Glossary of selected oil and natural gas terms

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.

2-D seismic. Geophysical data that depicts the subsurface strata in two dimensions.

3-D seismic. Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.

Appraisal wells. Wells drilled to convert an area or sub-region from the resource to the reserves category.

Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) same environment of deposition; (iii) similar geological structure; and (iv) same drive mechanism.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, NGLs or other liquid hydrocarbons.

Bbtu. One billion British thermal units.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate energy

equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price of six Mcf of natural gas.

Btu. British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting to the appropriate authority that the well has been abandoned.

Deterministic method. The method of estimating reserves or resources when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole; Dry well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically producible. As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploitation. The continuing development of a known producing formation in a previously discovered field. To maximize the ultimate recovery of oil or natural gas from the field by development wells, secondary recovery equipment or other suitable processes and technology.

Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Fracture stimulation. A stimulation treatment routinely performed involving the injection of water, sand and chemicals under pressure to stimulate hydrocarbon production.

Full cost pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Held-by-production. A provision in an oil, natural gas and mineral lease that perpetuates a company's right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or natural gas.

Horizontal wells. Wells drilled at angles greater than 70 degrees from vertical.

Initial production rate. Generally, the maximum 24 hour production volume from a well.

Mbbl. One thousand stock tank barrels.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Mmbbl. One million stock tank barrels.

Mmbtu. One million British thermal units.

Mmcf. One million cubic feet of natural gas.

Mmcf/d. One million cubic feet of natural gas per day.

Mmcfe. One million cubic feet of natural gas equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate

energy equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price of six Mcf of natural gas.

Mmcfe/d. One million cubic feet of natural gas equivalent per day calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Net acres or net wells. Exists when the sum of fractional ownership interests owned in gross acres or gross wells equals one. We compute the number of net wells by totaling the percentage interest we hold in all our gross wells.

NYMEX. New York Mercantile Exchange.

NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Overriding royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of the costs of production.

Pad drilling. The drilling of multiple wells from the same site.

Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.

Present value of estimated future net revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting future income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated.

Probabilistic method. The method of estimation of reserves or resources when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Productive well. A productive well is a well that is not a dry well.

Proved Developed Reserves. These reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved Reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with Reasonable Certainty to be economically producible from a

given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with Reasonable Certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with Reasonable Certainty. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with Reasonable Certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the Reasonable Certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes Reasonable Certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing Reasonable Certainty.

Recompletion. An operation within an existing well bore to make the well produce oil and/or natural gas from a different, separately producible zone other than the zone from which the well had been producing.

Reasonable Certainty. If deterministic methods are used, Reasonable Certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to EUR with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Resources. Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of the costs of production.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Shut-in well. A producing well that has been closed down temporarily for, among other things, economics, cleaning out, building up pressure, lack of a market or lack of equipment.

Spud. To start the well drilling process.

Standardized Measure of discounted future net cash flows or the Standardized Measure. Under the Standardized Measure, future cash flows are estimated by applying the simple average spot prices for the trailing 12 month period using the first day of each month beginning on January 1 and ending on December 1 of each respective year, adjusted for price differentials, to the estimated future production of year-end Proved Reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

Stock tank barrel. 42 U.S. gallons liquid volume.

Tcf. One trillion cubic feet of natural gas.

Tcfe. One trillion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas. This ratio of Bbl to Mcf is commonly used in the oil and natural gas industry and represents the approximate energy equivalent of natural gas to oil or NGLs, and does not represent the sales price equivalency of natural gas to oil or NGLs. Currently the sales price of a Bbl or NGL is significantly higher than the sales price for six Mcf of natural gas.

Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains Proved Reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production.

Workovers. Operations on a producing well to restore or increase production.

Available information

We make available, free of charge, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports on our website at www.excoresources.com as soon as reasonably practicable after those reports and other information are electronically filed with, or furnished to, the SEC.


Item 1A.	Risk Factors

The risk factors noted in this section and other factors noted throughout this Annual Report on Form 10-K, including those risks identified in “Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this Annual Report on Form 10-K.

Risks Relating to Our Restructuring

We have filed voluntary petitions for relief under the Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.

On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. Our business and operations will be subject to various risks for the duration of the Chapter 11 proceedings, including, but not limited to, the following:

our ability to continue as a going concern;

our ability to develop, file and consummate a Chapter 11 plan of reorganization;

our ability to obtain Court, creditor and regulatory approval of a Chapter 11 plan of reorganization in a timely manner;

our ability to obtain consents or waivers to further extend the DIP Facilities beyond the scheduled maturity date of May 22, 2019 or refinance the DIP Facilities if we are unable to consummate a plan of reorganization in a timely manner;

our ability to obtain Court approval with respect to motions in the Chapter 11 Cases and the outcomes of Court rulings and of the Chapter 11 Cases in general;

the ability of third parties to file motions in our Chapter 11 Cases, which may interfere with our business operations or our ability to propose and/or complete a Chapter 11 plan of reorganization;

~~increased~~significant costs related to the Chapter 11 Cases and related litigation;

our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers, as well as our ability to maintain contracts that are critical to our operations;

a loss of, or a disruption in the materials or services received from suppliers, contractors or service providers with whom we have commercial relationships;

potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees;

significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations; and

our ability to fund and execute our business plan and our ability to obtain any necessary financing for our business on acceptable terms or at all.

We are also subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the duration of the Chapter 11 Cases. For example, negative events or publicity associated with the Chapter 11 Cases could adversely affect our relationships with our vendors and employees, as well as with customers, which in turn could adversely affect our operations and financial condition. Also,

pursuant to the Bankruptcy Code, we need Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities.

Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.

We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings.

We have a significant amount of indebtedness that is senior to our existing common shares in our capital structure. As a result, we believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares ~~will~~are not expected to be entitled to any recovery. The March 2019 Plan would result in our common shares being canceled, discharged, released and extinguished without the holders thereof receiving any distribution. As a ~~limited recovery, if any. Any~~result, any trading in our common shares during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks to purchasers ~~of shares~~ of our common shares.

Operating under Court protection for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. ~~A long~~We have been operating under Court protection since our initial filing for relief under Chapter 11 of the Bankruptcy Code in January 2018, and this prolonged period of operations under Court protection ~~could~~has had, and is expected to continue to have, a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the proceedings related to the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations.

In conjunction with these bankruptcy proceedings, we are exploring the potential sale of certain or substantially all of our assets under Section 363 of the Bankruptcy Code. There can be no assurance that any such sale will be completed. The process to market our assets will result in additional uncertainty surrounding the potential outcome of the Chapter 11 Cases and could further delay the conclusion of the Chapter 11 Cases. A prolonged period of operating under Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our businesses successfully and seek to establish alternative commercial relationships.

During the course of the Chapter 11 Cases, we have been required, and expect that we will continue to be required, to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases. We have incurred $67.8 million in legal and professional fees related to the Chapter 11 Cases for the period from the Petition Date to December 31, 2018. Furthermore, we have experienced, and expect to continue to experience, significant costs and delays due to litigation during the Chapter 11 Cases. These fees and expenses have forced us to divert our capital resources away from capital expenditures to grow our business.

During the pendency of the bankruptcy proceedings, our Liquidity will depend mainly on cash generated from operating activities and available funds under the DIP Credit Agreement. On January 22, 2018, we closed the DIP Credit Agreement providing for $250.0 million of debtor-in-possession financing. The proceeds from the DIP Facilities were used to refinance all obligations outstanding under the EXCO Resources Credit Agreement and ~~will~~are expected to provide additional liquidity to fund our operations during the Chapter 11 Cases.

So long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases. Furthermore, we may experience significant costs and delays due to litigation during the Chapter 11 Cases. The DIP Facilities mature on May 22, 2019 and may not be sufficient to support our day-to-day operations in the event of a prolonged restructuring process and we may be required to seek additional debtor-in-possession financing to fund our operations. A further extension of the DIP Facilities beyond the scheduled maturity date would require a waiver or consent from the DIP Lenders. If we are ~~unable~~required to seek additional financing, we may not be able to obtain such financing on favorable terms or at ~~all,~~all. See further discussion regarding the impact of the maturity of the DIP Facilities in "Item 1A. Risk Factors - We have substantial liquidity needs and may be required to seek additional financing if we experience a prolonged bankruptcy process. If we are unable to maintain adequate liquidity, we may not be able to obtain financing on satisfactory terms". As a result, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any claims and securities in the Debtors could become further devalued or become worthless.

We cannot predict the ultimate outcome for the liabilities that will be subject to a plan of reorganization. Even if a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11.

We are subject to the risks and uncertainties associated with our exclusive right to file a plan of reorganization.

At the outset of the Chapter 11 proceedings, the Bankruptcy Code provides debtors-in-possession the exclusive right to file and solicit acceptance of a plan of reorganization for the first 120 days of the bankruptcy case, subject to extension at the discretion of the court. All other parties are prohibited from filing or soliciting a plan of reorganization during this period. Our initial filing exclusivity period was set to expire on May 15, 2018 and the solicitation exclusivity period was set to expire on July 14, 2018. The Court has approved multiple extensions to the filing exclusivity period and the solicitation exclusivity period. The most recent extensions were approved by the Court on February 15, 2019, which extended the filing exclusivity period through April 1, 2019 and the solicitation exclusivity period through May 31, 2019. If the Court terminates that right or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of a plan in order to achieve our stated goals. The possible decision of creditors and/or other third parties, whose interest may be inconsistent with our own, to file alternative plans of reorganization could further protract the Chapter 11 proceedings, leading us to continue to incur significant professional fees and costs. Because of these risks and uncertainties associated with the termination or expiration of our exclusivity rights, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 cases may have on our corporate or capital structure.

We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Court protection as a viable entity, we must meet certain statutory requirements with respect to a Chapter 11 plan of reorganization, including obtaining the requisite acceptances of such a plan, and certain other statutory conditions for confirmation of such a Chapter 11 plan, which have not occurred to date. We were not able to reach an agreement with our creditors for a plan of reorganization prior to commencement of the Chapter 11 Cases. Therefore, the outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and our creditors. ~~The confirmation process is subject to potential delays, which could include a delay in the Court’s commencement of the confirmation hearing regarding our plan.~~

We have not received consents from any creditors in support of the March 2019 Plan. Therefore, we may not receive the requisite acceptances ~~of our creditors in the proceedings related to the Chapter 11 Cases~~ to confirm ~~a plan.~~the March 2019 Plan. Even if the requisite acceptances of a plan are received, the Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, or common shares).

If a Chapter 11 plan of reorganization is not ultimately confirmed by the Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims. Our creditors would likely incur significant costs in connection with developing and seeking approval of an alternative plan of reorganization, which might not be supported by any of the current debt holders, various statutory committees or other stakeholders. If we are unable to confirm the March 2019 Plan and an alternative reorganization could not be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity. There can be no assurance as to whether we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 Cases.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, or market conditions deteriorate, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement will affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to:

changes in the price of oil and natural gas, including our increased exposure since none of our estimated future production is currently covered by commodity derivative contracts;

our ability to obtain adequate liquidity and financing sources, including acceptable terms for any new debt instruments contemplated by a plan of reorganization;

our ability to maintain the confidence of our vendors, customers and joint interest partners in our viability as a continuing entity and to attract and retain sufficient business with them;

our ability to retain key employees; and

the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets.

Adverse changes in any of these factors could materially affect the successful reorganization of our businesses. Accordingly, any Chapter 11 plan of reorganization may not enable us to achieve our goals or continue as a going concern.

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts will be even more speculative than normal, because they may involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face risks.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, changes in prices for oil and natural gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that any plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other means to fund our business after the completion of the Chapter 11 process. Adequate funds may not be available when needed or may not be available on favorable terms.

The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities.

The availability of borrowings under the DIP Credit Agreement is essential to our ability to fund our operations during the Chapter 11 Cases. The DIP Credit Agreement includes certain affirmative and negative covenants, including, among other covenants customary in similar reserve-based credit facilities and debtor-in-possession financings, requirements to maintain a

minimum level of liquidity and limit our aggregate disbursements to certain thresholds compared to the 13-week cash flow forecasts provided to the DIP Lenders. Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations, development activities and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. The DIP Facilities contain events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases.

If we violate any provisions of our such financing agreements that are not cured or waived within the appropriate time periods provided therein, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

We have substantial liquidity needs and may be required to seek additional financing if we experience a prolonged bankruptcy process. If we are unable to maintain adequate liquidity, we may not be able to obtain financing on satisfactory terms.

Our principal sources of Liquidity historically have been internally generated cash flows from operations, borrowings under certain credit agreements, issuances of debt securities, dispositions of non-strategic assets, joint ventures and capital markets when conditions are favorable. Our ~~capital program approved for 2018 will require additional~~Liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things; (i) our ability to comply with the terms and conditions of any post-petition financing ~~above~~and cash collateral order entered by the ~~level of~~Court in connection with the Chapter 11 Cases, (ii) our ability to maintain adequate cash ~~generated by~~on

hand, (iii) our ~~operations. As described above, we have entered into the DIP Facilities, but we cannot guarantee that the funds available under the DIP Facilities and our~~ability to generate cash flow from operations, ~~will be sufficient~~(iv) our ability to ~~fund~~develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction and (v) the cost, duration and outcome of the Chapter 11 Cases. Our ability to maintain adequate Liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our ~~operations if we experience a prolonged bankruptcy process.~~control.

We face uncertainty regarding the adequacy of our Liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirement necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 Cases. We cannot provide assurance that our Liquidity will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to Chapter 11 Cases until we are able to emerge from our Chapter 11.

