest obligations. In January 2016, we retained K&E and Jefferies to provide strategic advice generally and to act as our advisors in that regard. The timing and outcome of these effortssubstantially all is highly uncertain. One or more of these alternatives could potentially be consummated without the consent of any one or more of our current security holders and, if consummated, could be dilutive to the holders of our outstanding equity securities and adversely affect the trading prices and values of our current debt and equity securities or if we were to seek protection under the bankruptcy laws, could cause the shares of our common stock to be canceled, with limited recovery, if any. Furthermore, there can be no assurance that any of these alternatives will be successful on acceptable terms or at all. operated by us.

While we were in compliance with the leverage covenant under the Revolver at December 31, 2015, based on our current operating forecast and capital structure, we do not believe that we will be able to comply with the leverage covenant during the next twelve months. Furthermore, we reclassified all of our debt as current as of December 31, 2015, which represents a breach of the current ratio covenant under the Revolver. Pursuant to the Eleventh Amendment to the Revolver, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default under the Revolver until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). If we do not obtain a waiver or other suitable relief from the lenders under the Revolver before the extension expires, there will exist an event of default under the Revolver. Even if we obtain such a waiver or other relief, we still believe we cannot comply with the leverage covenant during the next twelve months. If we cannot obtain from our lenders a waiver of such potential breach or an amendment of the leverage covenant, our breach would constitute an event of default that could result in an acceleration of substantially all of our outstanding indebtedness. We would not have sufficient capital to satisfy these obligations. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”

Additionally, as further described under “Financial Condition – Ability to Continue as a Going Concern” below, our registered independent public accountants have issued an opinion with a going concern explanatory paragraph on our consolidated financial statements. As a result, we are in default under our Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default under the Revolver until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). If we are unable to obtain a waiver or other suitable relief with respect to these defaults, an event of default may occur and could result in an acceleration of our Revolver and potential cross-default and acceleration of substantially all of our other indebtedness. We would not have sufficient capital to satisfy these obligations

~~Reduced Capital Budget and Suspension of Drilling Program~~Credit Facility

In response to the recent declines in commodity prices, and given the uncertainty regarding the timing and magnitude of any price recovery, we suspended our drilling activities in February 2016. While we intend to resume drilling in 2016, there can be no assurance that we will have adequate capital to do so.

~~Revolver Amendments and Commitment and Borrowing Base Reduction~~

~~On March 15, 2016,~~October 2018, we entered into the ~~Eleventh~~Borrowing Base Agreement and Amendment No. 5 to the Credit Facility, or the Fifth Amendment, to ~~the Revolver. The Eleventh Amendment provides (i) for an extension before certain events of default under the Revolver will occur, (ii) for a reduction in commitments to $171.8 million and (iii) that~~our credit agreement, or Credit Facility, increasing the borrowing base ~~under~~from $340.0 million to $450.0 million, among other things.

Acquisition of Producing Properties

In December 2017, we entered into a purchase and sale agreement with Hunt, to acquire certain oil and gas assets in the ~~Revolver is not~~Eagle Ford Shale, primarily in Gonzales and Lavaca Counties, Texas for $86.0 million in cash, subject to ~~scheduled redetermination until May 15, 2016. Specifically,~~adjustments, or the ~~extension period~~Hunt Acquisition. The Hunt Acquisition had an effective date of October 1, 2017, and closed on March 1, 2018, at which time we paid cash consideration of $84.4 million. We received $1.4 million from Hunt, primarily attributable to suspended revenues, in a final settlement that occurred in July 2018. In connection with the Hunt Acquisition, we also acquired working interests in certain wells that we previously drilled as operator, and in which Hunt had rights to participate prior to the transaction closing. Accumulated costs, net of suspended revenues for these wells was $13.8 million, which we have reflected as a component of the total net assets acquired. The Hunt Acquisition expanded our 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.

Commodity Hedging Program

As of February 22, 2019, we have hedged a portion of our estimated future crude oil production through the end of 2020 with a mix of WTI- and LLS- indexed swaps. We are currently unhedged with respect to ~~events~~NGL and natural gas production. The following table summarizes our hedge positions for the periods presented:



	WTI Volumes	WTI Average Swap Price		LLS Volumes	LLS Average Swap Price
	(Barrels per day)	($ per barrel)		(Barrels per day)	($ per barrel)
Remainder of 2019	6,407	$	54.49	5,000	$	59.17
2020	6,000	$	54.09	—	—

Divestiture of default is through 12:01 am on April 12, 2016, which can be further extended through 12:01 am on May 10, 2016 if certain conditions have been satisfied. The extension period can be terminated early upon certain triggering events.Mid-Continent Properties

~~The key conditions~~In June 2018, we entered into a purchase and sale agreement with a third party to the first extension (April 12, 2016) and entry to the Eleventh Amendment are: (i) termination of certain hedge agreements and application of the proceeds against the loans (which will result in a further reductionsell all of our ~~lenders’ commitments), (ii) entry into control agreements over deposit accounts,~~remaining Mid-Continent oil and gas properties, located primarily in Oklahoma in the Granite Wash, for $6 million in cash, subject to customary ~~exceptions, (iii) payment~~adjustments. The sale had an effective date of ~~advisor fees,~~March 1, 2018, and ~~(iv) agreement to certain changes~~closed on July 31, 2018, and we received proceeds of $6.2 million. In November 2018, we paid $0.5 million, including $0.2 million of suspended revenues, to the Revolver, including increasing the interest rate by 1.00%, tightening certain restrictive covenants and agreeing that monthly hedge settlements will be applied against the loans (which will result in a further reduction in our lenders’ commitments).

The key conditions to the second extension (May 10, 2016) are: (i) termination of certain additional hedges and application of most of the proceeds against the loans (which will result in a further reduction in our lenders’ commitments)and (ii) no notification by the representative of the ad hoc committee of unsecured noteholders that they do not support such extension. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”

In January 2016, the Revolver was amended to (i) allow us to convert to or continue LIBOR loans without having to make a solvency representation and (ii) increase our mortgage requirement from 80 percent to 100 percent (subject to certain exceptions) of our proved reserves. In November 2015,buyer in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver to $275 million due primarily to depressed commodity prices and our reduced capital program.final settlement.

~~Suspension of Preferred Stock Dividends~~

In September 2015, we announced a suspension of quarterly dividends on our outstanding Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015. The suspension was extended through the quarter ended December 31, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarters ended September 30, 2015 and December 31, 2015 and any future unpaid dividends, will accumulate. For the year ended December 31, 2015, we accumulated a total of $10.7 million in unpaid preferred stock dividends. The suspension of quarterly dividends does not affect our business operations and does not cause an event of default under any of our debt agreements. Pursuant to the Eleventh Amendment, we are precluded from making dividend payments on our Series A and Series B Preferred Stock.

~~Sale of Assets~~

In October 2015, we sold certain non-core Eagle Ford properties for $12.5 million, net of transaction costs and customary closing adjustments. We recognized a loss of $9.5 million on this transaction in the fourth quarter of 2015.

In August 2015, we sold our East Texas assets and received cash proceeds of approximately $73 million, net of transaction costs and customary closing adjustments. The effective date of the sale was May 1, 2015 and we recognized a gain of approximately $43 million. The properties sold had net production of 1,898 BOEPD during the second quarter of 2015, consisting of 74 percent natural gas, 19 percent NGLs and seven percent crude oil.

~~The net proceeds from these transactions were used to pay down a portion of our outstanding borrowings under the Revolver.~~

~~Production and Development in the Eagle Ford~~

Our Eagle Ford production was 16,544 BOEPD during the three months ended December 31, 2015 with oil comprising 11,764 BOPD, or 71 percent, and NGLs and natural gas comprising approximately 16 percent and 13 percent. Our fourth quarter production represented an 11 percent decrease compared to 18,528 BOEPD during the three months ended September 30, 2015, of which 12,826 BOPD, or 69 percent, was crude oil, 17 percent was NGLs and 14 percent was natural gas. The sequential decline in production was attributable to our reduction in drilling activity.

During the three months ended December 31, 2015, we drilled and completed six gross (4.5 net) wells in the Eagle Ford for a total of 61 gross (38.6 net) wells for the full year. The last 11 wells that we drilled and completed were two-string lower Eagle Ford wells with slickwater stimulation. The average drilling and completion costs for these wells totaled approximately $5.2 million per well.

During the three months ended December 31, 2015, the wells that we drilled and completed had an average IP rate of over 1,600 BOEPD over an average of 19.5 frac stages, with 71 percent of production from crude oil, compared to an average of approximately 1,500 BOEPD over an average of 21.2 frac stages in the three months ended September 30, 2015. The average amount of proppant per stage for these was approximately 450,000 pounds and the average amount of proppant per lateral foot was approximately 2,020 pounds, compared to approximately 422,000 pounds per stage and 1,800 pounds per lateral foot in the three months ended September 30, 2015. Of the five gross wells that we have completed in 2016, three had IP rates in excess of 3,500 BOEPD with approximately 93 percent production from crude oil over an average of 27.7 frac stages. These particular wells are among the most productive wells we have drilled in the Eagle Ford thus far. We believe the strong improvement in early-time production rates is attributable to the use of slickwater stimulations, continued use of “zipper fracs” for alternating laterals on multi-well pads and increased frac intensity as measured by the increased proppant pumped per stage.

Financial Condition

~~Ability to Continue as a Going Concern~~

The precipitous decline in oil and natural gas prices during 2015 and into 2016 has had a significant adverse impact on our business, and as a result of our financial condition, our registered independent public accountants have issued an opinion with an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” The Revolver requires us to deliver audited, consolidated financial statements without a “going concern” or like qualification or exception. Furthermore, we have classified all of our total outstanding debt as short-term as of December 31, 2015, which represents a breach of the current ratio covenant under the Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such default, together with certain other defaults, will not become events of default until April 12, 2016 (which can be further extended until May 10, 2016 if certain other conditions have been satisfied). For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.” If we do not obtain a waiver or other suitable relief from the lenders under the Revolver before the extension expires, there will exist an event of default under the Revolver. Even if we obtain such a waiver or other relief, we still believe we cannot comply with the leverage covenant during the next twelve months. If we cannot obtain from our lenders a waiver of such potential breach or an amendment of the leverage covenant, our breach would constitute an event of default that could result in an acceleration of substantially all of our outstanding indebtedness. We would not have sufficient capital to satisfy these obligations.

Liquidity

Our primary sources of liquidity ~~have historically included~~include our cash ~~from~~on hand, cash provided by operating activities and borrowings under the ~~Revolver, proceeds from~~Credit Facility. The Credit Facility provides us with up to $450 million in borrowing commitments. The current borrowing base under the ~~sales~~Credit Facility is also $450 million. As of ~~assets and, from time to time, proceeds from capital market transactions, including~~February 22, 2019, we had $136.6 million of availability under the ~~offering of debt and equity securities.~~ Credit Facility.

Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for ~~our~~ crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. ~~As a result of continued low oil and natural gas prices during 2015 and into 2016, our liquidity has been significantly negatively impacted.~~

As of December 31, 2015, we had an aggregate amount of approximately $1.2 billion of debt outstanding. We will be required to pay interest on our senior notes in the amount of $87.6 million in 2016, including $10.9 million in April 2016 and $32.9 million in May 2016. Our ability to make those payments is severely in doubt. In 2015, we incurred a loss from operations of $1.6 billion, including an impairment charge of $1.4 billion. As of March 11, 2016, we had only $32.3 million in cash and cash equivalents. Pursuant to the Eleventh Amendment, the commitments under the Revolver were reduced to $171.8 million, which is equal to our currently outstanding loans ($170 million) and issued letters of credit ($1.8 million) under the Revolver. Because we do not have any unused commitment capacity, we will not be able to draw on the Revolver to pay our second quarter interest payments on our senior notes or for any other purpose. Furthermore, we are required, at the time of borrowing and as a condition to borrowing, to make certain representations to our lenders. We may not currently be able to make these representations, nor is it likely that we will be able to do so in the future unless we can restructure our debt obligations. There can be no assurance that we will be able to restructure our debt obligations. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or to otherwise extend the maturity dates, and to cure any potential defaults under the agreements governing such debt, there is no assurance that any particular action or actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our debt agreements will be sufficient.

Moreover, our lenders may in the future exercise their right to redetermine our $275 million borrowing base under the Revolver. Pursuant to the Eleventh Amendment, any such redetermination will not occur until after May 15, 2016. If our borrowing base is redetermined below the amount of our outstanding borrowings, a deficiency will result, and any deficiency must be repaid within 60 days. For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”

~~Capital Resources~~

Our business plan for 2016 reflects a suspension of our drilling program as a result of depressed commodity prices. Upon the resumption of a drilling program, if any, we expect to allocate substantially all of our capital expenditures to the Eagle Ford. We continually review our drilling and capital expenditure plans and may change the amount we spend, or the allocations, based on available opportunities, product pricing, industry conditions, cash from operating activities and the overall availability of capital. For a detailed analysis of our historical capital expenditures, see the ~~Cash Flows~~ ~~discussion that follows.~~

~~Cash From Operating Activities.~~ In addition to commodity price volatility, as discussed in detail below, our cash from operating activities is impacted by the timing of our working capital requirements. The most significant component thereof is the timing of payments made for drilling and completion capital expenditures and the related billing and collection of our partners’ share thereof. This component can be substantial to the extent that we are the operator of lower working interest wells. In certain circumstances, we have and will continue to utilize capital cash calls to mitigate the burden on our working capital. In addition, we have been required to make prepayments for certain oilfield products and services due to the recent reduction in our credit standing.

We historically have actively managed our exposure to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of collar and swap contracts. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow ~~at risk,~~protection, available hedge prices, the magnitude of our capital program and our operating strategy. ~~During 2015,~~In order to mitigate this volatility, we entered into derivative contracts hedging a portion of our ~~commodity derivatives portfolio resulted in $137.5 million of net cash receipts related to lower than anticipated prices received for our~~estimated future crude oil production through the end of 2020.

Capital Resources

We plan to fund our 2019 capital spending primarily with cash from operating activities and, ~~$0.7 million of net cash receipts attributable~~ to ~~lower than anticipated prices received~~the extent necessary, borrowings under the Credit Facility. Based upon current price and production expectations for ~~our natural gas production. If commodity prices remain depressed,~~2019, we ~~anticipate~~believe that our ~~derivative portfolio~~cash from operating activities and borrowings under our Credit Facility will ~~continue~~be sufficient to ~~result in receipts from settlements for~~fund our operations through year-end 2019; 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 ~~remainder of 2016.~~

For 2016, we have hedged approximately 6,000 BOPD at weighted-average floor/swap prices of $80.41 per barrel. Our natural gas hedges have expired and we anticipate remaining unhedged with respect to natural gas production for 2016.“Cash Flows” discussion that follows.

~~Revolver Borrowings.~~Cash on Hand and Cash From Operating Activities. As of ~~December 31, 2015,~~February 22, 2019, we had approximately $14 million of cash on hand. For additional information and an analysis of our historical cash flows from operating activities, see the ~~Revolver provided for a revolving commitment and borrowing base of $275~~“Cash Flows” discussion that follows.

Credit Facility Borrowings. During 2018, we borrowed $244 million, ~~including up to $20 million for the issuance of letters of credit. The borrowing base~~ under the ~~Revolver is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base.~~

The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had outstanding borrowings of $170 million and letters of credit of $1.8 million as of December 31, 2015. Pursuant to the Eleventh Amendment, the commitments under the Revolver were reduced to $171.8 million, which is equal to our currently outstanding loans ($170 million) and issued letters of credit ($1.8 million) under the Revolver. Because we do not have any unused commitment capacity, we will not be able to draw on the Revolver to pay our second quarter interest payments on our senior notes or for any other purpose. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults under the agreements governing such debt, there is no assurance that any particular action or actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our debt agreements will be sufficient.

Credit Facility. For additional information regarding the terms and covenants under the ~~Revolver,~~Credit Facility, see the “Capitalization” discussion that follows.

The following table summarizes our borrowing activity under the ~~Revolver during~~Credit Facility for the periods presented:

Borrowings Outstanding

Weighted-
Average
Maximum
Weighted-
Average Rate
Three months ended December 31, 2015 $ 160,543
$ 170,000
2.5151 %
Year ended December 31, 2015 $ 173,904
$ 232,000
2.1981 %



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended December 31, 2018	$	305,217	$	321,000	6.25	%
Year ended December 31, 2018	$	230,934	$	321,000	5.76	%

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, including the sale in 2018 of our Mid-Continent properties, 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 ~~have undertaken~~may consider capital market transactions, including the offering of debt and equity securities. ~~Historically, we have entered into such transactions to facilitate acquisitions and to pursue opportunities to adjust our total capitalization.~~

Cash Flows

The following table summarizes our cash flows for the periods presented:

Year Ended December 31,
2015 2014 Variance
Cash flows from operating activities

Operating cash flows, net $ 146,211
$ 373,362
$ (227,151 )
Working capital changes (excluding interest, income taxes and restructuring and exit costs paid), net (15,918 ) 8,282
(24,200 )
Commodity derivative settlements received (paid), net: —
Crude oil 137,488
(6,170 ) 143,658
Natural gas 681
(1,254 ) 1,935
Interest payments, net of amounts capitalized (86,226 ) (84,797 ) (1,429 )
Income taxes received (paid), net 714
(3,612 ) 4,326
Strategic and financial advisory costs paid (3,693 ) —
(3,693 )
Drilling rig termination costs paid (6,636 ) —
(6,636 )
Acquisition-related arbitration costs paid —
(589 ) 589
Restructuring and exit costs paid (3,318 ) (2,498 ) (820 )
Net cash provided by operating activities 169,303
282,724
(113,421 )
Cash flows from investing activities

Capital expenditures – property and equipment (364,844 ) (774,139 ) 409,295
Acquisition and working capital-related settlements, net —
33,712
(33,712 )
Proceeds from sales of assets, net 85,189
313,933
(228,744 )
Net cash used in investing activities (279,655 ) (426,494 ) 146,839
Cash flows from financing activities

Proceeds (repayments) from revolving credit facility borrowings, net 135,000
(171,000 ) 306,000
Proceeds from the issuance of preferred stock, net —
313,330
(313,330 )
Payments made to induce conversion of preferred stock —
(4,256 ) 4,256
Debt issuance costs paid (744 ) (151 ) (593 )
Dividends paid on preferred stock (18,201 ) (12,803 ) (5,398 )
Other, net —
1,428
(1,428 )
Net cash provided by financing activities 116,055
126,548
(10,493 )
Net increase (decrease) in cash and cash equivalents $ 5,703
$ (17,222 ) $ 22,925



	Year Ended
	December 31,
	2018			2017
Cash flows from operating activities
Operating cash flows, net of working capital changes	$	346,780		$	91,365
Crude oil derivative settlements paid, net	(48,291		)	(3,511		)
Interest payments, net of amounts capitalized	(22,599		)	(4,102		)
Acquisition, divestiture and strategic transaction costs paid	(2,968		)	(1,088		)
Reorganization items paid, net	(540		)	(954		)
Consulting costs paid to former Executive Chairman	(250		)	—
Net cash provided by operating activities	272,132			81,710
Cash flows from investing activities
Acquisitions, net	(85,387		)	(200,849		)
Capital expenditures	(430,592		)	(115,687		)
Proceeds from sales of assets, net	7,683			869
Net cash used in investing activities	(508,296		)	(315,667		)
Cash flows from financing activities
Proceeds from credit facility borrowings, net	244,000			52,000
Proceeds from second lien facility, net	—			196,000
Debt issuance costs paid	(989		)	(9,787		)
Proceeds from rights offering, net	—			55
Other, net	—			(55		)
Net cash provided by financing activities	243,011			238,213
Net increase in cash and cash equivalents	$	6,847		$	4,256

Cash Flows ~~From~~from Operating Activities. C~~ommodity prices declined~~The increase in net cash from operating activities for 2018 compared to 2017 was primarily attributable to: (i) higher overall production volume in 2018, (ii) incremental net operating cash inflows from the Hunt Acquisition and the 2017 acquisition of oil and gas assets from Devon Energy Corporation, or the Devon Acquisition, (iii) higher overall product pricing in 2018 and (iv) lower payments in 2018 for bankruptcy-related administration costs as the case was closed in November 2018. These items were partially offset by: (i) substantially ~~during 2015 resulting~~higher settlements paid for crude oil derivatives, (ii) higher interest payments due to greater outstanding borrowings in ~~lower realized cash receipts~~2018, (iii) higher payments for acquisition, divestiture and strategic transaction costs in 2018 and (iv) certain costs paid in connection with the retirement of our Executive Chairman in February 2018.

Cash Flows from ~~our product revenues. Our working capital utilization increased during 2015 as~~Investing Activities. In 2018, we paid ~~down~~ a ~~substantial level~~combined total of ~~accounts payable~~$86.5 million for the Hunt Acquisition and ~~accrued expenses~~the purchase of other working interests in ~~2015 attributable to activities from 2014. In addition, we were required to make prepayments~~producing properties in the ~~latter part~~Eagle Ford and received a total of the fourth quarter of 2015 for certain oilfield services due to deterioration in our credit standing. During 2015, we paid early termination charges for the early release of four drilling rigs, of which $0.7 million had been accrued at the end of 2014. During 2015, we also incurred and paid higher professional fees and other consulting costs associated with our strategic initiatives, including our refinancing efforts and our search for a new chief executive officer. Restructuring and exit costs paid were higher during 2015 due primarily to the payment of termination and severance benefits of approximately $1.0$1.1 million in connection with ~~reductions in headcount. Cash~~the final settlement of the Devon Acquisition. In 2017, we paid a total of $200.8 million for ~~interest, net~~the preliminary settlement of ~~amounts capitalized, was higher during 2015 due primarily~~the Devon Acquisition which included $0.7 million paid to higher average amounts outstanding under the Revolver. The overall decline in operating cash flows was partially offset by (i) cash settlements from our commodity derivatives portfolio during 2015 as comparedother parties that had tag-along rights to ~~net payments during 2014 and (ii) the receipt of federal income tax refunds in 2015 as compared to federal and state income tax payments in 2014.~~

~~Cash Flows From Investing Activities.~~ sell their interests. As illustrated in the tables below, our cash payments for capital expenditures were ~~substantially lower~~higher during ~~2015~~2018 as compared to ~~2014~~2017 due primarily to an increase to a three-rig and two frac spread development program from a two-rig and single frac spread program in 2017 as well as the ~~reduction~~effect of higher working interests from the Hunt and Devon Acquisitions. The increased capital expenditures for 2018 and 2017 were partially offset by proceeds from asset sales during each year. We received proceeds of $7.7 million in 2018 attributable to the sales of: (i) all of our Mid-Continent properties, (ii) undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana, (iii) certain undeveloped leasehold rights in Oklahoma, (iv) certain pipeline assets in our ~~capital program including (i) reductions~~former Marcellus Shale operating region and (v) scrap and surplus tubular and well materials. In 2017, we received proceeds of $0.9 million from the sale of certain inactive acreage in the number of operated drilling rigs from eight at the beginning of 2015 to one by the end of the year, (ii) corresponding reductions in well completion and frac crews, (iii) lower pipeline and gathering infrastructure expenditures and (iv) the completion of our water system infrastructure project in 2014.Oklahoma.