~~Our Liquidity, including our ability~~The DIP Facilities are currently set to ~~meet our ongoing operational obligations, is dependent upon, among other things; (i) our ability~~mature on May 22, 2019. In order to comply with the terms and conditions of any post-petition financing and cash collateral order entered by the Court in connection with the Chapter 11 Cases, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction and (v) the cost, duration and outcome of the Chapter 11 Cases. Our ability to maintain adequate Liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event thatrepay the DIP Facilities ~~and our cash on hand and cash flow from operations are not sufficient to meet our Liquidity needs,~~at maturity, we ~~may be required~~currently expect that we would need to seek additional ~~financing.~~financing, sell assets, refinance or restructure the DIP Facilities prior to maturity or extend the maturity date of the DIP Facilities. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Although we have previously extended the maturity date of the DIP Facilities, the DIP Lenders may not agree to any further extensions. Our ability to consummate the March 2019 Plan in a timely manner, if at all, is subject to significant risk since we have not received consents from any creditors in support of the March 2019 Plan. As a result, it is unlikely that we will be able to consummate a plan of reorganization prior to the maturity of the DIP Facilities. Therefore, our long-term ~~Liquidity requirements~~liquidity and the adequacy of our capital resources are ~~difficult to predict~~highly uncertain at this time.

Upon emergence from bankruptcy, the composition of our board of directors will change significantly.

The composition of our board of directors is expected to change significantly following the Chapter 11 Cases. Any new directors may have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Court may convert our Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations. In addition, if the Chapter 11 Cases are converted to cases under Chapter 7, that would constitute an event of default under the DIP Credit Agreement.

As a result of the Chapter 11 Cases, our historical financial information may be volatile and not be indicative of our future financial performance.

During the Chapter 11 Cases, we expect our financial results under U.S. GAAP to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments may significantly impact our Consolidated Financial Statements. As a result, our historical financial performance may not be indicative of our financial performance after the date of the bankruptcy filing.

Our capital structure will likely be significantly altered under any Chapter 11 plan confirmed by the Court. Under fresh-start accounting rules that may apply to us upon the effective date of a Chapter 11 plan, our assets and liabilities would be adjusted to fair value, which could have a significant impact on our financial statements. Accordingly, if fresh-start accounting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Chapter 11 Cases and the development of a Chapter 11 plan, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to our consolidated financial position, liquidity and results of operations.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 Cases, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have NOLs of approximately ~~$2.1~~$2.2 billion as of December 31, ~~2017.~~2018. Our ability to utilize our NOLs to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in Section 382 of the U.S. Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more shareholders owning five percent or more of a corporation’s common stock ("Substantial Shareholder") have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period.

We received relief from the Court to establish notice and sell-down procedures for trading of our common shares in order to provide us with the ability to formulate a plan of reorganization that preserves our tax attributes. Under the order, prior to any proposed acquisition or disposition of equity securities that would result in an increase or decrease in the amount of our equity securities owned by a Substantial Shareholder, or that would result in a person or entity becoming a Substantial Shareholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition. We have the right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.

Following the implementation of a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under Section 382 of the U.S. Internal Revenue Code, absent an application exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation. If an ownership change occurs and our NOLs are subject to the Section 382 limitation, this could adversely impact our future cash flows if we have taxable income and are not able to offset it through the utilization of our NOLs. See further discussion of the impact of the restructuring on our tax attributes as part of "Note 12. Income taxes" in the Notes to our Consolidated Financial Statements.

We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivative contracts and we may not be able to enter into commodity derivative contracts covering our estimated future production on favorable terms or at all.

During the Chapter 11 Cases, our ability to enter into commodity derivative contracts covering estimated future production is limited under the DIP Credit Agreement. We are only permitted to enter into commodity derivative contracts with lenders under the DIP Credit Agreement. As a result, we may not be able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at all. IfNone of our estimated future production is currently covered by commodity derivative contracts; therefore, we will continue to be significantly impacted by changes in commodity prices if we cannot or choose not to enter into commodity derivative contracts in the ~~future, we could be more affected by changes in commodity prices.~~future. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

We have and may continue to experience increased levels of employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, we have and may continue to experience increased levels of employee attrition, and

our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, Liquidity and results of operations.

Risks Relating to Our Business

Oil and natural gas prices, which are subject to fluctuations, have declined substantially from historical highs. Reductions in oil and natural gas prices have, and may in the future, adversely affect our revenues as well as our ability to maintain or increase our borrowing capacity, repay current or future indebtedness and obtain additional capital on attractive terms.

Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. We are particularly dependent on prices for natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including, but not limited to:

the domestic and foreign supply of oil and natural gas;

weather conditions;

the price and quantity of imports and exports of oil and natural gas;

political conditions and events in other oil-producing and natural gas-producing countries, including embargoes, hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

the actions of the ~~OPEC;~~OPEC and other significant oil and natural gas producing nations;

domestic and international government regulation, legislation and ~~policies;~~policies, including levying tariffs on oil and natural gas imports;

the level of global oil and natural gas inventories;

technological advances affecting energy consumption;

the price and availability of alternative fuels and other energy sources; and

overall economic conditions.

Oil and natural gas prices ~~declined sharply during the latter half of 2014 and continued~~are currently depressed compared to ~~decline throughout 2015 and into 2016. Oil and natural gas prices have recently experienced a modest recovery;~~recent historical levels; however, they may never return to historical highs or remain at a level that allows us to economically operate our business. Prices of oil and natural gas have historically been extremely volatile and we expect this volatility to continue.

During ~~2017,~~2018, the NYMEX Henry Hub natural gas price fluctuated from a high of ~~$3.65~~$6.88 per Mmbtu to a low of ~~$2.44~~$2.48 per Mmbtu, while the NYMEX WTI crude oil price ranged from a high of ~~$60.42~~$76.41 per Bbl to a low of $42.53 per Bbl. For the five years ended December 31, ~~2017,~~2018, the NYMEX Henry Hub natural gas price ranged from a high of $7.94 per Mmbtu to a low of $1.49 per Mmbtu, while the NYMEX WTI crude oil price ranged from a high of ~~$110.53~~$107.26 per Bbl to a low of $26.21 per Bbl.

On December 31, ~~2017,~~2018, the spot market price for natural gas at Henry Hub was ~~$2.97~~$3.07 per Mmbtu, a ~~20% decrease~~3% increase from December 31, ~~2016.~~2017. On December 31, ~~2017,~~2018, the spot market price for crude oil at Cushing was ~~$60.42~~$45.41 per Bbl, a ~~12% increase~~25% decrease from December 31, ~~2016.~~2017. For ~~2017,~~2018, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were ~~$49.82~~$66.78 per Bbl and ~~$2.51~~$2.85 per Mcf, respectively, compared with ~~2016~~2017 average realized prices of ~~$38.05~~$49.82 per Bbl and ~~$1.93~~$2.51 per Mcf, respectively.

Our revenues, cash flow and profitability, as well as our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, depend substantially upon oil and natural gas prices. Any sustained reductions in oil and natural gas prices will directly affect our revenues and can indirectly impact expected production by changing the amount of funds available to us to reinvest in exploration and development activities. Further reductions in oil and natural gas prices could also reduce the quantities of reserves that are commercially recoverable. Depressed oil and natural gas prices and reductions in our reserves could have other adverse consequences, including ~~downward redeterminations~~our ability to obtain the exit financing required to consummate a plan of ~~the availability of borrowings under the DIP Credit Agreement, which may begin on January 1, 2019 if we elect to extend the maturity of the DIP Credit Agreement.~~reorganization. Additionally, further or continued declines in prices could result in additional non-cash charges to earnings due to impairments to our oil and natural gas properties.

In light of the depressed commodity price environment, there is risk that, among other things:

third parties’ confidence in our commercial or financial ability to explore and produce oil and natural gas could erode, which could impact our ability to execute on our business strategy;

it may become more difficult to retain, attract or replace key employees;

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

our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.

The occurrence of certain of these events may have a material adverse effect on our business, results of operations and financial condition.

Changes in the differential between NYMEX or other benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we use to price our oil and natural gas sales sometimes reflect a premium or discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could have a material adverse effect on our results of operations and financial condition. We have experienced significant volatility in our price differentials including crude oil production from the Eagle Ford shale and natural gas production from certain areas in Appalachia. Our crude oil production from the Eagle Ford shale is currently sold at a price based on the WTI index plus or minus the differential to indices correlated to the Louisiana Light Sweet index. During ~~2017,~~2018, the monthly average of this differential ranged from a high of WTI plus ~~$4.19~~$4.99 per barrel to a low of WTI less ~~$3.27~~$0.99 per barrel. Our natural gas production from the Marcellus shale in Northeast Pennsylvania is sold at a price based on a Platts index that represents value into the Transco Leidy Pipeline. Due to the ~~increased~~high levels of production in this region without ~~an offsetting increase in~~sufficient pipeline capacity or infrastructure to the Northeast United States markets, the monthly average of this differential during ~~2017~~2018 ranged from a low of NYMEX less ~~$0.44~~$0.31 per Mmbtu to a high of NYMEX less ~~$2.11~~$1.38 per Mmbtu. These differentials vary depending on factors such as supply, demand, pipeline capacity, infrastructure and weather. These differentials continue to be volatile; however, the differentials in the region have the potential to be favorably impacted by the expansion of infrastructure and other sources of demand for natural gas in the Northeast region in future years.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements or infrastructure may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities.

Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations owned and operated by third-parties. Our failure to obtain these services on acceptable terms could have a material adverse effect on our business. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs, outages caused by accidents or other events, or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. We may be required to ~~shut in~~shut-in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines, gathering systems or trucking capacity. A portion of our production may also be interrupted, or shut-in, from time to time for numerous other reasons, including as a result of accidents, excessive pressures, maintenance, weather, field labor issues or other disruptions of service. Curtailments and disruptions may last from a few days to several months, and we have no control over when or if third-party facilities are restored.

We have experienced production curtailments in our producing regions resulting from offsetting fracturing stimulation operations. As we have increased our knowledge of our shale properties, we have begun to shut-in production on adjacent wells when conducting completion operations. Due to the high production capabilities of these wells, these volumes can be significant. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.

In our South Texas region, the primary purchaser of our natural gas allegedly terminated a long-term natural gas sales contract on May 31, 2017. See further discussion of the litigation related to the purported termination of this contract in "Item 3. Legal proceedings". Our ability to transport or sell the natural gas from this region is limited due to the existing

infrastructure and we may experience significant curtailments of production if we cannot find an operational or commercial solution. After the alleged termination of the long-term natural gas sales contract, we have either sold natural gas on short-term sales contracts or flared natural gas in order to avoid significant curtailments of our oil production. However, our ability and the costs associated with entering into natural gas sales contracts in the future are highly uncertain.

These factors and the availability of markets are beyond our control. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities or lack of availability of transportation would interfere with our ability to market our oil and natural gas production, and could have a material adverse effect on our cash flow and results of operations.

Our oil production in the South Texas region may be curtailed if we are not able to find an operational or commercial solution for the associated natural gas production.

In our South Texas region, the primary purchaser of our natural gas allegedly terminated a long-term natural gas sales contract on May 31, 2017. As a result, our ability to transport or sell the natural gas from this region continues to be limited due to the existing infrastructure and we may experience significant curtailments of production in the future if we cannot find an

operational or commercial solution. After the alleged termination of the long-term natural gas sales contract, we have either sold natural gas on short-term sales contracts or flared natural gas in order to avoid significant curtailments of our oil production. However, our ability and the costs associated with entering into natural gas sales contracts in the future are highly uncertain.

In January 2018, we commenced the flaring of natural gas produced in our South Texas region pursuant to temporary flare permits. We submitted a request to the Texas Railroad Commission for an extension of the permits to continue the aforementioned flaring of natural gas for up to two years (the “Flaring Application”). We went before the Texas Railroad Commission at a hearing regarding the Flaring Application in May 2018 and expect that a final ruling will be issued during 2019. See further discussion in “Item 3. Legal Proceedings”. If the Flaring Application is denied or, in the future, we are unable, for any sustained period, to secure acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut-in or curtail production of both oil and natural gas from the affected wells in the South Texas region. Any such shut-in or curtailment or an inability to obtain acceptable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our cash flows and results of operations. We continue to evaluate alternatives, including construction of a Company-owned gathering system or the negotiation of a new gathering agreement.

We may experience a financial loss if any of our significant customers fail to pay us for our oil or natural gas or reduce the volume of oil and natural gas that they purchase from us.

Our ability to collect payments from the sale of oil and natural gas to our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fails to pay us for any reason, we could experience a material loss. We are managing our credit risk as a result of the current commodity price environment through the attainment of financial assurances from certain customers. In addition, if any of our significant customers cease to purchase our oil or natural gas or reduce the volume of the oil or natural gas that they purchase from us, the loss or reduction could have a detrimental effect on our production volumes and may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas. We have filed a lawsuit against a subsidiary of Shell regarding their failure to remit payment under certain natural gas sales agreements in the East Texas and North Louisiana regions, see further discussion in "Item 3. Legal proceedings".

We have significant natural gas firm transportation and marketing agreements primarily in East Texas and North Louisiana that require us to pay fixed amounts of money to the shippers or marketers regardless of quantities actually shipped or marketed. Our results of operations and Liquidity could be adversely affected if we are required to pay for shortfall amounts under these contracts.