The following table sets forth costs related to our capital expenditure program for the periods presented:

Year Ended December 31,
2015 2014
Oil and gas:

Drilling and completion $ 284,225
$ 667,385
Lease acquisitions and other land-related costs ¹
16,052
98,443
Geological and geophysical (seismic) costs 828
5,106
Pipeline, gathering facilities and other equipment 3,884
21,538
304,989
792,472
Other – Corporate 562
1,463
Total capital program costs $ 305,551
$ 793,935

~~_________________~~

¹~~Includes site-preparation and other pre-drilling costs.~~



	Year Ended
	December 31,
	2018		2017
Drilling and completion	$	405,677	$	125,235
Lease acquisitions and other land-related costs	5,180		4,493
Geological, geophysical (seismic) and delay rental costs	377		696
Pipeline, gathering facilities and other equipment, net	7,717		(597		)
	$	418,951	$	129,827

The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures ~~for additions to property and equipment~~ as reported in our Consolidated Statements of Cash Flows for the periods presented:


	Year Ended December 31,						Year Ended
	2015			2014			December 31,
Total capital program costs	$	305,551		$	793,935
Decrease (increase) in accrued capitalized costs	55,660			(24,715		)
							2018			2017
Total capital program costs (from above)							$	418,951		$	129,827
Increase in accrued capitalized costs							(44		)	(19,910		)
Less:
Exploration expenses charged to operations:
Geological and geophysical (seismic)	(828		)	(5,106		)
Other, primarily delay rentals	(111		)	(860		)
Transfers from tubular inventory and well materials	(4,570		)	(403		)	(10,056		)	(3,326		)
Sales & use tax refunds received and applied to property accounts							(643		)	(2,265		)
Add:
Tubular inventory and well materials purchased in advance of drilling	2,854			4,056			9,578			6,252
Capitalized internal labor							3,688			2,384
Capitalized interest	6,288			7,232			9,118			2,725
Total cash paid for capital expenditures	$	364,844		$	774,139		$	430,592		$	115,687

Our capital expenditures during 2015 and 2014 were partially offset by the receipt of net proceeds from the sale of assets. In 2015, we received approximately $85 million of net proceeds from the sale of our East Texas assets and certain non-core Eagle Ford properties. In 2014, we received approximately $314 million of net proceeds from the sale of our Selma Chalk assets in Mississippi, our natural gas gathering and gas lift assets in South Texas and the sale of rights to construct a crude oil gathering and intermediate transportation system in South Texas. We also received approximately $35 million, including interest of approximately $1 million, in 2014 with respect to the resolution of an acquisition-related arbitration matter. Approximately $34 million, excluding the interest component, was classified as an investing activity.

~~The following table sets forth the net proceeds received from the sale of assets for the periods presented:~~

Year Ended December 31,
2015 2014
Oil and gas properties, net $ 84,967
$ 70,818
Rights to construct an oil gathering system in South Texas, net —
147,149
South Texas natural gas gathering and gas lift system, net —
95,964
Tubular inventory, well materials and other, net 222
2
$ 85,189
$ 313,933

Cash Flows ~~From~~from Financing Activities. ~~We had net borrowings of $135~~During 2018 we borrowed $244 million under the ~~Revolver in 2015~~Credit Facility to fund ~~our multi-rig~~the three-rig capital program ~~compared~~and the Hunt Acquisition, while 2017 only included borrowings of $52 million, net of repayments. In 2017, we received proceeds of $196 million from the $200 million Second Lien Facility, or Second Lien Facility, net of OID, primarily to ~~net repayments of $171 million during 2014 using $313~~fund the Devon Acquisition. We also paid approximately $1.0 million of net proceeds from the June 2014 offering of our Series B Preferred Stock and proceeds from sales of assets. We paid total dividends of $18.2 million for the Series A Preferred Stock and the Series B Preferred Stock in 2015 compared to $12.8 million in 2014. While we suspended payments on both preferred stock series in the third quarter of 2015, the total dividend payments were higher in 2015 due primarily to the Series B Preferred Stock being outstanding only in the second half of 2014. In 2014, we paid a total of $4.3 million to induce the conversion of approximately 30 percent of the outstanding shares of the Series A Preferred Stock. We paiddebt issuance costs in ~~2015 and 2014 associated~~2018 in connection with amendments to the ~~Revolver including $0.7~~Credit Facility and other costs in connection with the Second Lien Facility compared to $9.8 million paid in ~~2015~~2017 in connection with an amendments to the Credit Facility and ~~$0.2 million~~the issuance of the Second Lien Facility. The receipt in ~~2014. We also received~~the 2017 period of delayed proceeds attributable to the rights offering in September 2016 were fully offset by costs paid in connection with the registration of ~~$1.4 million during 2014 from the exercise of~~our common stock ~~options.~~in 2017.

Capitalization

The following table summarizes our total capitalization as of the dates presented:

As of December 31,
2015 2014
Revolving credit facility $ 170,000
$ 35,000
Senior notes due 2019 300,000
300,000
Senior notes due 2020 775,000
775,000
Total debt 1,245,000
1,110,000
Shareholders’ equity ¹
(915,121 ) 675,817
$ 329,879
$ 1,785,817
Debt as a % of total capitalization 377 % 62 %

~~_________________~~



	December 31,
	2018			2017
Credit Facility borrowings	$	321,000		$	77,000
Second Lien Facility term loans, net of original issue discount and issuance costs	190,375			188,267
Total debt	511,375			265,267
Shareholders’ equity	447,355			221,639
Total capitalization	$	958,730		$	486,906
Debt as a % of total capitalization	53		%	54		%

¹Credit Facility~~Includes 3,915~~. The Credit Facility provides for a $450 million revolving commitment and ~~7,945 shares~~borrowing base. The Credit Facility includes a $5.0 million sublimit for the issuance of letters of credit. The availability under the Credit Facility may not exceed the lesser of the ~~Series A Preferred Stock~~aggregate commitments or the borrowing base. The borrowing base under the Credit Facility is redetermined semi-annually, generally in April and ~~27,551~~October of each year. Additionally, the Credit Facility lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes including working capital. The Credit Facility matures in September

2020. We had $0.4 million and ~~32,500 shares~~$0.8 million in letters of ~~the Series B Preferred Stock~~credit outstanding as of December, ~~31, 2015~~2018 and ~~2014. Both series of preferred stock have a liquidation preference of $10,000 per share representing a total of $314.7 million and $404.4 million as of~~ December 31, ~~2015 and 2014.~~2017, respectively.

~~Revolving Credit Facility. As of December 31, 2015,~~The outstanding borrowings under the ~~Revolver~~Credit Facility bear interest at a rate equal to, at our option, at either ~~(i)~~(a) a customary reference rate ~~derived~~plus an applicable margin ranging from ~~LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities,~~2.00% to 3.00%, determined based on the average availability under the Credit Facility or ~~Adjusted~~(b) a customary London interbank offered rate, or LIBOR, plus an applicable margin ~~(ranging~~ranging from ~~1.500%~~3.00% to ~~2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0% (clauses (a)~~4.00%, (b) and (c)), or the Base Rate, plus, in each case, an applicable margin (ranging from 0.500% to 1.500%). Pursuant to the Eleventh Amendment, the applicable margin for borrowings bearing interest as a rate derived from (a) LIBOR was increased 1.00% (to a range of 2.500% to 3.500%) and (b) the Base Rate was increased by 1.00% (to a range of 1.500% to 2.500%). In each case, the applicable margin is determined based on the ~~ratio~~average availability under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on LIBOR borrowings is payable every one, three or six months, at our ~~outstanding borrowings to~~election, and is computed on the ~~available Revolver capacity.~~basis of a year of 360 days. As of December 31, ~~2015,~~2018, the actual weighted-average interest rate applicable to the Revolver was 4.5% which is derived from the prime rate of 3.5% plus an applicable margin of 1.0%. The applicable interest rate was re-set on January 12, 2016 to a one-month LIBOR-based rate of 2.4375% (Adjusted LIBOR rate of 0.4375% plus an applicable margin of 2.0%.) Commitment fees are charged at 0.375% to 0.500% on the ~~undrawn portion of the Revolver depending on our ratio of~~ outstanding borrowings tounder the ~~available Revolver capacity. As of December 31, 2015,~~Credit Facility was 5.96%. Unused commitment fees ~~were being~~are charged at a rate of ~~0.375%~~0.50%.

The ~~Revolver~~Credit Facility is guaranteed by ~~Penn Virginia~~us and all of our ~~material~~ subsidiaries, or the Guarantor Subsidiaries. The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on our ability or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the ~~Revolver~~Credit Facility are secured by a first priority lien on substantially all of our ~~proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.~~assets.

~~2019 Senior Notes~~Second Lien Facility. On September 29, 2017, we entered into the $200 million Second Lien Facility. The ~~2019 Senior Notes, which were issued at par in April 2011,~~maturity date under the Second Lien Facility is September 29, 2022.

The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an ~~annual~~applicable margin of 6.00% or (b) a customary LIBOR rate plus an applicable margin of 7.00%. Amounts under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 7.25% which is payable on April 15 and October 15 of each year. We may redeem all or part of the 2019 Senior Notes at a redemption price of 103.625% of the principal amount reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries. Additionally, the 2019 Senior Notes contain certain cross-default provisions, which would result8.34% resulting in an event of default under the notes if our lenders under the Revolver accelerate the Revolver obligations. Such event of default, if it occurs, would permit the noteholders to accelerate the 2019 Senior Notes.