We have significant natural gas firm transportation contracts primarily in North Louisiana that require us to pay fixed amounts of money to the shippers regardless of quantities actually shipped. The use of firm transportation agreements allows us priority space in a shippers’ pipeline. Historically, we have paid significant amounts for the unused portion of these firm transportation agreements. These contracts include a natural gas sales contract with Enterprise Products Operating LLC (“Enterprise”) and a firm transportation agreement with Acadian Gas Pipeline System (“Acadian”) that are currently in litigation. See further discussion of the litigation related to our natural gas sales and firm transportation agreements in "Item 3. Legal proceedings". In addition, we are in default under a firm transportation contract with Regency Intrastate Gas LLC ("Regency") since we failed to remit payment during 2017. As a result, Regency is entitled to exercise certain rights and remedies, including the acceleration of the remaining charges under the agreement. As of December 31, 2017, the unpaid amounts and remaining charges under this agreement were $67.3 million.

We have an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems over a five-year period ending on November 30, 2018. If there is a shortfall to the minimum volume commitment in any year, then we are severally responsible with a joint venture partner to pay fixed amounts of money to the gatherer regardless of quantities actually produced in to the systems. For the twelve months ended November 30, 2017, our net share of the shortfall was $23.1 million, which had not been paid prior to the commencement of the Chapter 11 Cases.

In addition, we have sales and marketing agreements in North Louisiana whereby we are required to deliver a minimum amount of natural gas. These contracts include a natural gas sales contract with a subsidiary of Shell that is currently in litigation. See further discussion of the litigation in "Item 3. Legal proceedings".

~~On January 18, 2018, the Company and the Filing Subsidiaries filed motions to reject certain executory contracts as permitted under the Bankruptcy Code. The contracts include the following:~~

~~Firm transportation agreements with Acadian, which required us to transport 325,000 Mmbtu per day on the Acadian Gas Pipeline System or pay reservation charges through October, 31, 2025;~~

~~Natural gas sales agreements with Enterprise, which required us to sell 75,000 Mmbtu per day of natural gas to Enterprise or incur certain costs through October 31, 2025;~~

~~Firm transportation agreements with Regency, which required us to either transport 237,500 Mmbtu per day of natural gas or pay reservation charges through January 31, 2020;~~

~~Marketing agreement with Chesapeake, which required us to allow Chesapeake to purchase natural gas for certain wells in North Louisiana through 2021; and~~

~~Natural gas sales agreements with Shell, which required us to sell 100,000 Mmbtu per day of natural gas to Shell or incur certain costs through November 30, 2020.~~

On March 7, 2018, the Court approved the rejection of the aforementioned executory contracts with Regency, Chesapeake and Shell. The hearing to consider the motion to reject the Enterprise and Acadian contracts is scheduled for March 29, 2018. On March 1, 2018, the Company and the Filing Subsidiaries filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems through November 30, 2018. See further discussion of the future minimum obligations under these contracts as of December 31, 2017 in "Note 8. Commitments and contingencies" and the motions to reject these contracts in "Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements.

~~If we are not able to reject the remainder of these contracts, it could adversely affect our business, financial condition and results of operations.~~

There are risks associated with our drilling activity that could impact our results of operations and financial condition. Our ability to develop properties in new or emerging formations may be subject to more uncertainties than drilling in areas that are more developed or have a longer history of established production.

Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. Additionally, seismic and other technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. We have experienced some delays in contracting for drilling rigs and in obtaining fracture stimulation crews and materials. Also, we may experience issues with the availability of water and sand used in our drilling and hydraulic fracturing activities. All of these risks could adversely affect our results of operations and financial condition.

The results of our drilling in new or emerging formations, including our properties in shale formations, are more uncertain initially than drilling results in areas that are developed, have established production or where we have a longer history of operation. Because new or emerging formations have limited or no production history, we are less able to use past drilling results in those areas to help predict future drilling results. Our experience with horizontal drilling in these areas to date, as well as the industry’s drilling and production history, while growing, is limited. The ultimate success of these drilling and completion techniques will be better evaluated over time as more wells are drilled and production profiles are better established. We have implemented several initiatives to manage our base production and minimize the decline from our shale properties. If these initiatives are not successful and we are required to incur significant expenditures to manage our base production, this could negatively impact our production and cash flows from operations.

If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, and/or natural gas and oil prices decline, our investment in these areas may not be as attractive as we anticipate and we could incur material impairments of undeveloped properties and the value of our undeveloped acreage could decline in the future, which could have a material adverse effect on our business and results of operations.

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.

We conduct a substantial portion of our operations through joint interest and joint venture arrangements. Material disagreements with our partners could have a material adverse effect on the success of these operations, our financial condition and our results of operations. Furthermore, the actions taken by our partners could prevent or alter our development plans.

We conduct a substantial portion of our operations through joint interest and joint venture arrangements with third parties. In many instances, we depend on these third parties for elements of these arrangements, such as payments of substantial development and other costs. The performance of these third party obligations or the ability of third parties to meet their obligations under these arrangements is outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements, and their value to us, may be adversely affected. If our current or future joint interest or joint venture partners are unable to meet their obligations, we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights, which may cause disputes among our partners and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations.

Such arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

our partners may share certain approval rights over major decisions;

the possibility that our partners might become insolvent or bankrupt, leaving us liable for their shares of joint interest or joint venture liabilities;

the possibility that we may incur liabilities as a result of an action taken by our partners;

partners may be in a position to take action contrary to our instructions or requests or contrary to our policies or objectives;

disputes between us and our partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and prevent our officers and directors from focusing their time and effort on our business; and

that under certain joint venture arrangements, neither joint venture partner may have the power to control the venture and an impasse could be reached that might have a negative influence on our investment in the joint venture.

The failure to resolve disagreements with our partners could adversely affect our ability to transact the business that is the subject of such arrangement, which would in turn negatively affect our financial condition and results of operations. We are currently in litigation with a subsidiary of Shell related to their failure to remit payment for natural gas sales in the East Texas and North Louisiana regions. The outcome of the litigation could impact our joint venture with Shell in the East Texas and North Louisiana regions. See further discussion related to this litigation in "Item 3. Legal proceedings". Furthermore, on January 26, 2018, we filed a motion to authorize the entry into a settlement agreement with Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region. Under the terms of the settlement agreement, our joint venture with Shell in the Appalachia region would be terminated. The Court approved this settlement agreement on February 22, 2018, and the settlement agreement closed on February 27, 2018. See further discussion related to the settlement agreement in "Note 17. Subsequent events" in the Notes to our Consolidated Financial Statements.

The owners of working interests may not consent to the development of certain properties that we operate, which may require us to assume their share of the working interest during the development and a period after the well is on production. This may require us to expend additional capital that was not anticipated as part of our development plans and assume additional risks associated with the development and future performance of the properties. The owners of working interests in certain properties that we operate may also hold rights within the respective operating agreements that could prevent us from performing additional development activities on the properties such as recompletions and other workovers without their consent.

We may be unable to acquire or develop additional reserves, which would reduce our revenues and access to capital.

Our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder our ability to acquire or develop additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale. If we are unable to conduct successful development activities or acquire properties containing Proved Reserves, our total Proved Reserves will generally decline as a result of production. Also, our production will generally decline. We may be unable to locate additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.

Acquisitions, development drilling and exploratory drilling are the main methods of replacing reserves. However, development and exploratory drilling operations may not result in any increases in reserves for various reasons. Our future oil and natural gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. Throughout 2016 and 2017 we reduced our development activities and suspended drilling in certain regions, which caused our production to decline and negatively impacted our ability to replace our reserves, which in turn negatively impacted our operating results.

We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, exploration, development and exploitation activities.

Our future success will depend on the success of our acquisition, exploration, development and exploitation activities. Our decisions to purchase, explore, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. These decisions could significantly reduce our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.

Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves, our financial condition and the value of our common shares.

Numerous uncertainties are inherent in estimating quantities of Proved Reserves, including many factors beyond our control. This Annual Report on Form 10-K contains estimates of our Proved Reserves and the PV-10 and Standardized Measure of our Proved Reserves. These estimates are based upon reports of our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as the current market value of our estimated Proved Reserves.

The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, the estimates are inherently imprecise evaluations of reserve quantities and future net revenue and such estimates prepared by different engineers or by the same engineers at different times, may vary substantially.

Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and Standardized Measure described in this Annual Report on Form 10-K, and our financial condition. In addition, our reserves, the amount of PV-10 and Standardized Measure may be revised downward or upward, based upon production history, results of future exploitation and development activities, prevailing oil and natural gas prices, decisions and assumptions made by engineers and other factors. A material decline in prices paid for our production can adversely impact the estimated volumes and values of our reserves. Similarly, a decline in market prices for oil or natural gas may adversely affect our PV-10 and Standardized Measure. Any of these negative effects on our reserves or PV-10 and Standardized Measure may negatively affect the value of our common shares.

Impairments of our asset values could have a substantial negative effect on our results of operations and net worth.

We follow the full cost method of accounting for our oil and natural gas properties. Depending upon oil and natural gas prices in the future, and at the end of each quarterly and annual period when we are required to test the carrying value of our assets using full cost accounting rules, we may be required to record an impairment to the value of our oil and natural gas properties if the present value of the after-tax future cash flows from our oil and natural gas properties falls below the net book value of these properties. We have in the past experienced, and may experience in the future, ceiling test impairments with respect to our oil and natural gas properties. As discussed above, we are also currently in Chapter 11 proceedings and, upon the approval of a Chapter 11 plan, may be required to apply fresh-start accounting principles that may cause us to experience additional impairments. See “Item 1A. Risk Factors - As a result of the Chapter 11 cases, our historical financial information may be volatile and not be indicative of our future financial ~~performance”~~performance” for additional information.

Our evaluation of impairment is based upon estimates of Proved Reserves. The value of our Proved Reserves may be lowered in future periods as a result of a decline in prices of oil and natural gas, a downward revision of our oil and natural gas reserves or other factors. As a result, our evaluation of impairment for future periods is subject to uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development

activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because several of these factors are beyond our control, we cannot accurately predict or control

the amount of ceiling test impairments in future periods. Future ceiling test impairments could negatively affect our results of operations and net worth.

We did not recognize any impairments to our proved oil and natural gas properties for the ~~year ended December 31, 2017. For the~~ years ended December 31, ~~2016~~2018 and ~~2015, we recognized impairments of $160.8 million and $1.2 billion to our proved oil and natural gas properties.~~2017. We may have additional impairments of our oil and natural gas properties in future periods if the cost of our unamortized proved oil and natural gas properties exceeds the limitation under the full cost method of accounting. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

We also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting unit exceeds the estimated fair value of the reporting unit, an impairment charge will occur, which would negatively impact our results of operations and net worth. As a result of our testing of goodwill for impairment, we did not record an impairment charge for the years ended December 31, ~~2017, 2016~~2018 and ~~2015.~~2017.

We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

fires, explosions and blowouts;

pipe failures;

abnormally pressured formations; and

environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

We have in the past experienced some of these events during our drilling, production and midstream operations. These events may result in substantial losses to us from:

injury or loss of life;

severe damage to or destruction of property, natural resources and equipment;

pollution or other environmental damage;

environmental clean-up responsibilities;

regulatory investigation;

penalties and suspension of operations; or

attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these potential losses or liabilities. Furthermore, insurance coverage may not continue to be available at commercially acceptable premium levels or at all. Due to cost considerations, from time to time we have declined to obtain coverage for certain drilling activities. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our results of operations and cash flow.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to comply with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, production and sale of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations. For additional information, see “Item 1. Business - Applicable Laws and Regulations".

Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures and could negatively impact production.

Our operations are subject to numerous complex U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements.

In general, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. For example, the EPA has identified ensuring environmental compliance by the energy extraction ~~section~~sector as one of its enforcement initiatives for fiscal years 2017 - 2019. ~~This~~However, the EPA has proposed to transition away from a sector specific initiative ~~was identified during~~for the ~~prior administration and it is unclear whether the new administration will continue with the ongoing initiatives.~~2020-2023 fiscal years to a more general focus on significant sources of VOCs.

Compliance with environmental laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations as well as associated natural resource damages, or the issuance of injunctive relief. Any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Changes to the requirements for drilling, completing, operating, and abandoning wells and related facilities could have similar adverse effects on us.

In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent than those currently in effect. For example, the regulation of GHG emissions by the EPA or by various states in the areas in which we conduct business could have an adverse effect on our operations and demand for our oil and natural gas production. Moreover, the EPA has shown a general increased scrutiny on the oil and gas industry through its regulations under the CAA, SDWA, RCRA, TSCA and CWA.

The environmental laws and regulations to which we are subject may, among other things:

require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;

restrict the types, quantities and concentrations of substances that can be released into the environment in connection with drilling, hydraulic fracturing, and production activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other “waters of the United States,” threatened and endangered species habitats and other protected areas;

require remedial measures to mitigate pollution from current or former operations, such as cleaning up spills, dismantling abandoned facilities, pit closure or plugging abandoned wells;

require additional control and monitoring devices on equipment; and

impose substantial liabilities for pollution resulting from our operations.

Our operations may be impacted by recent or changing regulatory standards. For example, the EPA issued effluent limitation guidelines limiting our ability to dispose of waste water from hydraulic fracturing activities into publicly owned wastewater treatment systems. The EPA and state regulators are also reviewing the practices for the disposal of solid waste in surface impoundments from exploration and production facilities under Subtitle D of RCRA and may continue to refine those requirements. The EPA and state regulators are also expanding National Pollutant Discharge Elimination System permitting for storm water discharges at drilling sites.