~~2020 Senior Notes. The 2020 Senior Notes, which were issued at par in April 2013, bear~~effective interest ~~at an annual~~ rate of ~~8.50% which is payable on May 1 and November 1~~9.89%. As of ~~each year. Beginning in May 2017, we may redeem all or part of~~December 31, 2018, the 2020 Senior Notes at a redemption price of 104.250% of the principal amount reducing to 100% in May 2019 and thereafter. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries. Additionally, the 2020 Senior Notes contain certain cross-default provisions, which would result in an event of default under the notes if our lenders under the Revolver

~~accelerate the Revolver obligations. Such event of default, if it occurs, would permit the noteholders to accelerate the 2020 Senior Notes.~~

~~Series A and Series B Preferred Stock.~~ ~~The annual dividend on each share of the Series A Preferred Stock and Series B Preferred Stock is 6.00% per annum~~actual interest rate on the ~~liquidation preference of $10,000 per share and~~Second Lien Facility was 9.53%. Interest on reference rate borrowings is payable quarterly in arrears and is computed on ~~each~~the basis of ~~January 15, April 15, July 15~~a year of 365/366 days, and ~~October 15 of each year. We may,~~interest on eurocurrency borrowings is payable every one or three months (including in three month intervals if we select a six month interest period), at our option, pay dividends in cash, common stock or a combination thereof; however, the utilization of common stock to pay dividends on Series B Preferred Stock would require shareholder approval. In addition, cash payment of dividends may be limited by certain financial covenants under the Revolver. See “~~Covenant Compliance” that follows.~~

~~Each share of the Series A Preferred Stock~~election and ~~Series B Preferred Stock~~ is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the applicable conversion prices, which is initially $6.00 per share for the Series A Preferred Stock and $18.34 per share for the Series B Preferred Stock, subject in each case to specified anti-dilution adjustments. The initial conversion rate is equal to 1,666.67 shares of our common stock for each share of the Series A Preferred Stock and 545.17 shares of our common stock for each share of the Series B Preferred Stock. The Series A Preferred Stock and Series B Preferred Stock are not redeemable for cash by us or the holders at any time. At any time on or after October 15, 2017 in the case of the Series A Preferred Stock and July 15, 2019 in the case of the Series B Preferred Stock, we may, at our option, cause all outstanding shares of the Series A Preferred Stock and Series B Preferred Stock, respectively, to be automatically converted into shares of our common stock at the then-applicable conversion prices for each series if the closing price of our common stock exceeds 130% of the then-applicable conversion price for a specified period prior to conversion. If a holder elects to convert shares of the Series A Preferred Stock and Series B Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value.

~~In September 2015, we announced a suspension of quarterly dividends~~computed on the ~~Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015. The suspension was extended through December 31, 2015. Our articles~~basis of incorporation provide that any unpaid dividends will accumulate, including the unpaid dividends for the quarters ended September 30, 2015 and December 31, 2015 and any future unpaid dividends. If we do not pay dividends on our Series A and B Preferred Stock for six quarterly periods, whether consecutive or non-consecutive, the holdersa year of ~~the shares of both series of preferred stock, voting together as a single class, will~~360 days. We have the right, to ~~elect two additional directors~~the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to ~~serve on our board of directors until all accumulated and unpaid dividends are paid in full. Pursuant~~prepay loans under the Second Lien Facility at any time, subject to the ~~Eleventh Amendment, we are precluded from making dividend payments on our Series A~~following prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): during year one, a customary “make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and ~~Series B Preferred Stock.~~

~~While~~thereafter, no premium. The Second Lien Facility also provides for the ~~accumulation does not result~~following prepayment premiums in ~~presentation~~the event of a ~~liability on~~change in control that results in an offer of prepayment that is accepted by the ~~balance sheet,~~lenders under the ~~accumulated dividends are added to our net loss in the determination~~Second Lien Facility. During years one and two, 102% of the ~~loss attributable~~amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium.

The Second Lien Facility is collateralized by substantially all of the Company’s and its subsidiaries’ assets with lien priority subordinated to ~~common shareholders~~the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by us and the related loss per share. For the quarters ended September 30, 2015 and December 31, 2015, we accumulated a total of $10.7 million in unpaid preferred stock dividends, including $1.7 million attributable to the Series A Preferred Stock and $9.0 million attributable to the Series B Preferred Stock.Guarantor Subsidiaries.

Covenant Compliance. The ~~Revolver~~Credit Facility requires us to maintain certain financial and non-financial covenants. These covenants impose limitations on our ability to pay dividends as well as our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into(1) a ~~merger or sale of our assets, including the sale or transfer of interests in our subsidiaries, among other requirements.~~

~~The Revolver requires us to maintain certain financial covenants as follows:~~

~~Total debt to~~minimum interest coverage ratio (adjusted EBITDAX, ~~each~~ as defined in the ~~Revolver, for any four consecutive quarters may not exceed 4.75~~Credit Facility, to 1.0 for periods through March 31, 2016, 5.25 to 1.0 for periods through June 30, 2016, 5.50 to 1.0 for periods through December 31, 2016, 4.50 to 1.0 for periods through March 31, 2017 and 4.0 to 1.0 through maturity in September 2017. EBITDAX, which is a non-GAAP measure, generally means net income plusadjusted interest ~~expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.~~

Credit exposure to EBITDAX for any four consecutive quarters may not exceed 2.75 to 1.0 for periods ending after March 31, 2015 through March 31, 2017. Credit exposure consists of all outstanding borrowing under the Revolver plus any outstanding letters of credits.

~~The current ratio,~~expense), measured as of the last day of ~~any~~each fiscal quarter, ~~may not be less than 1.0~~of 3.00 to ~~1.0. The~~1.00, (2) a minimum current ratio ~~is generally~~(as defined in the ~~ratio~~Credit Facility, which considers the unused portion of current assets to current liabilities. Current assets and current liabilities attributable to derivative instruments are excluded. In addition, current assets include the amount of any unused commitment under the Revolver.

~~In addition, we are precluded from the payment of cash dividends on our outstanding convertible preferred stock if~~ the total ~~debt~~commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to ~~EBITDAX~~1.00, and (3) a maximum leverage ratio ~~exceeds 5.0~~(consolidated indebtedness to ~~1.0. Pursuant to the Eleventh Amendment, we are no longer permitted to make payment of dividends on our outstanding convertible preferred stock or common stock.~~

~~The indentures governing our senior notes include an incurrence test which is determined by an interest coverage ratio,~~EBITDAX, as defined in the ~~indentures.~~Credit Facility), measured as of the last day of each fiscal quarter, of 3.50 to 1.00. The ~~interest coverage ratio may not be less than 2.25 times consolidated EBITDAX, a non-GAAP measure.~~Second Lien Facility has no financial covenants.

The ~~following table summarizes~~Credit Facility and Second Lien Facility also contain customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the ~~actual results~~incurrence of ~~our financial compliance under the Revolver~~liens and ~~senior note indentures as~~indebtedness, merger, consolidation or sale of assets, payment of dividends, and ~~for the year ended December 31, 2015:~~



	~~Required~~	~~Actual~~
~~Description~~	~~Covenant~~	~~Results~~
~~Total debt to EBITDAX~~	~~< 4.75 to 1~~	~~4.54 to 1~~
~~Credit exposure to EBITDAX~~	~~< 2.75 to 1~~	~~0.63 to 1~~
~~Current ratio~~	~~> 1.00 to 1~~	~~0.13 to 1~~
~~Interest coverage~~	~~> 2.25 to 1~~	~~2.56 to 1~~

transactions with affiliates and other customary covenants.

The ~~precipitous decline in oil~~Credit Facility and natural gas prices during 2015 and into 2016 has had a significant adverse impact on our business, and as a result of our financial condition, our registered independent public accountants have issued an opinion with an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” The Revolver requires us to deliver audited, consolidated financial statements without a “going concern” or like qualification or exception. Furthermore, we have classified all of our total outstanding debt as short-term as of December 31, 2015, which represents a breach of the current ratio covenant under the Revolver. Pursuant to the Eleventh Amendment, we have received an agreement from our lenders that such breach, together with the “going concern” default and certain other defaults, will not becomeSecond Lien Facility contain customary events of default until April 12, 2016 (which can be further extended until May 10, 2016 if certain conditions have been satisfied). For additional information regarding the Eleventh Amendment, please see Item 9B, “Other Information.”and remedies. If we do not obtain a waiver or other suitable relief from the lenders under the Revolver prior to the expiration of the extension, there will exist an event of default under the Revolver. Even if we obtain such a waiver or other relief, we still believe we cannot comply with the ~~leverage covenant during~~financial and other covenants in the ~~next twelve months. If~~Credit Facility and Second Lien Facility, the lenders thereto may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility and Second Lien Facility.

As of December 31, 2018, we ~~cannot obtain from our lenders a waiver of such potential breach or an amendment~~were in compliance with all of the leverage covenant, our breach would constitute an event of default that could result in an acceleration of substantially all of our outstanding indebtedness. We would not have sufficient capital to satisfy these obligations.

~~Additionally, pursuant to the Eleventh Amendment, the commitments~~covenants under the ~~Revolver were reduced to $171.8 million, which is equal to our currently outstanding loans ($170 million)~~Credit Facility and ~~issued letters of credit ($1.8 million) under~~ the Revolver. Because we do not have any unused commitment capacity, we will not be able to draw on the Revolver to pay our second quarter interest payments on our senior notes or for any other purpose. Moreover, our lenders may in the future exercise their right to redetermine our $275 million borrowing base under the Revolver. Pursuant to the Eleventh Amendment, any such redetermination will not occur until after May 15, 2016. If our borrowing base is redetermined below the amount of our outstanding borrowings, a deficiency will result, and any deficiency must be repaid within 60 days.Second Lien Facility.

Results of Operations

~~Substantial~~The tabular presentations included below reflect the results of operations associated with the Successor periods of 2018, 2017 and 2016 (the period from September 13 through December 31, 2016) and the Predecessor period of 2016 (the period from January 1 through September 12, 2016). As discussed previously in “Overview and Executive Summary,” the adoption of Fresh Start Accounting and the full cost method of accounting for oil and gas properties on the Emergence Date results in the Successor not being comparable to the Predecessor for purposes of financial reporting. While the Successor effectively represents a new reporting entity for financial reporting purposes, the impact is generally limited to those areas associated with the basis in and accounting for our oil and gas properties (specifically DD&A and exploration expenses), capital structure (specifically interest expense) and income taxes (due to the change in control). Accordingly, we believe that describing certain year-over-year variances and trends in our production, revenues and expenses for the calendar years 2018, 2017 and 2016 without regard to the concept of a Successor and Predecessor facilitates a meaningful analysis of our results of operations.

A portion of the components of our ~~year-to-year~~year-over-year variances for 2018 to 2017 are due to the effects of ~~property divestitures. In 2015, we sold all~~the Hunt Acquisition in March 2018 and the Devon Acquisition in September 2017. Partially offsetting the impact these transactions are the effects of our interests in the Haynesville Shale and Cotton Valley in East Texas and in 2014 we sold all of our interests in the Selma Chalk in Mississippi. These non-core assets were primarily focused on natural gas production.property divestitures. In the discussion and analysis that follows, the term “Divested properties” refers to the production, revenues and expenses associated with our former assets ~~and~~in the Mid-Continent region that we sold in July 2018 as well as former operations in ~~East Texas~~the Marcellus Shale in Pennsylvania. We terminated operations in that region in August 2016 and ~~Mississippi. In 2015,~~completed well-plugging and remediation activities in 2017.

As discussed previously in “Overview and Executive Summary,” the adoption of ASC Topic 606 and ASU 2017–07 effective January 1, 2018 impacts the presentation and comparability of (i) NGL product revenues and GPT expense; and (ii) G&A expenses and Other income (expense), net. Because we ~~also sold various non-core properties~~adopted ASC Topic 606 using the cumulative effect transition method, we are precluded from changing the presentation of impacted items, which include NGL product revenues and GPT expenses, in prior periods. Accordingly, the presentation of NGL product revenues and GPT expenses for 2018 are not comparable to those presented for 2017 and the Successor and Predecessor periods in 2016 (see Note 6 to the Consolidated Financial Statements included in Part II, Item 8, “Financial Statements and Supplementary Data.”) Conversely, the adoption of ASU 2017–07, which applies to the presentation of the components of retiree pension and postretirement benefits costs, was applied on a retrospective basis to all prior periods. Accordingly, the presentations of our ~~South Texas~~G&A expenses and ~~Mid-Continent regions of operations.~~Other income (expense), net are comparable for all periods presented.