Changes in regulation can also occur at a state or local level. For example, the State of Pennsylvania Department of Environmental Protection is updating oil and gas regulations which include more stringent permitting requirements, waste handling disposal and water restoration requirements. Some localities, for example in Texas, are enacting water usage restrictions that may impact oil and gas exploration. In addition, some states have considered, and notably California has adopted, a state specific GHG regulatory program that may limit GHG emissions or may require costs in association with the control of GHG emissions.

The implementation of climate change regulations could result in increased operating costs and reduced demand for our oil and natural gas production.

GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for our oil and natural gas production. In the most recent Congressional session, a resolution was proposed which aimed to dramatically reduce GHG emissions, including a transition from fossil fuel. It is unclear what the future of this or other legislation would be. However, such legislation if adopted could have an adverse effect on demand for the oil and natural gas that we produce.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the U.S. Supreme Court struck down GHG permitting requirements for GHG as a stand-alone pollutant, it upheld the EPA’s authority to control GHG emissions when a source has to secure a major source permit to control the emissions of other criteria pollutants. These permitting provisions, to the extent applicable to our operations, could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements. Additionally, the EPA established GHG reporting requirements for a broad range of sources, including in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although this rule does not limit the amount of GHGs that can be emitted, it requires us to incur costs to monitor record and report GHG emissions associated with our operations.

As part of a move to reduce GHG emissions, the EPA has issued new rules limiting methane emissions from new or modified oil and gas sources. The rules amend the air emissions rules for the oil and natural gas sources and natural gas processing and transmission sources to include new standards for methane. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes. The grouping together of sources may cause a group of sources to be treated as a “major source” and face enhanced regulation under federal environmental laws, including the CAA.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Most hydraulic fracturing (other than hydraulic fracturing using diesel) is exempted from regulation under the SDWA. Congress has considered legislation to amend the federal SDWA to remove the exemption from regulation and permitting that is applicable to hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Many states have adopted or are considering legislation regulating hydraulic fracturing, including the disclosure of chemicals used in the process. Such bills or similar legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance. At the state and local levels, some jurisdictions have adopted, and others are considering adopting, requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, as well as bans on hydraulic fracturing activities. In the event that new or more stringent state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we have properties, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program (“UIC”) and has issued guidance regarding its authority over the permitting of these activities. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. If this assessment results in additional regulatory scrutiny, it could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations.

Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

These new initiatives related to hydraulic fracturing may increase our cost of disposal and impact our business operations and could cause our hydraulic fracturing activities to become subject to additional permit requirements or operations

restrictions which could lead to permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we ultimately are able to produce.

The EPA has adopted rules to limit air emissions from oil and gas operations, subjecting oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and NESHAPS programs under the CAA. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device, or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. The implementation of these new requirements may result in increased operating and compliance costs, increased regulatory burdens and delays in our operations. There may also be further refinement to existing NSPS standards for VOCs as data is gathered about the implementation of those requirements.

We operate in a litigious environment.

Any constituent could bring suit regarding our existing or planned operations or allege a violation of an existing contract. Any such action could delay when planned operations can actually commence or could cause a halt to existing production until such alleged violations are resolved by the courts. Not only could we incur significant legal and support expenses in defending our rights, but halting existing production or delaying planned operations could impact our future operations and financial condition. In addition, we are defendants in numerous cases involving claims by landowners for surface or subsurface damages arising from our operations and for claims by unleased mineral owners and royalty owners for unpaid or underpaid revenues customary in our business. We incur costs in defending these claims and from time to time must pay damages or other amounts due. Such legal disputes can also distract management and other personnel from their primary responsibilities. For additional information on our significant litigation matters, see “Item 3. Legal Proceedings" and "Note 8. Commitments and contingencies” in the Notes to our Consolidated Financial Statements.

Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions.

As an oil and natural gas production company, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. The implementation of additional procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

There are inherent limitations in all internal ~~control~~controls over financial reporting, and misstatements due to error or fraud may occur and not be detected.

While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in our ability to control all circumstances. Our management, including our chief financial officer and chief accounting officer, do not expect that our internal controls and disclosure controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent

limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future

events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of our company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

The Consolidated Financial Statements included herein contain disclosures that express substantial doubt about our ability to continue as a going concern, indicating the possibility that we may not be able to operate in the future.

The Consolidated Financial Statements included herein have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. The Consolidated Financial Statements do not reflect any adjustments that might result from the outcome of our Chapter 11 proceedings. Our level of indebtedness has adversely impacted and is continuing to adversely impact our financial condition. The outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and our creditors. The significant risks and uncertainties related to our liquidity and Chapter 11 proceedings described above raise substantial doubt about our ability to continue as a going concern.

See further discussion regarding our ability to continue as a going concern as part of "Note 1. Organization and basis of presentation" in the Notes to our Consolidated Financial Statements.

Risks Relating to Our Common Shares

Our common shares are no longer listed on a national securities exchange and ~~are quoted only in over-the-counter markets,~~were deregistered under the Exchange Act, which may have a negative impact on our share price, volatility and Liquidity.

On December 22, 2017, the NYSE suspended trading in our common shares and commenced proceedings to delist our common shares due to our failure to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million pursuant to Section 802.01B of the NYSE Listed Company Manual.

OnSince December 27, 2017, our common shares ~~began~~have been trading over the counter on the OTC Pink Marketplace under the ticker symbol “XCOO.” Our common shares continue to trade under that symbol with the added designation of “Q” to symbolize that we are currently in bankruptcy proceedings.

~~The~~Our bankruptcy proceedings, as well as the delisting of our common shares from the NYSE and commencement of trading on the OTC Pink Marketplace, has resulted and may continue to result in a significant reduction in some or all of the following, each of which could have a material adverse effect on our shareholders:

the liquidity of our common shares;

the market price of shares of our common shares;

our ability to obtain financing for the continuation of our operations;

the number of institutional and other investors that will consider investing in shares of our common shares;

the number of market makers in our common shares;

the availability of information concerning the trading prices and volume of our common shares; and

the number of broker-dealers willing to execute trades in our common shares.

~~Although~~There is no assurance that we will continue to trade on the OTC Pink Marketplace as we are dependent on one or more market makers establishing a market for our common shares, ~~have been delisted from~~and even if they continue to do so, there can be no assurance that an active trading market will be maintained. Broker-dealers may decline to trade in the ~~NYSE,~~OTC Pink Marketplace because (1) the market for such securities is often limited, (2) such securities are generally more volatile, and (3) the risk to investors is generally greater. Selling our shares could be difficult because smaller quantities of shares can be bought and sold, transactions can be delayed and securities analyst and media coverage of us may be reduced. These factors could result in lower prices and larger spreads in the bid and ask prices for shares of our common shares as well as lower trading volume. We cannot provide any assurance that, even if our common shares continue to be listed or quoted on the OTC Pink Marketplace or another market or system, the market for our common shares will be liquid.

On February 15, 2019, we ~~are required to continue filing periodic reports with the SEC unless and until we take action to deregister~~deregistered our common shares under ~~Section 12(g) of~~ the Exchange Act, which terminated the requirement to publicly file reports including financial statements and ~~suspend~~other pertinent information about the Company. As a result, our ~~reporting obligations under Section 15(d)~~common share price and liquidity of our common shares may be further negatively impacted since there will be significantly less public information about the ~~Exchange Act.~~Company.

We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares are not expected to be entitled to any recovery. As a result, we expect that the market for our common shares will be extremely limited during the pendency of our bankruptcy proceedings. See Item "1A. Risk Factors - We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings".

Our common share price may fluctuate ~~significantly.~~or remain significantly depressed throughout the pendency of our bankruptcy proceedings.

Our common shares currently trade on ~~the~~ OTC Pink Marketplace but ~~an active trading market for~~may have severely limited liquidity as a result of our ~~common shares may not be sustained.~~bankruptcy proceedings, among other things. The market price of our common shares ~~could fluctuate significantly~~has previously experienced significant fluctuations as a result of:

bankruptcy proceedings and the outcome of the Chapter 11 Cases;

dilutive issuances of our common shares;

announcements relating to our business or the business of our competitors;

changes in expectations as to our future financial performance or changes in financial estimates of public market analysis;

actual or anticipated quarterly variations in our operating results;

conditions generally affecting the oil and natural gas industry;

the success of our operating strategy; and

the operating and share price performance of other comparable companies.

Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common shares. ~~In addition, the stock markets in general can experience considerable~~The price ~~and volume fluctuations. See further discussion~~ of ~~the impact of the Chapter 11 Cases on~~ our common shares may fluctuate significantly in ~~Item "1A.~~the future as a result of these or other factors. However, we currently believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 proceedings, and the holders of our existing common shares are not expected to be entitled to any recovery. As a result, the market price of our common shares may remain significantly depressed during the pendency of our Chapter 11 proceedings. See "Item 1A. Risk Factors - We believe it is highly likely that our existing common shares will be canceled at the conclusion of our Chapter 11 ~~proceedings"~~proceedings".


Item 1B.	Unresolved Staff Comments

~~Not applicable.~~None.


Item 2.	Properties

Corporate offices

We lease office space in Dallas, Texas. We also have small offices for technical and field operations in Texas, Louisiana and Pennsylvania. The table below summarizes our material corporate leases.

Location

Approximate square footage

Approximate remaining monthly payment

Expiration

Approximate square footage

Approximate remaining monthly payment

Expiration

Dallas, Texas ~~(1)~~

155,000

251,000

May 31, 2025

48,000

95,000

December 31, 2022


Item 3.	Legal Proceedings

Bankruptcy proceedings under Chapter 11

On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. See further discussion in "Note ~~17. Subsequent events"~~1. Organization and basis of presentation" in the Notes to our Consolidated Financial ~~Statements for additional information.~~Statements.

Enterprise and Acadian contract litigation

During the third quarter of 2016, ~~we terminated~~a dispute arose regarding our sales and transportation contracts with Enterprise Products Operating LLC ("Enterprise") and Acadian Gas Pipeline System ("Acadian"), respectively. Enterprise and Acadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). ~~Under~~In August 2016, each of EXCO and Enterprise did not remit certain payments allegedly due under the parties’ sales and transportation agreements, Enterprise owed us for July 2016 natural gas sales, and we owed Acadian for July 2016 transportation fees. The amount owed to us by Enterprise exceeded the amount owed by us to Acadian. Werespective agreements. EXCO’s subsidiary, Raider, notified Enterprise that the agreements were in ~~writing of its failure to pay~~default, and ~~gave Enterprise opportunity to cure. When Enterprise failed to cure, we gave written notice to Enterprise and Acadian that we were terminating~~subsequently terminated the ~~sales and transportation~~ agreements. Enterprise ~~subsequently filed an amended petition~~disputed our right to terminate the agreements, and commenced litigation at Enterprise Products Operating LLC and Acadian Gas Pipeline System v. EXCO Operating Company, LP, EXCO Partners OLP GP, LLC, Raider Marketing, LP, and Raider Marketing GP, LLC No. 2016-60848 157th Judicial District, Harris County, ~~Texas. The amended petition alleges that we could not terminate the parties’ agreements despite Enterprise's uncured payment default under the gas sales agreement,~~Texas, and further alleged that we were in breach of the firm transportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperly withheld payment for natural gas we delivered and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking a declaration that we properly terminated the contracts with Enterprise and Acadian, as well as payment of the amounts owed to us under the agreements. EPD subsequently joined Bluescape and two of our officers, Harold Hickey and Steve ~~Estes, asserting breach~~Estes. In October 2016, we filed counterclaims against Enterprise and Acadian in the state court action. The suit was automatically stayed pursuant to the Bankruptcy Code upon the commencement of ~~fiduciary duty claims and thereafter joined Bluescape asserting tortious interference with an existing contract. We have~~the bankruptcy cases.

On February 12, 2018, Enterprise filed a ~~summary judgment~~ motion asin the Court seeking to lift the ~~claims~~automatic stay to continue the suit in state court, and on March 9, 2018, Enterprise filed a motion in the state court seeking to sever the litigation against Bluescape from the litigation against us and our

officers ~~and the motion is pending before the court. If we prevail on the summary judgment motion~~so it could ~~be case dispositive. This case was anticipated~~proceed despite the automatic stay. On March 19, 2018, we filed a motion seeking to gohalt litigation against Bluescape and our directors. On April 19, 2018, the Court entered a stipulation and agreed order pursuant to ~~trial in the second or third quarter of 2018; however, the case is stayed due to our Chapter 11 filings. EPD has filed a~~which, among other things: (a) Enterprise withdrew its motion to lift the ~~stay.~~stay, dismissed its claims against our directors, and agreed not to commence litigation against Bluescape (although discovery could commence) until its claims against us had been resolved; and (b) we agreed to object to any proofs of claim filed by Enterprise or Acadian in the bankruptcy cases by July 20, 2018.

On April 23, 2018, Enterprise and Acadian filed proofs of claim asserting claims against EXCO and Raider. On July 20, 2018, we filed an objection to all proofs of claim filed by Enterprise and Acadian (“Enterprise Claims Objection”), and on October 22, 2018, we filed a motion seeking summary judgment in our favor. On October 5, 2018, Enterprise filed a response to the Enterprise Claims Objection and a motion seeking the Court’s abstention therefrom (“Enterprise Abstention Motion”). On October 29, 2018, the Debtors and Bluescape each filed an objection to the Enterprise Abstention Motion. On November 14, 2018, the Enterprise Claims Objection (and related summary judgment motion) and Enterprise Abstention Motion were abated by agreement. If the abatement is lifted, litigation between us and Enterprise/Acadian could recommence in either the state court, the Court, or both.

On November 13, 2018, EXCO and Bluescape executed an agreement with EPD to settle the aforementioned litigation and claims against the Debtors ("EPD Settlement Agreement"). Per the terms of the EPD Settlement Agreement:

The proofs of claim filed by EPD in the Chapter 11 Cases shall be settled for an allowed general unsecured claim of $10.0 million. These claims primarily include costs related to the rejection of a natural gas sales agreement and natural gas transportation agreement in the North Louisiana region. On the effective date of a plan of reorganization, Bluescape shall be required to purchase the claim from Enterprise for $5.0 million;

The Debtors shall pay Enterprise: (i) $6.25 million on the effective date of a plan of reorganization, and (ii) $6.25 million on September 1, 2019; and

Upon completion of the payments from the Debtors and Bluescape to EPD, each party shall provide releases and take all actions to dismiss the aforementioned litigation.

The EPD Settlement Agreement will not be effective until it is approved by the Court. Furthermore, the EPD Settlement Agreement will be terminated if the effective date of a plan of reorganization does not occur prior to July 1, 2019. We filed a motion with the Court to approve the EPD Settlement Agreement on March 13, 2019 and the hearing is scheduled for April 11, 2019.

Chesapeake natural gas sales contract litigation

On June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against Chesapeake Energy Marketing, LLC ("CEML") in Dallas County, Texas, Case No. DC-17-06672, in the 14th District Court of Dallas County, Texas, for allegedly wrongfully terminating a long-term sales contract with ~~an expiration of June 30, 2032, between Chesapeake and Raider Marketing, LP ("Raider").~~Raider. We are asserting breach of contract, tortious interference with existing contract, tortious interference with prospective business relations, and declaratory relief that the contract is still in full force and effect. On June 7, 2017, Chesapeake filed to remove the lawsuit to the United States District Court Northern District of Texas. We subsequently joined Chesapeake Energy Corporation ("CEC"). CEC has filed a motion to dismiss for lack of personal jurisdiction, and the motion remains pending. See further discussion of the impact of the wrongful termination of the contract by CEML on our ability to divest certain assets in the South Texas region in "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements.

On May 24, 2018, CEML filed a motion seeking relief from the automatic stay to pursue counterclaims against us in the district court litigation. On July 23, 2018, the Court entered an order approving a joint stipulation and agreed order lifting the automatic stay to for the limited purpose of allowing CEML to assert any counterclaims or affirmative defenses in the litigation.

On February 21, 2019, EXCO executed an agreement with CEC and CEML to settle the aforementioned litigation, claims against the Debtors, and other matters ("Chesapeake Settlement Agreement"). Per the terms of the Chesapeake Settlement Agreement:

All claims filed by CEC and CEML in the Chapter 11 Cases shall be deemed disallowed and expunged. These claims primarily include costs related to the rejection of a marketing agreement in the North Louisiana region and pre-petition costs related to sales of natural gas in the South Texas region;

EXCO agreed to release CEC and CEML from pre-petition litigation including the wrongful termination of a natural gas sales contract in South Texas and improper charges for post-production costs in North Louisiana; and

EXCO will assume certain sales contracts with CEML and joint operating agreements with CEC.

The Chesapeake Settlement Agreement will not be effective until it is approved by the Court. We filed a motion with the Court to approve the Chesapeake Settlement Agreement on February 25, 2019 and the hearing is scheduled for March 20, 2019.

Shell natural gas sales contract litigation

We are plaintiffs in an adversary proceeding pending in the United States Bankruptcy Court for the Southern District of Texas, Houston Division under Case No. 18-30155. This lawsuit was originally filed in Harris County District Court on December 26, 2017. We filed a notice of non-suit without prejudice onOn January 26, 2018, ~~in order to bring the claim as~~we initiated an ~~adversary proceeding in the Chapter 11 reorganization. EXCO initiated this~~ adversary proceeding against Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, under Case No. 18-30155 in the bankruptcy proceeding. This lawsuit was originally filed in Harris County District Court on ~~January~~December 26, ~~2018.~~2017 and subsequently non-suited after the filing of the bankruptcy petitions. We brought suit ~~as a result of~~due to Shell Energy’s ~~improper~~ withholding of approximately $33.4 million ~~in revenue, which EXCO is owed under~~related to the ~~parties’ Base Contract for Sale and Purchase~~sales of ~~Natural Gas executed in August of 2009. This unpaid revenue is due to EXCO for the~~ natural gas ~~EXCO delivered~~ to Shell Energy in East Texas and North Louisiana for the months of November and December 2017. On March 23, 2018, the adversary proceeding was dismissed. The issues between Shell Energy and us related to the unpaid revenues remain outstanding.

In addition, we had withheld $28.5 million in revenues owed to Shell as a result of the dispute with Shell Energy. On October 1, 2018, the Court approved our settlement with Shell ("Shell Settlement Agreement"), pursuant to which:

EXCO will pay a total of $22.5 million to Shell, including $9.0 million within 15 days following the approval of the settlement agreement by the Court, $9.0 million within 45 days following the approval of the Court, and the remaining $4.5 million on or before the effective date of the plan of reorganization. Per the terms of the Shell Settlement Agreement, we paid Shell $18.0 million during the fourth quarter of 2018. Upon payment in full of the remaining amount, Shell shall release EXCO from any further liability related to the withheld revenues;

EXCO will commence the completion of four wells that were previously drilled in North Louisiana no later than November 15, 2018, and subsequently commence the completion of three additional wells that were previously drilled in North Louisiana. Per the terms of the Shell Settlement Agreement, we commenced completion on each of these wells during the fourth quarter of 2018 and first quarter of 2019;

EXCO shall assume the joint development agreement with Shell for the East Texas/ North Louisiana joint venture as part of the bankruptcy proceedings and any defaults occurring thereunder are deemed to be satisfied; and

Shell shall not challenge EXCO’s right to serve as operator under the joint development agreement for the East Texas/ North Louisiana joint venture for the remaining term through January 1, 2020, subject to certain exceptions.

other cause of action against us. Furthermore, the settlement agreement provides that it shall not affect any proof of claim that Shell Energy filed in the Chapter 11 Cases. On March 7, 2018, the Court approved the rejection of certain natural gas sales agreements with Shell’s affiliate, Shell Energy, and we recorded a liability of $41.5 million in “Liabilities subject to compromise” related to our current estimate of the allowed claim. The receivable for sales of oil and natural gas to Shell Energy in November and December 2017 and the estimate of the allowed claim for the rejection of the natural gas sales agreement with Shell Energy were presented as a net amount of $8.1 million in "Liabilities subject to compromise" as of December 31, 2018.

Azure minimum volume commitment litigation

On March 1, 2018, we filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018. The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP (“EOC”) and Raider commenced an adversary proceeding against Azure under Case No. 18-03096 in the bankruptcy proceedings. We initiated this adversary proceeding against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties. Various dispositive motions were filed, which were heard by the Court on August 9, 2018. In addition, on April 11, 2018, Azure filed a motion to compel payment of an administrative expense claim for payment of certain disputed compression fees, and on April 13, 2018 filed proofs of claims on account of the gathering and minimum volume commitment agreements. We objected to Azure’s proofs of claim and filed a motion to estimate the claims against EOC at $0.

On November 19, 2018, the Court approved our settlement with Azure ("Azure Settlement Agreement"), pursuant to which:

EXCO agreed to pay Azure $15.0 million and transfer equity interests held in Azure (~3.35%) on the effective date of EXCO’s plan of reorganization; and

EXCO will assume the base gathering agreement with Azure and cure any associated pre-petition amounts associated with the agreement on or before February 28, 2019.

Upon completion of the aforementioned criteria, Azure’s claims related to the base gathering agreement and minimum volume commitment will be deemed to be satisfied. On March 1, 2019, we paid $6.4 million of pre-petition costs for gathering services under the base gathering agreement. The remaining payment and transfer of equity interests are expected to be paid on the effective date of EXCO's plan of reorganization.

Natural gas flaring application

In January 2018, we commenced the flaring of natural gas produced in our South Texas region pursuant to temporary flare permits. In May 2018, we went before the Texas Railroad Commission at a hearing regarding a requested extension of the Flaring Application for up to two-years. We expect that a final ruling by the Texas Railroad Commission on the Flaring Application will be issued in early 2019.


Item 4.	Mine Safety Disclosures

Not applicable.

PART II


Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market information for our common shares

Our common shares have ~~historically~~ been traded on the NYSE. On December 22, 2017, the NYSE suspended the trading of our common shares and commenced proceedings to delist our common shares due to our failure to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. As a result, on December 27, 2017, our common shares commenced trading on the OTC Pink Marketplace under the symbol “XCOO”. Subsequent to our filing voluntary petitions for relief under Chapter 11 on January 15, 2018, our common shares are quoted over-the-counter under the symbol "XCOOQ".

since December 27, 2017. Prior to that time, our common shares were traded on the NYSE.

The following table sets forth for the periods indicated, the highest and lowest sales price for our common shares, as reported on the NYSE for the periods through December 22, 2017, and the quarterly high and low bid quotations for our common shares as reported over-the-counter for the period beginning December 27, 2017:


	Price per share				Price per share
	High		Low		High		Low
2017
2018:
First Quarter	$	14.70	$	7.05	$	0.74	$	0.19
Second Quarter	9.90		2.65		0.39		0.06
Third Quarter	2.81		1.00		0.16		0.05
Fourth Quarter	1.72		0.19		0.14		0.02

2016
2017:
First Quarter	$	29.10	$	10.50	$	14.70	$	7.05
Second Quarter	28.65		7.65		9.90		2.65
Third Quarter	21.30		13.50		2.81		1.00
Fourth Quarter	18.90		12.75		1.72		0.19

Our shareholders

According to our transfer agent, Continental Stock Transfer & Trust Company, there were ~~132~~60 holders of record of our common shares on December 31, ~~2017~~2018 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders and holders of restricted shares).

~~Our dividend policy~~

We have not paid any dividends on our common shares since 2014 and we do not anticipate paying any dividends on our common shares in the foreseeable future. The agreements governing our indebtedness contain covenants that generally limit our ability to pay dividends. In addition, we are currently prohibited from paying cash dividends on our common shares under the Bankruptcy Code, as well as under Texas law because we have negative shareholders’ equity. Any future declaration of dividends, as well as the establishment of record and payment dates, will depend on, among other things, our earnings, capital requirements, financial condition, prospects and other factors our Board of Directors may deem relevant.

~~Issuer repurchases of common shares~~

~~The following table details our repurchases of common shares for the three months ended December 31, 2017:~~

Period Total Number of Shares Purchased Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (1)
October 1 - October 31 —
$ —
—
$ 192.5
November 1 - November 30 —
—
—
192.5
December 1 - December 31 —
—
—
192.5
Total —
—
—


~~(1)~~	~~On July 19, 2010, we announced a $200.0 million share repurchase program.~~


Item 6.	Selected Financial Data

The ~~following table presents our selected historical financial~~information required herein has been omitted due to the relief from disclosure afforded to smaller reporting companies under Regulation S-K and ~~operating data. This financial data should be read in conjunction with “Item 7. Management's Discussion and Analysis~~Article 8 of Financial Condition and Results of Operations,” our Consolidated Financial Statements, the Notes to our Consolidated Financial Statements and the other financial information included in this Annual Report on Form 10-K. This information does not replace the Consolidated Financial Statements. Certain reclassifications have been made to prior period information to conform to current period presentation.

~~Selected consolidated financial and operating data~~

Year Ended December 31,
(in thousands, except per share amounts) 2017 2016 2015 2014 2013
Statement of operations data (1):
Total revenues $ 283,646
$ 271,001
$ 355,700
$ 695,917
$ 663,090
Operating income (loss) (2) (40,556 ) (220,949 ) (1,339,875 ) 126,875
179,221
Net income (loss) (3)(4)(5) $ 24,362
$ (225,258 ) $ (1,192,381 ) $ 120,669
$ 22,204
Basic net income (loss) per share $ 1.14
$ (12.09 ) $ (65.37 ) $ 6.75
$ 1.55
Diluted net income (loss) per share $ 1.14
$ (12.09 ) $ (65.37 ) $ 6.74
$ 1.44
Cash dividends declared per share $ —
$ —
$ —
$ 2.25
$ 3.00
Weighted average common shares and common share equivalents outstanding:
Basic 21,288
18,630
18,241
17,884
14,334
Diluted 21,288
18,630
18,241
17,892
15,394
Statement of cash flow data:
Net cash provided by (used in):
Operating activities $ 54,411
$ (414 ) $ 134,027
$ 362,093
$ 350,634
Investing activities (182,551 ) (55,009 ) (300,833 ) (221,588 ) (252,478 )
Financing activities 158,669
52,244
132,748
(144,683 ) (93,317 )
Balance sheet data:
Current assets $ 167,830
$ 110,617
$ 149,801
$ 330,766
$ 305,854
Total assets 840,347
661,414
954,126
2,304,942
2,399,836
Current liabilities (6) 1,666,970
258,363
252,919
329,436
349,170
Long-term debt (6) —
1,258,538
1,320,279
1,430,516
1,850,120
Shareholders' equity (846,199 ) (871,906 ) (662,323 ) 510,004
147,905
Total liabilities and shareholders' equity 840,347
661,414
954,126
2,304,942
2,399,836
Regulation S-X.