Production

The following tables set forth a summary of our total and average daily production volumes by product and geographic region for the periods presented:

Total Production Average Daily Production
Year Ended December 31, 2015 vs. 2014 vs. Year Ended December 31, 2015 vs. 2014 vs.
2015 2014 2013 2014 2013 2015 2014 2013 2014 2013

Crude oil (MBbl & Bbl/day) 4,923
4,644
3,435
279
1,209
13,523
12,723
9,412
800
3,311
NGLs (MBbl & Bbl/day) 1,381
1,110
982
272
128
3,893
3,040
2,692
853
348
Natural gas (MMcf & MMcf/day) 9,713
13,085
14,435
(3,372 ) (1,351 ) 29
36
40
(6 ) (4 )
Total (MBOE & BOE/day) 7,923
7,934
6,824
(11 ) 1,111
22,323
21,738
18,696
585
3,043
% Change 3 %
16 %

Year Ended December 31, 2015 vs. 2014 vs. Year Ended December 31, 2015 vs. 2014 vs.
2015 2014 2013 2014 2013 2015 2014 2013 2014 2013
(MBOE) (BOE per day
South Texas ¹
6,995
5,913
4,091
1,082
1,823
19,165
16,201
11,208
2,964
4,994
Mid-Continent and other ²
479
765
962
(286 ) (197 ) 1,311
2,096
2,636
(785 ) (540 )
Divested properties ³
449
1,256
1,771
(807 ) (515 ) 1,847
3,441
4,852
(1,594 ) (1,411 )
Total 7,923
7,934
6,824
(11 ) 1,111
22,323
21,738
18,696
585
3,043
% Change 3 % 16 %



	Total Production
	Successor				Predecessor
				September 13 Through	January 1 Through
	Year Ended December 31,			December 31,	September 12,
	2018	2017		2016	2016
Crude oil (MBbl)	6,077	2,764		710	2,311
NGLs (MBbl)	1,004	523		164	533
Natural gas (MMcf)	5,181	2,949		994	3,012
Total (MBOE)	7,944	3,779		1,039	3,346
2018 vs 2017 Variance (MBOE)		4,165
% Change		110	%
2017 vs. Combined 2016 Variance (MBOE)					(606	)
% Change					(14	)%
	Average Daily Production
				September 13 Through	January 1 Through
	Year Ended December 31,			December 31,	September 12,
	2018	2017		2016	2016
Crude oil (Bbl per day)	16,650	7,573		6,457	9,028
NGLs (Bbl per day)	2,750	1,432		1,486	2,083
Natural gas (MMcf per day)	14	8		9	12
Total (BOEPD)	21,765	10,353		9,449	13,071
2018 vs 2017 Variance (BOEPD)		11,412
% Change		110	%
2017 vs. Combined 2016 Variance (BOEPD)					(1,631	)
% Change					(14	)%
	Total Production by Region
				September 13 Through	January 1 Through
	Year Ended December 31,			December 31,	September 12,
	2018	2017		2016	2016
South Texas	7,780	3,487		937	3,071
Divested properties ¹	165	292		103	276
Total (MBOE)	7,944	3,779		1,039	3,346
2018 vs 2017 Variance (MBOE)		4,165
% Change		110	%
2017 vs. Combined 2016 Variance (MBOE)					(606	)
% Change					(14	)%
	Average Daily Production by Region
				September 13 Through	January 1 Through
	Year Ended December 31,			December 31,	September 12,
	2018	2017		2016	2016
South Texas	21,314	9,553		8,515	11,995
Divested properties ¹	451	800		934	1,076
Total (BOEPD)	21,765	10,353		9,449	13,071
2018 vs 2017 Variance (BOEPD)		11.412
% Change		110	%
2017 vs. Combined 2016 Variance (BOEPD)					(1,631	)
% Change					(14	)%

^{_____________________________________________}

¹~~Includes~~Represents total production and average daily production of our former Mid-Continent operations for all periods presented and approximately 9210 MBOE ~~(303 BOEPD), 96 MBOE (264 BOEPD) and 33 MBOE (90~~(48 BOEPD) for ~~2015, 2014 and 2013, respectively, attributable to non-core Eagle Ford properties that we sold~~Predecessor period in ~~October 2015.~~

³2018 vs. 2017. ~~Includes~~Total production increased during 2018 compared to 2017 due primarily to a greater number of wells turned to sales in 2018 under our expanded drilling program as well as incremental production from the Hunt and Devon Acquisitions. We operated three drilling rigs during 2018 compared to two during 2017, the second of which was not contracted until mid-March 2017. These increases were partially offset by the effect of the divestiture in July 2018 of our former Mid-Continent operations, as well as natural production declines from our legacy Eagle Ford wells.

Approximately 76 percent of total production ~~and average daily production of approximately 449 MBOE (1,847 BOEPD), 844 MBOE (2,311 BOEPD) and 1,020 MBOE (2,794 BOEPD) in 2015, 2014 and 2013, respectively,~~during 2018 was attributable to crude oil when compared to approximately 73 percent during 2017. Our Eagle Ford production represented 98 percent of our ~~East Texas assets that were sold in August 2015. Also includes~~ total production ~~and average daily~~during 2018 compared to approximately 92 percent from this region during 2017. Subsequent to the sale of our Mid-Continent properties on July 31, 2018, the entirety of our production ~~of approximately 412 MBOE (1,946 BOEPD) and 751 MBOE (2,058 BOEPD) in 2014 and 2013 attributable~~was derived from the Eagle Ford. During 2018, we turned 53 gross (45.5 net) Eagle Ford wells to ~~our Mississippi assets that were sold in July 2014.~~sales compared to 29 gross (16.9 net) wells during 2017.

~~2015~~2017 vs. ~~2014.~~2016. Total production ~~was essentially unchanged~~decreased during ~~the year ended December 31, 2015~~2017 compared to ~~2014. Production from~~ the ~~continued development of our Eagle Ford assets~~combined Successor and Predecessor periods in ~~South Texas offset~~2016 due primarily to natural production declines and the ~~sale~~carryover effect from the suspension of our ~~East Texas properties~~drilling program that began in February 2016 and extended through November 2016. While we resumed the drilling program at the end of 2016, we did not turn any new wells to sales until mid-February 2017. The decline was further exacerbated by mechanical issues with our previously-contracted drilling rigs and the effects of Hurricane Harvey in August ~~2015. Approximately 80 percent~~2017 which resulted in a partial curtailment of ~~total~~ production during 2015 was attributable to oil and NGLs, which represents an increase of approximately 10 percent over 2014. During 2015, our Eagle Ford production represented approximately 88 percent of our total production compared to approximately 74 percent during 2014. During 2015, we turned in line 61 gross Eagle Ford wells compared to 93 gross wells that were brought on line during 2014. A substantial majority of these wells were brought on line during the first half of 2015 at a time when we were operating as many as eight drilling rigs.

~~2014 vs. 2013.~~ Total production increased during the year ended December 31, 2014 compared to 2013 due primarily to development of our Eagle Ford properties. The increase was partially offset by natural production declines in the South Texas, Mid-Continent, East Texas and Mississippi regions,for several days as well as ~~the sale of~~delays in our ~~Mississippi properties~~scheduled drilling and completion activities in ~~July 2014.~~South Texas. Approximately 73 percent of total production during ~~2014~~2017 was attributable to crude oil when compared to approximately 69 percent during the combined Successor and ~~NGLs, which represents an increase of approximately 30 percent over 2013. During 2014, our~~Predecessor periods in 2016. Our Eagle Ford production represented ~~approximately 74~~92 percent of our total production during 2017 compared to approximately 6091 percent from this ~~play~~region during ~~2013.~~the combined Successor and Predecessor periods in 2016. During ~~2014,~~2017, we turned ~~in line 93~~29 gross ~~wells in the~~(16.9 net) Eagle Ford aswells to sales compared to 59five gross (2.9 net) wells ~~that were brought on line~~ during ~~2013.~~the combined Successor and Predecessor periods in 2016.

Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of volume by product and geographic region for the periods presented:

Total Product Revenues Revenue per Unit of Volume
Year Ended December 31, 2015 vs. 2014 vs. Year Ended December 31, 2015 vs. 2014 vs.
2015 2014 2013 2014 2013 2015 2014 2013 2014 2013

Crude oil (Total & $/Bbl) $ 220,596
$ 420,286
$ 347,407
$ (199,690 ) $ 72,879
$ 44.81
$ 90.50
$ 101.13
$ (45.69 ) $ (10.63 )
NGLs (Total & $/Bbl) 16,905
34,552
30,748
(17,647 ) 3,804
12.24
31.14
31.30
(18.90 ) (0.16 )
Natural gas (Total & $/Mcf) 25,479
58,044
52,538
(32,565 ) 5,506
2.62
4.44
3.64
(1.82 ) 0.80
Total (Total & $/BOE) $ 262,980
$ 512,882
$ 430,693
$ (249,902 ) $ 82,189
$ 33.19
$ 64.64
$ 63.11
$ (31.45 ) $ 1.53
% Change (49 )% 2 %

Year Ended December 31, 2015 vs. 2014 vs. Year Ended December 31, 2015 vs. 2014 vs.
2015 2014 2013 2014 2013 2015 2014 2013 2014 2013
($ per BOE)
South Texas ¹
$ 244,749
$ 440,566
$ 346,454
$ (195,817 ) $ 94,112
$ 34.99
$ 74.50
$ 84.69
$ (39.51 ) $ (10.19 )
Mid-Continent and other ²
10,071
32,125
37,131
(22,054 ) (5,006 ) 21.03
41.99
38.60
(20.96 ) 3.39
Divested properties ³
8,160
40,191
47,108
(32,031 ) (6,917 ) 18.17
32.00
26.60
(13.83 ) 5.40
Total $ 262,980
$ 512,882
$ 430,693
$ (249,902 ) $ 82,189
$ 33.19
$ 64.64
$ 63.11
$ (31.45 ) $ 1.53
% Change (49 )% 2 %



	Total Product Revenues
	Successor							Predecessor
						September 13 Through		January 1 Through
	Year Ended December 31,					December 31,		September 12,
	2018		2017			2016		2016
Crude oil	$	402,485	$	140,886		$	33,157	$	81,377
NGLs	21,073		10,066			2,707		6,064
Natural gas	15,972		8,517			2,790		6,208
Total	$	439,530	$	159,469		$	38,654	$	93,649
2018 vs. 2017 Variance			$	280,061
% Change			176		%
2017 vs. Combined 2016 Variance								$	27,166
% Change								21		%
	Product Revenues per Unit of Volume
						September 13 Through		January 1 Through
	Year Ended December 31,					December 31,		September 12,
	2018		2017			2016		2016
Crude oil ($ per barrel)	$	66.23	$	50.96		$	46.68	$	35.21
NGLs ($ per barrel)	$	20.99	$	19.25		$	16.56	$	11.37
Natural gas ($ per Mcf)	$	3.08	$	2.89		$	2.81	$	2.06
Total ($ per BOE)	$	55.33	$	42.20		$	37.19	$	27.99
2018 vs. 2017 Variance ($ per BOE)			$	13.13
% Change			31		%
2017 vs. Combined 2016 Variance ($ per BOE)								$	12.03
% Change								40		%
	Product Revenues by Region
						September 13 Through		January 1 Through
	Year Ended December 31,					December 31,		September 12,
	2018		2017			2016		2016
South Texas	$	435,599	$	152,521		$	36,261	$	88,849
Divested properties ¹	3,931		6,948			2,393		4,800
Total	$	439,530	$	159,469		$	38,654	$	93,649
2018 vs. 2017 Variance			$	280,061
% Change			176		%
2017 vs. Combined 2016 Variance								$	27,166
% Change								21		%
	Product Revenues per BOE by Region
						September 13 Through		January 1 Through
	Year Ended December 31,					December 31,		September 12,
	2018		2017			2016		2016
South Texas	$	55.99	$	43.74		$	38.71	$	28.94
Divested properties ¹	$	23.87	$	23.79		$	23.29	$	17.42
Total ($ per BOE)	$	55.33	$	42.20		$	37.19	$	27.99
2018 vs. 2017 Variance ($ per BOE)			$	13.13
% Change			31		%
2017 vs. Combined 2016 Variance ($ per BOE)								$	12.03
% Change								40		%

^{_______________________}

¹~~Includes~~Represents revenues of ~~$4.3 million, $7.8 million~~our former Mid-Continent operations for all periods presented and ~~$3.2 million for 2015, 2014 and 2013, respectively, attributable to non-core Eagle Ford properties that we sold in October 2015.~~


²	Includes revenues of $0.4 million, $0.7 million and $1.0 million attributable to certain Mid-Continent properties that we sold in October 2015 as well as revenues of $0.2 million, $0.5 million and $0.5 million attributable to the Marcellus Shale for 2015, 2014 and 2013, respectively.

³~~Includes revenues of $8.2 million, $28.2 million and $28.6~~$0.1 million attributable to ~~East Texas~~the Marcellus Shale for ~~2015, 2014 and 2013, respectively, and $12.0 million and $18.5 million attributable to Mississippi for 2014 and 2013.~~the Predecessor period in 2016.

The following table provides an analysis of the changes in our revenues for the periods presented:


																								Year Ended December 31, 2017 vs.
																		Year Ended December 31, 2018 vs.						Combined Successor and Predecessor
																		Year Ended December 31, 2017						Periods Ended December 31, 2016
	2015 vs. 2014 Revenue Variance Due to									2014 vs. 2013 Revenue Variance Due to								Revenue Variance Due to						Revenue Variance Due to
	Volume			Price			Total			Volume			Price			Total		Volume		Price		Total		Volume			Price		Total
Crude oil	$	25,263		$	(224,953	)	$	(199,690	)	$	122,219		$	(49,340	)	$	72,879	$	168,812	$	92,787	$	261,599	$	(9,742	)	$	36,094	$	26,352
NGLs	8,454			(26,101		)	(17,647		)	3,987			(183		)	3,804		9,259		1,748		11,007		(2,188		)	3,483		1,295
Natural gas	(14,957		)	(17,608		)	(32,565		)	(4,962		)	10,468			5,506		6,448		1,007		7,455		(2,378		)	1,897		(481		)
	$	18,760		$	(268,662	)	$	(249,902	)	$	121,244		$	(39,055	)	$	82,189	$	184,519	$	95,542	$	280,061	$	(14,308	)	$	41,474	$	27,166

2018 vs. 2017. Our product revenues during 2018 increased over 2017 due primarily to approximately 120 percent higher crude oil volumes, 92 percent higher NGL volumes and 76 higher natural gas volumes as well as the effect of 30 percent higher crude oil prices and approximately seven percent higher natural gas prices. Our Eagle Ford crude oil production benefits from pricing based on the LLS index which has averaged approximately eight percent higher than the comparable WTI index during the year ended in 2018 compared to 2017. Excluding the $2.4 million effect of the adoption of ASC Topic 606, NGL pricing increased by 21 percent during 2018 as compared to 2017.

Crude oil revenues were approximately 92 percent of our total revenues during 2018 as compared to 88 percent during 2017. Total Eagle Ford revenues were approximately 99 percent of total revenues during 2018 and 96 percent in 2017. Effective August 2018, all of our revenues were derived from the Eagle Ford.

2017 vs. 2016. Our product revenues in 2017 increased over the combined Successor and Predecessor periods in 2016 due primarily to the significant increases in all product pricing which was partially offset by the decline in production described previously. Total crude oil revenues were approximately 88 percent during 2017 compared to 87 percent during the combined Successor and Predecessor periods in 2016. Total Eagle Ford revenues were approximately 96 percent of total revenues in 2017 compared to 95 percent in the combined Successor and Predecessor periods in 2016.

Effects of Derivatives

~~In 2015, we received $138.2 million from cash settlements of oil and gas derivatives compared to net payments of $7.4 million and $1.0 million in 2014 and 2013, respectively.~~ The following table reconciles crude oil ~~and natural gas~~ revenues to realized prices, as adjusted for derivative activities, for the periods presented:


																		Successor								Predecessor
																								September 13 Through		January 1 Through
	Year Ended December 31,					Increase			Year Ended December 31,						Favorable			Year Ended December 31,						December 31,		September 12,
	2015		2014			(Unfavorable)			2014			2013			(Unfavorable)			2018			2017			2016		2016
Crude oil revenues as reported	$	220,596	$	420,286		$	(199,690	)	$	420,286		$	347,407		$	767,693		$	402,485		$	140,886		$	33,157	$	81,377
Derivative settlements, net	137,488		(6,170		)	143,658			(6,170		)	(2,624		)	(8,794		)	(48,291		)	(3,511		)	384		48,008
	$	358,084	$	414,116		$	(56,032	)	$	414,116		$	344,783		$	758,899		$	354,194		$	137,375		$	33,541	$	129,385

Crude oil prices per Bbl, as reported	$	44.81	$	90.51		$	(45.70	)	$	90.51		$	101.14		$	(10.63	)	$	66.23		$	50.96		$	46.68	$	35.21
Derivative settlements per Bbl	27.93		(1.33		)	29.26			(1.33		)	(0.76		)	(0.57		)	(7.95		)	(1.27		)	0.54		20.77
	$	72.74	$	89.18		$	(16.44	)	$	89.18		$	100.38		$	(11.20	)	$	58.28		$	49.69		$	47.22	$	55.98

Natural gas revenues as reported	$	25,479	$	58,044		$	(32,565	)	$	58,044		$	52,538		$	5,506
Derivative settlements, net	681		(1,254		)	1,935			(1,254		)	1,582			(2,836		)
	$	26,160	$	56,790		$	(30,630	)	$	56,790		$	54,120		$	2,670

Natural gas prices per Mcf, as reported	$	2.62	$	4.44		$	(1.82	)	$	4.44		$	3.64		$	0.80
Derivative settlements per Mcf	0.07		(0.10		)	0.17			(0.10		)	0.11			(0.21		)
	$	2.69	$	4.34		$	(1.65	)	$	4.34		$	3.75		$	0.59

Gain (Loss) on Sales of ~~Property and Equipment~~Assets

~~In 2015, we recognized a gain of approximately $43 million~~We recognize gains and losses on the sale or disposition of assets other than our ~~East Texas assets. Additionally, in connection with an amendment to our crude~~ oil ~~gathering agreement with Republic which included a pricing concession, we recognized $8.4 million of a gain that was previously deferred~~ and ~~being recognized over~~gas properties upon the ~~term~~completion of the underlying ~~agreement.~~ transactions.

The following table sets forth the total gains and losses recognized for the periods presented:



	Successor									Predecessor
							September 13 Through			January 1 Through
	Year Ended December 31,						December 31,			September 12,
	2018			2017			2016			2016
Gain (loss) on sales of assets, net	$	(177	)	$	(36	)	$	(49	)	$	1,261

2018, 2017 and Successor Period in 2016. In ~~2015,~~2018, 2017 and the Successor period in 2016, we ~~also~~ recognized ~~$0.4 million of deferred gain from the 2014~~insignificant net losses attributable to sale of ~~our natural gas gathering~~certain support equipment and ~~gas lift assets~~tubular inventory and well materials.

Predecessor Period in ~~South Texas. These gains were partially offset by a loss of $9.5~~2016. The Predecessor period in 2016 includes $1.7 million from the ~~sale~~amortization of ~~certain non-core Eagle Ford properties and a combined loss of $1.2 million from other sale transactions and post-closing adjustments~~deferred gains attributable to ~~prior year asset sales.~~

Inour 2014 ~~we recognized a gain of $63.0 million in connection with the~~ sale ~~to Republic~~ of rights to construct a crude oil gathering and intermediate transportation ~~system and a gain~~system. The amortization of ~~$57.1~~$0.3 million onof deferred gains from the 2014 sale of our South Texas natural gas gathering and gas lift assets is also included for the Predecessor period in ~~South Texas, including $56.7 million recognized upon the closing~~2016. As of the ~~sale~~Emergence Date, the unamortized portions of those deferred gains were reversed from our Consolidated Balance Sheet in connection with our application of Fresh Start Accounting and ~~$0.4 million attributable to the deferred portion~~included as a component of ~~the gain.~~

In 2013, we recognized losses of $0.3 million related primarily to certain post-closing adjustments for asset sales that occurred in prior years. In addition, we recognized several individually insignificant gains and losses on the sale of property, equipment, tubular inventory and well material.Reorganization items, net.

Other Revenues, Net

~~2015 vs. 2014.~~ Other revenues, ~~which~~net, includes ~~gathering, transportation,~~fees for marketing ~~compression,~~and water ~~supply and~~ disposal ~~fees~~services that we charge to ~~other~~third parties, net of ~~marketing and~~ related expenses as well as other miscellaneous revenues and credits attributable to our operations. During the Predecessor period, these revenues also included fees for water supply services as well as charges for accretion ofattributable to our unused firm transportation ~~obligation, decreased~~obligation.

The following table sets forth the total other revenues, net for the periods presented:



	Successor						Predecessor
					September 13 Through		January 1 Through
	Year Ended December 31,				December 31,		September 12,
	2018		2017		2016		2016
Other revenues, net	$	1,479	$	621	$	398	$	(600	)

2018 vs. 2017. Other revenues, net increased during ~~2015~~2018 from ~~2014. Certain of these revenue sources declined following~~2017 due primarily to higher fees charged to third parties resulting from substantially higher production.

2017 vs. 2016. Other revenues, net increased during 2017 from the ~~sale of our assets~~combined Successor and Predecessor periods in ~~East Texas where we provided services~~2016 due primarily to ~~other producers. The declines were~~higher marketing fees partially offset by ~~revenue from~~lower water disposal ~~facilities~~fees resulting from lower overall production. The combined Successor and Predecessor periods in ~~Eagle Ford that were brought on-line in 2015.~~

~~2014 vs. 2013.~~ ~~Other revenues increased during 2014~~2016 included charges for reserves of certain of our receivables from ~~2013 due primarily to income related to water supply which began in April 2014. The increase was partially offset by the effect of a $1.6 million gain in 2013~~joint venture partners and charges attributable to the ~~sale~~accretion of ~~certain proprietary seismic data.~~unused firm transportation, both of which are presented as contra-revenue items in this caption. There were no firm transportation charges in 2017 because the underlying obligation was rejected in our bankruptcy proceedings.