~~(1)~~	~~We have completed numerous acquisitions and dispositions which impact the comparability of the selected financial data between periods.~~

~~(2)~~

Operating income (loss) during 2017 was impacted by the acceleration of the remaining $56.4 million in costs under a firm transportation agreement. See "Note 8. Commitments and contingencies" in the Notes to our Consolidated Financial Statements for additional information. Operating income (loss) loss during 2016 was impacted by the impairment of oil and natural gas properties charge of $160.8 million and the ~~settlement of the litigation with a joint venture part~~ner. See "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements for additional information regarding the litigation with our joint venture partner. Operating income (loss) during 2015 was impacted by the impairment of oil and natural gas properties charge of $1.2 billion. Operating income (loss) during 2013 was impacted by a gain recognized on the contribution of properties to Compass Production Partners, L.P. ("Compass").

~~(3)~~

In March 2017, we issued warrants to the investors of 1.5 Lien Notes and to certain exchanging holders of the Second Lien Term Loans (collectively referred to as the "2017 Warrants" as defined in "Note 4. Derivative financial instruments" in the Notes to our Consolidated Financial Statements). We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. As a result of the change in the fair value of the 2017 Warrants, we recorded a gain of $159.2 million on the revaluation of the warrants during the year ended December 31, 2017.


~~(4)~~	During 2016, we recognized a net gain on extinguishment of debt $119.5 million due to repurchases of a portion of the 2018 Notes and 2022 Notes. During 2015, we recognized a gain on restructuring and extinguishment of debt as a result of repurchasing a portion of our 2018 Notes and 2022 Notes in exchange for the holders of such notes agreeing to act as lenders in connection with

the Exchange Term Loan (as defined in "Note 5. Debt" in the Notes to our Consolidated Financial Statements). In addition, we repurchased a portion of the 2018 Notes in open market purchases which resulted in a net gain on extinguishment of debt. See "Note 5. Debt" in the Notes to our Consolidated Financial Statements for further discussion.


~~(5)~~	On November 15, 2013, we sold our equity interest in TGGT Holdings, LLC ("TGGT") to Azure Midstream Holdings LLC ("Azure") in exchange for cash proceeds and an equity interest in Azure. We report our equity interest acquired in Azure using the cost method of accounting.

~~(6)~~

During 2017, we reclassified all of our outstanding indebtedness to a current liability as a result of agreements entered into in anticipation of events of default under certain debt agreements, as well as any outstanding debt with cross-default provisions, and an event of default under the Second Lien Term Loans. See "Note 5. Debt" in the Notes to our Consolidated Financial Statements for further discussion.


Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following management's discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following management's discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.

Overview and history

We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including Texas, Louisiana and the Appalachia region. Our primary strategy focuses on the exploitation and development of our shale resource plays and the pursuit of leasing and acquisition opportunities.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. We attempt to offset the impact of this natural decline by implementing drilling and exploitation projects to identify and develop additional reserves and adding reserves through leasing and undeveloped acreage acquisition opportunities. Our financial condition has been negatively impacted by the prolonged depressed oil and natural gas price environment, levels of indebtedness, and gathering, transportation and certain other commercial contracts.

Chapter 11 Cases

On January 15, 2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. The Debtors have filed a motion with the Court seeking joint administration of their Chapter 11 cases under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI). The Court has granted all of the first day motions filed by the Debtors that were designed primarily to minimize the impact of the Chapter 11 proceedings on our operations, customers and employees. We will continue to operate our businesses as “debtors in possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. We expect to continue our operations without interruption during the pendency of the Chapter 11 proceedings.

On January 22, 2018, we closed the DIP Credit Agreement, which includes an initial borrowing base of $250.0 million. The proceeds from the DIP Facilities were used to refinance all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. ~~We continue~~On January 15, 2019, we entered into an amendment to ~~engage in discussions~~the DIP Credit Agreement to extend the maturity date from January 22, 2019 to May 22, 2019.

On October 1, 2018, the Debtors filed the October 2018 Plan and related Disclosure Statement with ~~our creditors regarding~~ the ~~terms~~Court. On November 5, 2018, the Court authorized us to solicit acceptances of the October 2018 Plan and approved the Disclosure Statement and other related solicitation materials and procedures necessary to approve the October 2018 Plan. Simultaneous with the solicitation process, we initiated a marketing process for the issuance of a ~~financial restructuring plan. In conjunction with this process, we will explore potential strategic alternatives to maximize value for~~new revolving credit facility and a new second lien debt instrument. During the ~~benefit of our stakeholders, which may include a sale of certain or substantially all of our assets under Section 363~~course of the ~~Bankruptcy Code,~~marketing process, oil prices experienced a ~~plan~~significant decline and overall market conditions worsened. As a result, we were not able to obtain the exit financing required to consummate the October 2018 Plan. On February 15, 2019, the Court approved a motion to extend the filing exclusivity period through April 1, 2019 and the solicitation exclusivity period through May 31, 2019. On March 8, 2019, the Debtors filed the March 2019 Plan and related Disclosure Statement with the Court. The March 2019 Plan provides for either a reorganization of ~~reorganization to equitize certain indebtedness~~the Debtors as a going concern or an ~~alternative to~~All Asset Sale. We have not received consents from any creditors in support of the ~~sale process, or a combination thereof.~~March 2019 Plan.

For the duration of the Chapter 11 ~~proceedings,~~Cases, our operations and ~~our~~ ability to develop and execute our business plan are subject to risks and uncertainties associated with the Chapter 11 ~~proceedings described in "Item 1A. Risk Factors”.~~Cases. As a result

of these risks and uncertainties, our assets, liabilities, shareholders’ equity, officers and/or directors could be significantly different following the outcome of the Chapter 11 ~~proceedings,~~Cases, and the description of our operations, properties and capital plans included in this annual report on Form 10-K may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 ~~proceedings.~~Cases. See further discussion of the impact of the bankruptcy proceedings as part of “Note 1. Organization and basis of presentation” in the Notes to our Consolidated Financial Statements.

Impact on our indebtedness

The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the EXCO Resources Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, 2018 Notes, and 2022 Notes. These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in ~~"Note 17. Subsequent events"~~the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. As of December 31, 2018, the carrying value for each of our debt instruments approximates the principal amount. The corresponding expense associated with the adjustments was recorded as “Reorganization items, net” on our Consolidated Statement of Operations for the year ended December 31, 2018.

On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We accrued interest on 1.75 Lien Term Loans, senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”), 2018 Notes and 2022 Notes through the Petition Date, with no interest accrued subsequent to the filings. As a result, we expect our interest expense to decrease in the future.

Rejection of executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Company or the applicable Filing Subsidiaries for damages caused by such rejection. Our estimate of allowable claims related to the executory contracts and unexpired leases approved for rejection by the Court was recorded as “Liabilities subject to compromise” on our Consolidated Balance Sheet as of December 31, 2018 and the corresponding expense was recorded as “Reorganization items, net” in our Consolidated Statement of Operations for year ended December 31, 2018.

During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. On November 19, 2018, the Court approved an agreement entered into by EXCO and Azure to settle any claims related to a minimum volume commitment for gathering services in the East Texas and North Louisiana regions. We expect our realized natural gas price differentials and gathering and transportation expenses to improve in the future as a result of the rejection and settlement of these contracts.

On August 9, 2018, the Court approved the rejection of the office lease for our corporate headquarters in Dallas, Texas. We subsequently entered into a new lease for a reduced amount of square footage in the same office building with a term through December 31, 2022. We expect our rent expense included within general and administrative expenses to decrease in the future as a result of the rejection of this contract. See further discussion of the impact of the rejection and settlement of executory contracts as part of “Note 1. Organization and basis of presentation” in the Notes to our Consolidated Financial Statements.

Appalachia JV Settlement

On February 27, 2018, we closed ~~the Appalachia JV Settlement~~a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia ~~region.~~region (“Appalachia JV Settlement”). As a result of the Appalachia JV Settlement, we acquired ~~Shell's~~Shell’s interests in ~~the~~our joint venture in Appalachia, including entities that own interests in oil and natural gas properties, an entity that operates the wells in the joint venture in Appalachia (“OPCO”) and an entity that owns and operates midstream assets in the Appalachia ~~region.~~region (“Appalachia Midstream”). As a result, the Appalachia JV Settlement increased our production, revenues and expenses in the Appalachia ~~region are expected to increase in~~region. Also, the ~~future. Also,~~Appalachia JV Settlement decreased our recoveries of general and administrative expenses related to the joint venture in ~~Appalachia are expected to decrease in the future.~~Appalachia. See further discussion of this settlement as part of ~~"Note 17. Subsequent events"~~“Note 3. Acquisitions, divestitures and other significant events” in the Notes to our Consolidated Financial Statements.

~~Financing transactions and restructuring activities during 2017~~

On March 15, 2017, we closed a series of transactions including the issuance of $300.0 million in aggregate principal amount of 1.5 Lien Notes, exchange of $682.8 million in aggregate principal amount of Second Lien Term Loans for a like amount of 1.75 Lien Term Loans and issuance of warrants to purchase our common shares. The terms of the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow for interest payments in cash, common shares or additional indebtedness, subject to certain restrictions and limitations. The transaction fees paid to the lenders included a combination of cash and warrants to purchase our common shares. The 1.5 Lien Notes were issued to affiliates of Fairfax, Bluescape and Oaktree Capital Management, LP ("Oaktree"), as well as an unaffiliated lender.

The proceeds from the 1.5 Lien Notes were primarily utilized to repay the outstanding indebtedness under the EXCO Resources Credit Agreement as of March 2017. In connection with these transactions, the EXCO Resources Credit Agreement was amended to reduce the borrowing base to $150.0 million, permit the issuance of the 1.5 Lien Notes and the exchange of Second Lien Term Loans, and modify certain financial covenants. On June 20, 2017, we paid interest on the 1.75 Lien Term Loans in common shares, which resulted in the issuance of 2,745,754 common shares. On September 20, 2017, we paid $17.0 million and $26.2 million of interest on the 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 Lien Notes and 1.75 Lien Term Loans.

On September 7, 2017, we announced that our Board of Directors delegated authority to the independent directors of the Audit Committee to explore strategic alternatives to strengthen the Company’s balance sheet and maximize the value of the Company, which included, but was not limited to, seeking a comprehensive out-of-court restructuring or reorganization under Chapter 11 of the Bankruptcy Code. At the direction of the Audit Committee, we retained PJT Partners LP as financial advisors and Alvarez & Marsal North America, LLC as restructuring advisors, and continued to engage Kirkland & Ellis LLP as legal advisors to assist the Company with the restructuring process. We initiated discussions with certain stakeholders regarding strategic alternatives to restructure our balance sheet. During the third quarter of 2017, the Compensation Committee of the Board of Directors and the Company revised our employee compensation programs to retain employees and align the interests of employees with our stakeholders. The revised incentive plans solely consist of cash-based compensation and we have discontinued the grant of share-based compensation to employees until the completion of a restructuring. See further discussion of the revisions to our employee compensation programs in "Note 11. Equity-based and other incentive-based compensation" in the Notes to our Consolidated Financial Statements.

During the third quarter of 2017, we borrowed substantially all of our remaining unused commitments under the EXCO Resources Credit Agreement. On September 29, 2017, we obtained a limited waiver from the lenders under the EXCO Resources Credit agreement waiving an event of default as a result of a failure to comply with certain financial covenants as of September 30, 2017.

Due to liquidity constraints and restrictions and limitations on our ability to pay interest in cash, common shares or additional indebtedness, we did not make our interest payment on the 1.75 Lien Term Loans that was due on December 20, 2017 and the interest payment on the Second Lien Term Loans that was due on December 26, 2017. In anticipation of certain events of default related to compliance with financial covenants and failure to pay interest on certain debt instruments, we entered into agreements with certain holders of the indebtedness under our EXCO Resources Credit Agreement, 1.5 Lien Notes, and 1.75 Lien Term Loans to forbear from exercising their rights and remedies as a result of an event of default under such debt instruments until January 15, 2018. See further discussion in "Note 5. Debt" in the Notes to our Consolidated Financial Statements.

~~Changes to Board of Directors~~

On September 20, 2017, each of B. James Ford and Samuel A. Mitchell resigned from their respective positions as members of our Board of Directors. At the time of their respective resignations, neither Mr. Ford nor Mr. Mitchell was a member of any committee of the Board. On October 6, 2017, Stephen J. Toy resigned from his position as a member of the Board. At the time of his resignation, Mr. Toy was a member of each of the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee of the Board. On November 9, 2017, C. John Wilder resigned from his position as a member of the Board and as Executive Chairman of the Board. At the time of his resignation, Mr. Wilder was not a member of any committee of the Board. In connection with the resignation of Mr. Wilder, we entered into a suspension agreement with Energy Strategic Advisory Services LLC ("ESAS") pursuant to which, among other things: (i) the services and investment agreement with ESAS, dated as of March 31, 2015, was suspended such that, during the suspension period and subject to the terms and conditions of the agreement: (a) ESAS is not required to provide any services to us, (b) we are not required to make any payments to ESAS with respect to the suspension period and (c) ESAS does not have the right to nominate a member to the Company’s Board of Directors; and (ii) the warrants previously issued to ESAS under the services and investment agreement ("ESAS Warrants") were forfeited and canceled and we have no further obligations under the ESAS Warrants. ESAS is a wholly owned subsidiary of an affiliate of Bluescape, and Mr. Wilder serves as the Executive Chairman of Bluescape and indirectly controls ESAS.

~~Reverse share split and NYSE compliance~~

On June 2, 2017, we filed a certificate of amendment to our Amended and Restated Certificate of Formation to reduce the number of authorized common shares from 780,000,000 to 260,000,000 and effect a 1-for-15 reverse share split. The reverse share split became effective after the market closed on June 12, 2017. See "Note 1. Organization and basis of presentation" in the Notes to our Consolidated Financial Statements for further discussion.

As a result of our failure to maintain certain continued listing standards on the NYSE, our common shares were suspended from trading on the NYSE on December 22, 2017. Our common shares are traded over-the-counter under the symbol "XCOOQ".

~~Termination of South Texas Divestiture~~

On April 7, 2017, we entered into a purchase and sale agreement with a subsidiary of Venado Oil and Gas, LLC ("Venado") to divest our oil and natural gas properties and surface acreage in South Texas for a total purchase price of $300.0 million that was subject to closing conditions and adjustments based on an effective date of January 1, 2017.

Pursuant to the terms of the agreement, the closing of the transaction was originally anticipated to occur on June 1, 2017 (the “Original Scheduled Closing Date”), unless certain conditions had not been satisfied or waived on or prior to the Original Scheduled Closing Date. The purchase agreement included conditions to the closing, including seller's representation and warranty regarding all material contracts being in full force and effect be true as of the Original Scheduled Closing Date. As described in "Note 3. Acquisitions, divestitures and other significant events" in the Notes to our Consolidated Financial Statements, the closing conditions were not anticipated to be satisfied or waived by the Original Scheduled Closing Date due to the alleged termination of a long-term natural gas sales contract by CEML. We are currently in litigation with CEML as a result of their alleged termination of the contract, see further discussion in "Item 3. Legal proceedings". Therefore, we entered into an amendment to extend the Original Scheduled Closing Date to August 15, 2017.

The amendment, among other things, provided that the satisfaction of the closing conditions would be deemed satisfied by the reinstatement of the natural gas sales contract or by entry into a new gathering agreement. Because all closing conditions had not been satisfied or waived by August 15, 2017, EXCO and Venado mutually agreed to terminate the purchase and sale agreement, effective as of August 15, 2017. Following the termination, the purchase and sale agreement was void and of no further effect.

Critical accounting estimates

The process of preparing financial statements in conformity with GAAP requires us to make estimates and assumptions to determine reported amounts of certain assets, liabilities, revenues, expenses and related disclosures. We have identified the most critical accounting policies used in the preparation of our Consolidated Financial Statements. We determined the critical policies by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our estimates of Proved Reserves, derivative financial instruments,

business combinations, equity-based compensation, oil and natural gas properties, goodwill, revenue recognition, asset retirement obligations and income taxes.

The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP. For a more complete discussion of our accounting policies see "Note 2. Summary of significant accounting policies" in the Notes to our Consolidated Financial Statements.

Estimates of Proved Reserves

The Proved Reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

the quality and quantity of available data;

the interpretation of this data;

the accuracy of various mandated economic assumptions; and

the technical qualifications, experience and judgment of the persons preparing the estimates.

Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. The assumptions used for our shale properties including reservoir characteristics and performance are subject to further refinement as additional production history is accumulated.

You should not assume that the present value of future net cash flows represents the current market value of our estimated Proved Reserves. In accordance with the SEC's requirements, we based the estimated discounted future net cash flows from Proved Reserves according to the requirements in the SEC's Release No. 33-8995 Modernization of Oil and Gas Reporting. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates or cost of capital.

Proved Reserve quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases. A decline in the estimate of Proved Reserves may result from lower market prices, making it uneconomical to drill or produce from higher cost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.

Business combinations

When we acquire assets that qualify as a business, we use FASB ASC 805-10, Business Combinations ("ASC 805-10") to record our acquisitions of oil and natural gas properties or entities. ASC 805-10 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being recognized as goodwill. Application of ASC 805-10 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.

Derivative financial instruments

We ~~use~~have historically used derivative financial instruments to manage price fluctuations, protect our investments and achieve a more predictable cash flow. The estimates of the fair values of our derivative financial instruments require judgment. The fair value of our derivative financial instruments is determined by quoted futures prices, utilization of the credit-adjusted risk-free rate curves and the implied rates of volatility. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value

in earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instruments. Our ability to enter into commodity derivative contracts is limited during the Chapter 11 Cases, see further discussion in "Note 4. Derivative financial instruments" in the Notes to our Consolidated Financial Statements.

On March 15, 2017, we issued warrants to investors in connection with the issuance of the 1.5 Lien Notes and 1.75 Lien Term Loans in March 2017. The 2017 Warrants are accounted for as derivatives in accordance with FASB ASC 815, Derivatives and Hedging, ("ASC 815"), and required to be classified as liabilities due to the types of anti-dilution adjustments.

~~We record~~ As a pre-petition obligation that may be impacted by the Chapter 11 process, we have classified the 2017 Warrants as ~~non-current liabilities at fair value, with~~“Liabilities subject to compromise" on the ~~increase or decrease in fair value being recognized in earnings.~~Consolidated Balance Sheet as of December 31, 2018. The liability attributable to ~~our common share warrants~~the 2017 Warrants as of the issuance date and the end of each reporting period was measured using the Black-Scholes model based on inputs including our share price, volatility, expected remaining life and the risk-free rate of return. The increase or decrease in fair value of the 2017 Warrants is recognized in earnings. The implied rates of volatility were determined based on historical prices of our common shares over a period consistent with the expected remaining life. The 2017 Warrants will be measured at fair value on a recurring basis until the date of exercise, cancellation or expiration.

Equity-based compensation

Our equity-based compensation includes share-based compensation to employees which we account for in accordance with FASB ASC 718, Compensation-Stock Compensation ("ASC 718") ~~and~~. Our equity-based compensation for 2017 includes compensation expense for warrants issued to ~~ESAS~~Energy Strategic Advisory Services LLC (“ESAS”), a subsidiary of Bluescape, which we ~~account~~accounted for in accordance with FASB ASC 505-50, Equity-Based Payments to Non-Employees ("ASC 505-50"). The warrants were forfeited and canceled pursuant to an agreement with ESAS entered into on November 9, 2017.

ASC 718 requires share-based compensation to employees to be recognized in our Consolidated Statements of Operations based on their estimated fair values. Estimating the grant date fair value of our share-based compensation requires management to make assumptions and to apply judgment in estimating the fair value. These assumptions and judgments include estimating the volatility of our share price, dividend yields, expected term, forfeiture rates and other company-specific inputs. ASC 505-50 requires the warrants to be re-measured each interim reporting period until the completion of the services under the agreement and an adjustment is recorded in our Consolidated Statements of Operations. The fair value of the warrants iswas dependent on factors such as our share price, historical volatility, risk-free rate and performance relative to our peer group.

Changes in these assumptions could materially affect the estimate of the fair value. If actual results are not consistent with the assumptions used, the equity-based compensation expense reported in our financial statements may not be representative of the actual economic impact of the equity-based compensation.

Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives: the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. In determining whether such costs should be impaired or transferred, we evaluate lease expiration dates, recent drilling results, future development plans and current market values. Our undeveloped properties are predominantly held-by-production, which reduces the risk of impairment as a result of lease expirations.

We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20, Capitalization of Interest. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties. We capitalize the portion of general and administrative costs, including share-based compensation, which is attributable to our acquisition, exploration, exploitation and development activities.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded.

Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves.

Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs ("ceiling test"). The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling limitation is less than the full cost pool, we are required to record a ceiling test impairment of our oil and natural gas properties. The full cost ceiling limitation is computed as the sum of the present value of

estimated future net revenues from our Proved Reserves by applying the average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test is computed using the simple average spot price for the trailing 12 month period using the first day of each month. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations.

The evaluation of impairment of our oil and natural gas properties includes estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revisions of such estimate. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Goodwill

In accordance with FASB ASC 350-20, Intangibles-Goodwill and Other, goodwill isshall not be amortized, but is tested for impairment ~~on an annual basis as of December 31,~~at least annually, or more frequently as impairment indicators arise. Impairment tests involve the use of estimates related to the fair market value of the business operations with which goodwill is associated. Losses, if any, resulting from impairment tests will be reflected in operating income or loss in the Consolidated Statements of Operations.

~~We apply a two-part, equally weighted approach in determining the fair value~~As of ~~our business as part of the goodwill impairment test. We perform an income approach, which uses~~December 31, 2018, we utilized a discounted cash flow model to value our business and corroborated the results of the valuation model through a comparison to our enterprise value that is calculated as the combined market ~~approach, in which~~capitalization of our equity plus the fair value ~~is determined using trading metrics and transaction multiples~~ of ~~peer companies.~~our debt. The discounted cash flow model used in the income approach requires us to make various judgmental assumptions about future production, revenues, operating and capital expenditures, discount rates and other inputs which are based on our budgets, business plans, economic projections and anticipated future cash flows. The market approach requires us to make assumptions regarding the identifications of comparable companies and transactions as well as the future performance of ourselves and the comparable companies. As part of the determination of the fair value of our reporting unit, we corroborate the results of the valuation model through a comparison to our enterprise value that is calculated as the combined market capitalization of our equity plus the fair value of our debt. Due to the changing market conditions, it is possible that inputs and assumptions used in the valuation may change in the future, which could materially affect the estimate of the fair value of our business.

Revenue recognition and natural gas imbalances

We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust our oil and natural gas sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. Historically, these differences have been immaterial. Natural gas imbalances at December 31, ~~2017, 2016~~2018 were 0.7 Bcf and ~~2015~~were reflected as a reduction to our Proved Reserves. Natural gas imbalances at December 31, 2017 were not significant.

Asset retirement obligations

We follow FASB ASC 410-20, Asset Retirement Obligations ("ASC 410-20") to account for legal obligations associated with the retirement of long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated fair value at the time that the obligations are incurred. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. Our calculation of asset retirement obligations uses numerous assumptions and judgments,

including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.

Income taxes

Income taxes are accounted for in accordance with FASB ASC 740, Income Taxes. Deferred taxes are recorded to reflect

the tax benefits and consequences of future years' differences between the tax basis of assets and liabilities and their financial reporting basis. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. We assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. Examples of positive and negative evidence include historical taxable income or losses, forecasted income or losses, the estimated timing of the reversals of existing temporary differences as well as prudent and feasible tax planning strategies. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of December 31, ~~2017,~~2018, we continued to have a full valuation allowance against our net deferred tax assets. A significant amount of judgment is also required in determining the amount of unrecognized tax benefit to record for uncertain tax positions. We consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of unrecognized tax benefit. We currently do not have any uncertain tax positions recorded as of December 31, ~~2017.~~2018.

Our results of operations

A summary of key financial data for the years ended December 31, ~~2017~~, ~~2016~~2018 and ~~2015~~2017 related to our results of operations is presented below:


	Year Ended December 31,								Year to year change							Year Ended December 31,					Year to year Change
(dollars in thousands, except per unit prices)	2017		2016			2015			2017-2016			2016-2015				2018			2017		Year to year Change
Production:
Oil (Mbbls)	1,158		1,769			2,342			(611		)	(573		)		1,357			1,158		199
Natural gas (Mmcf)	80,136		93,829			109,926			(13,693		)	(16,097		)		98,779			80,136		18,643
Total production (Mmcfe) (1)	87,084		104,443			123,978			(17,359		)	(19,535		)		106,921			87,084		19,837
Average daily production (Mmcfe)	239		285			340			(46		)	(55		)		293			239		54
Revenues before derivative financial instrument activities:
Revenues before commodity derivative financial instrument activities:															Revenues before commodity derivative financial instrument activities:
Oil	$	57,693	$	67,317		$	102,787		$	(9,624	)	$	(35,470	)		$	90,614		$	57,693	$	32,921
Natural gas	201,137		181,332			226,471			19,805			(45,139		)		281,977			201,137		80,840
Total oil and natural gas revenues	258,830		248,649			329,258			10,181			(80,609		)		372,591			258,830		113,761
Purchased natural gas and marketing	24,816		22,352			26,442			2,464			(4,090		)		21,435			24,816		(3,381		)
Total revenues	$	283,646	$	271,001		$	355,700		$	12,645		$	(84,699	)		$	394,026		$	283,646	$	110,380
Oil and natural gas derivative financial instruments:
Commodity derivative financial instruments:															Commodity derivative financial instruments:
Gain (loss) on derivative financial instruments - commodity derivatives	$	24,732	$	(34,137	)	$	75,869		$	58,869		$	(110,006	)		$	(615	)	$	24,732	$	(25,347	)
Average sales price (before cash settlements of derivative financial instruments):
Average sales price (before cash settlements of commodity derivative financial instruments):															Average sales price (before cash settlements of commodity derivative financial instruments):
Oil (per Bbl)	$	49.82	$	38.05		$	43.89		$	11.77		$	(5.84	)		$	66.78		$	49.82	$	16.96
Natural gas (per Mcf)	2.51		1.93			2.06			0.58			(0.13		)		2.85			2.51		0.34
Natural gas equivalent (per Mcfe)	2.97		2.38			2.66			0.59			(0.28		)		3.48			2.97		0.51
Costs and expenses:
Oil and natural gas operating costs	$	35,011	$	34,609		$	53,903		$	402		$	(19,294	)		$	42,149		$	35,011	$	7,138
Production and ad valorem taxes	13,131		15,380			22,630			(2,249		)	(7,250		)		15,260			13,131		2,129
Gathering and transportation	111,427		106,460			99,321			4,967			7,139				76,175			111,427		(35,252		)
Purchased natural gas	23,400		23,557			27,369			(157		)	(3,812		)		16,387			23,400		(7,013		)
Depletion	50,066		74,482			213,302			(24,416		)	(138,820		)		78,981			50,066		28,915
Depreciation and amortization	974		1,500			2,124			(526		)	(624		)		1,308			974		334
General and administrative(2)	30,165		48,700			58,818			(18,535		)	(10,118		)		27,850			30,165		(2,315		)
Interest expense, net	108,175		70,438			106,082			37,737			(35,644		)		33,917			108,175		(74,258		)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.40	$	0.33		$	0.43		$	0.07		$	(0.10	)		$	0.39		$	0.40	$	(0.01	)
Production and ad valorem taxes	0.15		0.15			0.18			—			(0.03		)		0.14			0.15		(0.01		)
Gathering and transportation	1.28		1.02			0.80			0.26			0.22				0.71			1.28		(0.57		)
Depletion	0.57		0.71			1.72			(0.14		)	(1.01		)		0.74			0.57		0.17
Depreciation and amortization	0.01		0.01			0.02			—			(0.01		)		0.01			0.01		—
Net income (loss)(3)	$	24,362	$	(225,258	)	$	(1,192,381	)	$	249,620		$	967,123			$	(182,697	)	$	24,362	$	(207,059	)


8.	Commitments and contingencies

The following table presents our future minimum obligations under our commercial commitments as of December 31, ~~2017.~~2018. The commitments do not include those of our equity method investments.