Lease Operating Expenses

LOE include costs that we incur to operate our producing wells and field operations. The most significant costs include compression and gas-lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, pumping and well-tending, equipment rentals, utilities and supplies among others.

The following table sets forth our LOE for the periods presented:


													Successor						Predecessor
	Year Ended December 31,						2015 vs.			2014 vs.							September 13 Through		January 1 Through
	2015		2014		2013		2014			2013			Year Ended December 31,				December 31,		September 12,
							Favorable (unfavorable)						2018		2017		2016		2016
Lease operating	$	42,428	$	48,298	$	35,461	$	5,870		$	(12,837	)	$	35,879	$	21,784	$	5,331	$	15,626
Per unit of production ($/BOE)	$	5.36	$	6.09	$	5.20	$	0.73		$	(0.89	)	$	4.52	$	5.76	$	5.13	$	4.67
% Change per unit of production							12		%	(17		)%



Virginia		23-1184320
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)



Title of each class		Name of exchange on which registered
Common Stock, $0.01 Par Value		~~Not Applicable~~NASDAQ Global Select Market



Large accelerated filer	o ý	Accelerated filer	ýo	Non-accelerated filer	o	Smaller reporting company	o
						Emerging growth company	o


		Page		Page
Forward-Looking Statements	Forward-Looking Statements	1	Forward-Looking Statements	1
Glossary of Certain Industry Terminology	Glossary of Certain Industry Terminology	2	Glossary of Certain Industry Terminology	2
Part I
Item
1.	Business	4	Business	4
1A.	Risk Factors	10	Risk Factors	12
1B.	Unresolved Staff Comments	21	Unresolved Staff Comments	29
2.	Properties	21	Properties	29
3.	Legal Proceedings	26	Legal Proceedings	35
4.	Mine Safety Disclosures	27	Mine Safety Disclosures	35
Part II

5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	27	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
6.	Selected Financial Data	28	Selected Financial Data	38
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations:		Management’s Discussion and Analysis of Financial Condition and Results of Operations:
	Overview and Executive Summary	30	Overview and Executive Summary	39
	Key Developments	32	Key Developments	42
	Financial Condition	34	Financial Condition	44
	Results of Operations	41	Results of Operations	48
	Off-Balance Sheet Arrangements	49	Off-Balance Sheet Arrangements	60
	Contractual Obligations	49	Contractual Obligations	60
	Critical Accounting Estimates	50	Critical Accounting Estimates	61
7A.	Quantitative and Qualitative Disclosures About Market Risk	52	Quantitative and Qualitative Disclosures About Market Risk
8.	Financial Statements and Supplementary Data	54	Financial Statements and Supplementary Data	65
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	91	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	107
9A.	Controls and Procedures	91	Controls and Procedures	107
9B.	Other Information	91	Other Information	107
Part III

10.	Directors, Executive Officers and Corporate Governance	92	Directors, Executive Officers and Corporate Governance	108
11.	Executive Compensation	96	Executive Compensation	108
12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	116	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	108
13.	Certain Relationships and Related Transactions, and Director Independence	117	Certain Relationships and Related Transactions, and Director Independence	108
14.	Principal Accountant Fees and Services	117	Principal Accountant Fees and Services	108
Part IV

15.	Exhibits and Financial Statement Schedules	119	Exhibits, Financial Statement Schedules	109
16.			Form 10-K Summary	111

Signatures	Signatures	123	Signatures	112



	Proved	% of Total Proved		% Proved
Region	Reserves	Reserves		Developed
	(MMBOE)
South Texas	40.1	92	%	72	%
Mid-Continent and other ¹	3.6	8	%	100	%
	43.7	100	%	75	%




	Sales Price
Quarter Ended	High		Low
December 31, 2015	$	1.23	$	0.26
September 30, 2015	$	4.39	$	0.53
June 30, 2015	$	8.03	$	3.87
March 31, 2015	$	7.91	$	4.55
December 31, 2014	$	12.89	$	4.32
September 30, 2014	$	17.20	$	11.53
June 30, 2014	$	18.20	$	13.54
March 31, 2014	$	18.04	$	8.91



	As of December 31,
	2015			2014
Revolving credit facility	$	170,000		$	35,000
Senior notes due 2019	300,000			300,000
Senior notes due 2020	775,000			775,000
Total debt	1,245,000			1,110,000
Shareholders’ equity ¹	(915,121		)	675,817
	$	329,879		$	1,785,817
Debt as a % of total capitalization	377		%	62		%



	Total Product Revenues												Revenue per Unit of Volume
	Year Ended December 31,						2015 vs.			2014 vs.			Year Ended December 31,						2015 vs.			2014 vs.
	2015		2014		2013		2014			2013			2015		2014		2013		2014			2013

Crude oil (Total & $/Bbl)	$	220,596	$	420,286	$	347,407	$	(199,690	)	$	72,879		$	44.81	$	90.50	$	101.13	$	(45.69	)	$	(10.63	)
NGLs (Total & $/Bbl)	16,905		34,552		30,748		(17,647		)	3,804			12.24		31.14		31.30		(18.90		)	(0.16		)
Natural gas (Total & $/Mcf)	25,479		58,044		52,538		(32,565		)	5,506			2.62		4.44		3.64		(1.82		)	0.80
Total (Total & $/BOE)	$	262,980	$	512,882	$	430,693	$	(249,902	)	$	82,189		$	33.19	$	64.64	$	63.11	$	(31.45	)	$	1.53
% Change																			(49		)%	2		%

	Year Ended December 31,						2015 vs.			2014 vs.			Year Ended December 31,						2015 vs.			2014 vs.
	2015		2014		2013		2014			2013			2015		2014		2013		2014			2013
													($ per BOE)
South Texas ¹	$	244,749	$	440,566	$	346,454	$	(195,817	)	$	94,112		$	34.99	$	74.50	$	84.69	$	(39.51	)	$	(10.19	)
Mid-Continent and other ²	10,071		32,125		37,131		(22,054		)	(5,006		)	21.03		41.99		38.60		(20.96		)	3.39
Divested properties ³	8,160		40,191		47,108		(32,031		)	(6,917		)	18.17		32.00		26.60		(13.83		)	5.40
Total	$	262,980	$	512,882	$	430,693	$	(249,902	)	$	82,189		$	33.19	$	64.64	$	63.11	$	(31.45	)	$	1.53
% Change																			(49		)%	2		%



	Payments Due by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Revolver ¹	$	170,000	$	—	$	170,000	$	—	$	—
Senior Notes due 2019 and 2020 ²	1,075,000		—		—		1,075,000		—
Interest payments on long-term debt ³	385,972		95,275		181,009		109,688		—
Operating leases ⁴	8,818		2,606		4,871		1,341		—
Well drilling and completion commitments ⁵	3,984		3,984		—		—		—
Firm transportation commitments ⁶	32,649		3,892		7,773		7,763		13,221
Natural gas gathering commitments ⁷	5,000		5,000		—		—		—
Crude oil gathering and transportation commitments ⁸	123,289		10,328		24,638		24,671		63,652
Asset retirement obligations ⁹	60,381		—		—		—		60,381
Drilling carry ¹⁰	10,664		1,900		8,764		—		—
Other commitments ¹¹	804		459		345		—		—
Total contractual obligations ¹²	$	1,876,561	$	123,444	$	397,400	$	1,218,463	$	137,254


⁴	Relates primarily to office facilities and equipment leases.


⁵	~~Represents our remaining commitment for one drilling rig and certain coil tubing services.~~


⁶	Includes $18.6 million of undiscounted payments attributable to a firm transportation obligation for which a fair value of $13.5 million has been recognized on our Consolidated Balance Sheet as of December 31, 2015.


⁷	~~Represents minimum payments for natural gas gathering, compression and gas lift services in South Texas.~~


⁸	Represents minimum payments for gathering and intermediate pipeline transportation services for our crude oil and condensate production in South Texas. The gathering portion of these commitments is recognized as GPT while the intermediate transportation and pipeline support components are recognized as a reduction to the index-based price that we receive from crude oil sold to Republic Midstream.


⁹⁶	Includes fixed-term commitments for one drilling rig and one frac service crew and materials. Does not include commitments for drilling rigs contracted on a pad-to-pad basis


¹⁰	~~Represents a commitment for expenditures to develop certain Eagle Ford acreage that was acquired in 2014.~~


¹¹⁸	Represents all other significant obligations including information technology licensing and service agreements, among others.


¹²	~~Does not include accumulated and unpaid preferred stock dividends of $22.8 million as of December 31, 2015.~~


Item 7A	Quantitative and Qualitative Disclosures About Market Risk



		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
First quarter 2016	Swaps	6,000	$	80.41		$	22,894	$	—
Second quarter 2016	Swaps	6,000	$	80.41		21,509		—
Third quarter 2016	Swaps	6,000	$	80.41		20,767		—
Fourth quarter 2016	Swaps	6,000	$	80.41		19,937		—



		Average	Weighted
		Volume Per	Average		Fair Value
	Instrument	Day	Price		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
First quarter 2019	Swaps-WTI	6,446	$	54.46	$	4,959	$	—
First quarter 2019	Swaps-LLS	5,000	$	59.17	3,684		—
Second quarter 2019	Swaps-WTI	6,421	$	54.48	4,307		—
Second quarter 2019	Swaps-LLS	5,000	$	59.17	3,203		—
Third quarter 2019	Swaps-WTI	6,397	$	54.50	3,821		—
Third quarter 2019	Swaps-LLS	5,000	$	59.17	3,092		—
Fourth quarter 2019	Swaps-WTI	6,398	$	54.50	3,498		—
Fourth quarter 2019	Swaps-LLS	5,000	$	59.17	3,015		—
First quarter 2020	Swaps-WTI	6,000	$	54.09	2,807		—
Second quarter 2020	Swaps-WTI	6,000	$	54.09	2,609		—
Third quarter 2020	Swaps-WTI	6,000	$	54.09	2,450		—
Fourth quarter 2020	Swaps-WTI	6,000	$	54.09	2,234		—



	Change of $10.00 per Barrel of Crude Oil or $1.00 per MMBtu of Natural Gas ($ in millions)
	Increase			Decrease
Effect on the fair value of crude oil derivatives	$	(21.8	)	$	22.0

Effect on 2016 operating income, excluding crude oil derivatives ¹	$	22.6		$	(22.6	)
Effect on 2016 operating income, excluding natural gas derivatives ¹	$	3.5		$	(3.5	)



	Page
Reports of Independent Registered Public Accounting Firm	5566
Consolidated Statements of Operations ~~for the Years Ended December 31, 2015, 2014 and 2013~~	5768
Consolidated Statements of Comprehensive Income ~~for the Years Ended December 31, 2015, 2014 and 2013~~ (Loss)	5869
Consolidated Balance Sheets ~~as of December 31, 2015 and 2014~~	5970
Consolidated Statements of Cash Flows ~~for the Years Ended December 31, 2015, 2014 and 2013~~	6071
Consolidated Statements of Shareholders’ Equity ~~for the Years Ended December 31, 2015, 2014 and 2013~~	6172
Notes to Consolidated Financial Statements:
1. Nature of Operations	6273
2. Basis of Presentation	6273
3. Summary of Significant Accounting Policies	6375
4. Bankruptcy Proceedings, Emergence and Fresh Start Accounting	78
5. Acquisitions and Divestitures	6684
5.6. Accounts Receivable and Major Customers	6886
6.7. Derivative Instruments	6887
7.8. Property and Equipment	6989
8.9. Asset Retirement Obligations	6989
9.10. Long-Term Debt	7090
~~10.~~11. Income Taxes	72
~~11. Firm Transportation Obligation~~	7492
12. Executive Retirement and Exit Activities	94
13. Additional Balance Sheet Detail	7495
~~13.~~14. Fair Value Measurements	7595
~~14.~~15. Commitments and Contingencies	7797
~~15.~~16. Shareholders’ Equity	7998
~~16.~~17. Share-Based Compensation and Other Benefit Plans	80
~~17. Impairments~~	8398
18. Interest Expense	84101
19. Earnings per Share	85101
Supplemental Quarterly Financial Information (unaudited)	86102
Supplemental Information on Oil and Gas Producing Activities (unaudited)	87103


										Successor									Predecessor
																September 13, Through			January 1, Through
	Year Ended December 31,									Year Ended December 31,						December 31,			September 12,
	2015			2014			2013			2018			2017			2016			2016
Revenues
Crude oil	$	220,596		$	420,286		$	347,407		$	402,485		$	140,886		$	33,157		$	81,377
Natural gas liquids (NGLs)	16,905			34,552			30,748
Natural gas liquids										21,073			10,066			2,707			6,064
Natural gas	25,479			58,044			52,538			15,972			8,517			2,790			6,208
Gain (loss) on sales of property and equipment, net	41,335			120,769			(266		)
Other, net	983			3,122			1,041
Gain (loss) on sales of assets, net										(177		)	(36		)	(49		)	1,261
Other revenues, net										1,479			621			398			(600		)
Total revenues	305,298			636,773			431,468			440,832			160,054			39,003			94,310
Operating expenses
Lease operating	42,428			48,298			35,461			35,879			21,784			5,331			15,626
Gathering, processing and transportation	23,815			18,294			12,839			18,626			10,734			3,043			13,235
Production and ad valorem taxes	16,282			27,990			22,404			23,547			8,814			2,498			3,490
General and administrative	43,328			49,005			53,998			26,064			18,201			5,066			38,956
Exploration	12,583			17,063			20,994			—			—			—			10,288
Depreciation, depletion and amortization	334,479			300,299			245,594			127,961			48,649			11,652			33,582
Impairments	1,397,424			791,809			132,224
Total operating expenses	1,870,339			1,252,758			523,514			232,077			108,182			27,590			115,177
Operating loss	(1,565,041		)	(615,985		)	(92,046		)
Operating income (loss)										208,755			51,872			11,413			(20,867		)
Other income (expense)
Interest expense	(90,951		)	(88,831		)	(78,841		)
Loss on extinguishment of debt	—			—			(29,174		)
Interest expense, net of amounts capitalized										(26,462		)	(6,392		)	(879		)	(58,018		)
Derivatives	71,247			162,212			(20,852		)	37,427			(17,819		)	(16,622		)	(8,333		)
Other	(3,587		)	1,334			147
Loss before income taxes	(1,588,332		)	(541,270		)	(220,766		)
Income tax benefit	5,371			131,678			77,696
Net loss	(1,582,961		)	(409,592		)	(143,070		)
Other, net										2,266			58			792			(3,173		)
Reorganization items, net										3,322			—			—			1,144,993
Income (loss) before income taxes										225,308			27,719			(5,296		)	1,054,602
Income tax (expense) benefit										(523		)	4,943			—			—
Net income (loss)										224,785			32,662			(5,296		)	1,054,602
Preferred stock dividends	(22,789		)	(17,148		)	(6,900		)	—			—			—			(5,972		)
Induced conversion of preferred stock	—			(4,256		)	—
Net loss attributable to common shareholders	$	(1,605,750	)	$	(430,996	)	$	(149,970	)
Net income (loss) attributable to common shareholders										$	224,785		$	32,662		$	(5,296	)	$	1,048,630

Net loss per share:
Net income (loss) per share:
Basic	$	(21.81	)	$	(6.26	)	$	(2.41	)	$	14.93		$	2.18		$	(0.35	)	$	11.91
Diluted	$	(21.81	)	$	(6.26	)	$	(2.41	)	$	14.70		$	2.17		$	(0.35	)	$	8.50

Weighted average shares outstanding – basic	73,639			68,887			62,335			15,059			14,996			14,992			88,013
Weighted average shares outstanding – diluted	73,639			68,887			62,335			15,292			15,063			14,992			124,087



	Common Shares Outstanding	Preferred Stock			Common Stock		Paid-in Capital			Retained Earnings (Accumulated Deficit)			Deferred Compensation Obligation			Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Shareholders’ Equity
Balance as of December 31, 2012	55,117	$	1,150		$	364	$	849,046		$	45,790		$	3,111		$	(982	)	$	(3,363	)	$	895,116
Net loss	—	—			—		—			(143,070		)	—			—			—			(143,070		)
Issuance of common stock	10,000				100		42,041			—			—			—			—			42,141
Dividends declared on preferred stock ($600.00 per preferred share)	—	—			—		—			(6,900		)	—			—			—			(6,900		)
Share-based compensation	78				1		5,780			—			—			—			—			5,781
Deferred compensation	31	—			—		(679		)	—			(319		)	—			321			(677		)
Exercise of stock options	3	—			—		16			—			—			—			—			16
Restricted stock unit vesting	78				1		(252		)	—			—			—			—			(251		)
Change in pension and postretirement benefit obligations	—	—			—		—			—			—			1,249			—			1,249
Other	—	—			—		(4,601		)	—			—			—			—			(4,601		)
Balance as of December 31, 2013	65,307	1,150			466		891,351			(104,180		)	2,792			267			(3,042		)	788,804
Net loss	—	—			—		—			(409,592		)	—			—			—			(409,592		)
Issuance of preferred stock	—	3,250					310,080			—			—			—			—			313,330
Conversion of preferred stock	5,926	(356		)	59		297			—			—			—			—			—
Payments to induce conversion of preferred stock	—	—			—		—			(4,256		)	—			—			—			(4,256		)
Dividends declared on preferred stock ($600.00 and $348.33 per Series A and Series B preferred share, respectively)	—	—			—		—			(17,148		)	—			—			—			(17,148		)
Share-based compensation	15	—			1		3,626			—			—			—			—			3,627
Deferred compensation	—	—			—		—			—			419			—			(303		)	116
Exercise of stock options	257	—			3		1,425			—			—			—			—			1,428
Restricted stock unit vesting	64	—			—		(474		)	—			—			—			—			(474		)
Change in pension and postretirement benefit obligations	—	—			—		—			—			—			(18		)	—			(18		)
Balance as of December 31, 2014	71,569	4,044			529		1,206,305			(535,176		)	3,211			249			(3,345		)	675,817
Net loss	—	—			—		—			(1,582,961		)	—			—			—			(1,582,961		)
Conversion of preferred stock	9,414	(898		)	94		804			—			—			—			—			—
Dividends declared on preferred stock ($300.00 and $300.00 per Series A and Series B preferred share, respectively)	—	—			—		—			(12,134		)	—			—			—			(12,134		)
Share-based compensation	195	—			4		4,536			—			—			—			—			4,540
Deferred compensation	2	—			—		—			—			229			—			(229		)	—
Restricted stock unit vesting	73	—			1		(557		)	—			—			—			—			(556		)
Change in pension and postretirement benefit obligations	—	—			—		—			—			—			173			—			173
Balance as of December 31, 2015	81,253	$	3,146		$	628	$	1,211,088		$	(2,130,271	)	$	3,440		$	422		$	(3,574	)	$	(915,121	)


4.	~~Acquisitions~~Bankruptcy Proceedings, Emergence and ~~Divestitures~~Fresh Start Accounting



Enterprise value	$	234,831
Plus: Cash and cash equivalents	31,414
Less: Fair value of debt	(75,350		)
Fair value of Successor Common Stock	$	190,895
Shares outstanding as of September 12, 2016	14,992,018
Per share value	$	12.73



						Reorganization					Fresh Start
			Predecessor			Adjustments					Adjustments					Successor
Assets
Current assets
	Cash and cash equivalents		$	48,718		$	(17,304	)	(1	)	$	—				$	31,414
	Accounts receivable, net of allowance for doubtful accounts		35,606			4,292			(2	)	—					39,898
	Derivative assets		397			—					—					397
	Other current assets		3,966			(832		)	(3	)	—					3,134
		Total current assets	88,687			(13,844		)			—					74,843
Property and equipment, net			309,261			—					(55,751		)	(12	)	253,510
Other assets			6,902			(1,281		)	(4	)	—					5,621
		Total assets	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974

Liabilities and Shareholders’ Equity (Deficit)
Current liabilities
	Accounts payable and accrued liabilities		$	77,151		$	(21,166	)	(5	)	$	(3,455	)	(13	)	$	52,530
	Derivative liabilities		1,641			—					—					1,641
	Current maturities of long-term debt		113,653			(113,653		)	(6	)	—					—
		Total current liabilities	192,445			(134,819		)			(3,455		)			54,171

Other liabilities			84,953			100			(5	)	(80,615		)	(14	)	4,438
Derivative liabilities			9,120			—					—					9,120
Long-term debt			—			75,350			(7	)	—					75,350
Liabilities subject to compromise			1,154,163			(1,154,163		)	(8	)	—					—

Shareholders’ equity (deficit)
	Preferred stock (Predecessor)		1,880			(1,880		)	(9	)	—					—
	Common stock (Predecessor)		697			(697		)	(9	)	—					—
	Paid-in capital (Predecessor)		1,213,797			(1,213,797		)	(9	)	—					—
	Deferred compensation obligation (Predecessor)		3,440			(3,440		)	(9	)	—					—
	Accumulated other comprehensive income (Predecessor)		383			(383		)	(9	)	—					—
	Treasury stock (Predecessor)		(3,574		)	3,574			(9	)	—					—
	Common stock (Successor)		—			150			(10	)	—					150
	Paid-in capital (Successor)		—			190,745			(10	)	—					190,745
	Accumulated deficit		(2,252,454		)	2,224,135			(11	)	28,319			(15	)	—
		Total shareholders’ equity (deficit)	(1,035,831		)	1,198,407					28,319					190,895
		Total liabilities and shareholders’ equity (deficit)	$	404,850		$	(15,125	)			$	(55,751	)			$	333,974


1.	Represents the net cash payments that occurred on the Emergence Date:



Sources:
Proceeds from the Credit Facility	$	75,350
Proceeds from the Rights Offering, net of issuance costs	49,943
Total sources			$	125,293
Uses:
Repayment of RBL	$	113,653
Accrued interest payable on RBL	1,374
DIP Facility fees	12
Debt issue costs of the Credit Facility	3,011
Funding of professional fee escrow account	14,575
RBL lender professional fees and expenses	455
Ad Hoc Committee and indenture trustee professional fees and expenses	6,782
Payment of certain allowed claims and settlements	2,735
Total uses			142,597
			$	(17,304	)


2.	Represents the reclassification of SERP assets to a current receivable from other noncurrent assets upon the cancellation of the underlying plan and the reversion of the assets to the Successor.


3.	Represents the write-off of certain prepaid directors and officers tail insurance.


4.	Represents the capitalization of debt issuance costs attributable to the Credit Facility, net of the reclassification of SERP assets as discussed in item (2) above.