(in thousands) Gathering and firm transportation services (1) Other fixed commitments Drilling contracts Operating leases and other Total
2018 $ 87,621
$ 3,222
$ 1,138
$ 3,760
$ 95,741
2019 47,541
2,415
—
3,149
53,105
2020 46,463
1,949
—
1,622
50,034
2021 33,306
1,601
—
36
34,943
2022 33,306
—
—
—
33,306
Thereafter 94,443
—
—
—
94,443
Total $ 342,680
$ 9,187
$ 1,138
$ 8,567
$ 361,572


~~(1)~~	~~The commitments under our firm transportation agreement with Regency have been excluded from the above totals. See the discussion below for more details regarding this agreement.~~

~~Gathering and firm transportation services~~



(in thousands)	Drilling contracts		Operating leases and other		Other fixed commitments		Total
2019	$	3,661	$	1,635	$	17	$	5,313
2020	—		1,595		12		1,607
2021	—		1,193		2		1,195
2022	—		1,173		—		1,173
2023	—		—		—		—
Thereafter	—		—		—		—
Total	$	3,661	$	5,596	$	31	$	9,288

We have entered into firm transportation and gathering agreements with pipeline companies to facilitate sales from our East Texas and North Louisiana production. Gathering and firm transportation services presented in the tables within this footnote represent our gross commitments under these contracts, and a portion of these costs will be incurred by working interest and other owners. We report these costs as gathering and transportation expenses or as a reduction in total sales price received from the purchaser. In addition, our variable rate firm transportation and gathering agreements do not have a minimum volume commitment and are not included in the tables within this footnote. As such, our gathering and firm transportation services presented in the table above may not be representative of the amounts reported as gathering and transportation expenses in our Consolidated Financial Statements.

~~At December 31, 2017, our firm transportation and gathering agreements covered the following gross volumes of natural gas:~~

(in Bcf) Firm transportation services (1) Gathering services
2018 183
100
2019 183
—
2020 180
—
2021 146
—
2022 146
—
Thereafter 413
—
Total 1,251
100


~~(1)~~	~~The commitments under our firm transportation agreement with Regency have been excluded from the above totals. See the discussion below for more details regarding this agreement.~~

On January 18, 2018, the Company and the Filings Subsidiaries filed motions to reject certain executory contracts as permitted under the Bankruptcy Code. This included certain of our sales, gathering and transportation agreements included as commitments as of December 31, 2017. See further discussion of the rejection of these executory contracts in "Note 17. Subsequent events".

~~Enterprise and Acadian contract litigation~~

During the third quarter of 2016, we terminated our sales and transportation contracts with Enterprise Products Operating LLC (“Enterprise”) and Acadian Gas Pipeline System (“Acadian”), respectively. We transported natural gas produced from our operated wells in North Louisiana through Acadian, and Enterprise was a purchaser of certain volumes of our natural gas, until we terminated the contracts. Enterprise and Acadian are part of the corporate family of Enterprise Products Partners L.P. (“EPD”). Acadian is an indirect, wholly-owned subsidiary of EPD that owns and operates the Acadian natural gas pipeline system. The agreement with Acadian provided for the firm transportation of 150,000 Mmbtu/day and 175,000 Mmbtu/day of natural gas at reservation fees of $0.25 and $0.20, respectively. In addition, the sales contract with Enterprise contemplated that we could, subject to certain limitations and exclusions, sell 75,000 Mmbtu/day of natural gas at a $0.25 reduction from market index prices. The primary term for these contracts had been through October 31, 2025. The fees described represent our gross commitments and a portion of these costs is allocated to working interest and other owners. The Acadian firm transportation agreement is accounted for as gathering and transportation expenses, and the Enterprise sales contract is accounted for as a reduction in the total sales price within revenues.

Under the parties’ sales and transportation agreements, Enterprise owed us for July 2016 natural gas sales, and we owed Acadian for July 2016 transportation fees. The amount owed to us by Enterprise exceeded the amount owed by us to Acadian. We notified Enterprise in writing of its failure to pay and gave Enterprise opportunity to cure. When Enterprise failed to cure, we gave written notice to Enterprise and Acadian that we were terminating the sales and transportation agreements. Enterprise and Acadian subsequently filed an action in Harris County, Texas, against us alleging that we could not terminate the parties’ agreements despite Enterprise's uncured payment default under the natural gas sales agreement, and further alleged that we were in breach of the firm transportation agreements. On October 17, 2016, we filed a counterclaim asserting that Enterprise was the breaching party because it improperly withheld payment for natural gas we delivered to it and the amounts owed by Enterprise exceeded the amounts owed by us to Acadian. We are also seeking a declaration that we properly terminated the contracts with Enterprise and Acadian. EPD subsequently joined two of our officers, Harold Hickey and Steve Estes, asserting breach of fiduciary duty claims and thereafter joined Bluescape asserting tortious interference with an existing contract. We have filed a summary judgment motion as to the claims against us and our officers, and the motion is pending before the court. If we prevail on the summary judgment motion it could be case dispositive. This case is anticipated to go to trial in the second or third quarter of 2018; however, the case is stayed due to our Chapter 11 filings. We cannot currently estimate or predict the outcome of the litigation but we plan to vigorously defend our right to terminate the contracts and to seek the amounts owed to us for delivered natural gas.

We are no longer selling natural gas under the Enterprise sales contract or transporting natural gas under the Acadian firm transportation contract effective as of the termination date. The Company is accounting for these contracts in accordance with FASB ASC 450 ("ASC 450"), ~~Contingencies~~, which states a contingency that might result in a gain should not be reflected until it is realized or realizable. There is a rebuttable presumption that a claim subject to litigation does not meet the criteria to be realized or realizable; therefore, the termination of these contracts will not be reflected in our financial results until the

litigation is resolved. Upon resolution of the litigation, we will adjust the previously recognized amounts to reflect the outcome of the litigation. As of December 31, 2017, we recorded a net liability of $43.8 million for costs subsequent to the termination of the contract in accordance with the guidance related to contingencies in ASC 450. The minimum obligations under these agreements are included in the tables of our commercial commitments as of December 31, 2017.

~~Regency transportation agreement default~~

We have a firm transportation agreement with Regency Intrastate Gas Systems LLC ("Regency") to transport 237,500 Mmbtu/day of natural gas at a cost of $0.30 per Mmbtu until January 31, 2020. We were obligated to pay a reservation charge of $0.30 per Mmbtu if we failed to transport the minimum volumes under the agreement. The costs under the agreement were recorded as "Gathering and transportation expenses" in our Consolidated Statement of Operations.

On October 23, 2017, we were notified of our failure to pay $2.2 million for the July 2017 charges. The contract provides that the failure to pay the entire charge when due constitutes a default. If the payment default was not fully cured to Regency’s satisfaction within 30 days written notice, Regency has the right to immediately accelerate the payments of the remaining reservation charges due under the contract. We have not received a notice of acceleration. We have not cured the default for July 2017 and have not remitted payment for any subsequent months.

Due to our default under the contract and Regency's right to accelerate the remaining payments, we accounted for these contracts in accordance with ASC 450, which states that an estimated loss from a loss contingency shall be accrued if (1) information available before the financial statements are issued indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements, and (2) the amount of loss can be reasonably estimated. As of December 31, 2017, the unpaid amounts and remaining charges under this agreement of $67.3 million were recorded as "Revenue and royalties payable" in our Consolidated Balance Sheet. In addition to the expenses under the agreement prior to the event of default, we recorded $56.4 million related to the acceleration of the remaining charges subsequent to the event of default as "Other operating items" in our Consolidated Statement of Operations for the year ended December 31, 2017.

~~Shell natural gas sales contract litigation~~

We had a natural gas sales agreement with Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, under which we were contractually obligated to deliver and sell to Shell Energy, and Shell Energy was contractually obligated to receive and purchase from us, natural gas production of 100,000 Mmbtu/day. We were to receive the product of an index price and the volumes delivered less the product of the reservation charge of $0.39 per Mmbtu and the daily contract volume. The contract was scheduled to end in November 2020.

On December 22, 2017, we received notice from Shell Energy that they were exercising their right to require adequate assurance of performance from us for the reservation charges under the contract. Shell Energy requested assurances in the form of letters of credit of approximately $44.4 million, which was approximately equal to the remaining reservation charges for the remaining term of the contract. We responded to the notice by stating the request for the letter of credit request was unreasonable and unjustified under the terms of the agreement. Subsequently, Shell Energy notified us that they were withholding payment for the purchase of natural gas for the months of November and December 2017 as a means to satisfy their demands of reasonable assurance of performance. Shell Energy allegedly terminated the sales contracts on December 26, 2017 as a result of the adequate assurance provision despite our objections to the reasonableness of their request. We ceased selling natural gas to Shell Energy in the East Texas and North Louisiana regions effective as of the date of their breach.

On December 26, 2017, we filed a claim in Harris County, Texas seeking declaratory relief that (1) we had not undergone an event of default as defined within the agreement, (2) Shell Energy was in material breach of the contract, and (3) Shell Energy’s request of adequate assurance of performance was neither reasonable, nor justified, and not in good faith under the agreement or applicable Texas law. In addition to the preceding, we are also seeking actual damages, reasonable attorneys’ fees, court costs, prejudgment and post-judgment interest at the maximum rate allowed by Texas law, and all other relief to which we may be justly entitled. On January 26, 2018, we filed a notice of non-suit in Harris County District Court. Concurrently with filing the notice of non-suit in the county court, we filed an adversary proceeding against Shell Energy in the Chapter 11 Cases.

As of December 31, 2017, we recorded a receivable of approximately $33.4 million related to the sales of natural gas to Shell Energy in East Texas and North Louisiana for the months of November and December 2017. As of December 31, 2017, we are withholding $16.8 million in revenues payable to Shell to offset our exposure until the litigation is resolved. The revenues payable may increase in subsequent months due to the natural gas marketed on behalf of Shell's ownership interests in our operated wells. We plan to adamantly assert our right to terminate the contract as a result of Shell Energy's breach and

demand payment for the natural gas sales during November and December 2017. Due to the uncertainty surrounding the outcome of the litigation, we are not able to reasonably estimate a potential loss, if any, at this time. The minimum obligations under this agreement are included in the tables of our commercial commitments as of December 31, 2017.

~~Other commitments~~

We lease our offices and certain equipment. Our rental expenses were approximately ~~$2.3 million, $2.6~~$2.4 million and ~~$3.4~~$2.3 million for the years ended December 31, ~~2017~~, ~~2016~~2018 and ~~2015~~,2017, respectively. We have also entered into drilling rig contracts primarily to develop our assets in the East Texas and North Louisiana regions. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties. These contracts are short-term in nature and are dependent on our planned drilling program.

~~Our other fixed commitments primarily consist of marketing contracts in which we are obligated to pay the buyer a fee if we fail to deliver minimum quantities of natural gas.~~

In the ordinary course of business, we are periodically a party to lawsuits. From time to time, oil and natural gas producers, including EXCO, have been named in various lawsuits alleging underpayment of royalties and the allocation of production costs in connection with oil and natural gas sold. We have reserved our estimated exposure and do not believe it was material to our current, or future, financial position or results of operations.

We believe that we have properly reflected any potential exposure in our financial position when determined to be both probable and estimable.

Shell natural gas sales contract litigation

As of September 30, 2018, we had withheld $28.5 million in revenues owed to Shell as a result of a dispute regarding the failure of Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, to pay us for the sale of natural gas. We entered into a settlement agreement with Shell on September 17, 2018 that was approved by the Court on October 1, 2018 ("Shell Settlement Agreement"). Under the terms of the settlement agreement:

The settlement agreement does not prevent us from asserting any claim, cross-claim, defense, or other cause of action against Shell Energy, nor does the settlement agreement prevent Shell Energy from asserting any claim, cross-claim, defense, or other cause of action against us. Furthermore, the settlement agreement provides that it shall not affect any proof of claim that Shell Energy filed in the Chapter 11 Cases. As of December 31, 2017, we had a receivable of approximately $33.4 million related to the sales of natural gas to Shell Energy in East Texas and North Louisiana for the months of November and December 2017. Shell Energy is withholding payment as a means to satisfy their demands of reasonable assurance of

performance under a natural gas sales agreement. We believe the request for adequate assurance was unreasonable and unjustified under the terms of the agreement and these amounts have been improperly withheld by Shell Energy. On March 7, 2018, the Court approved the rejection of the aforementioned natural gas sales agreement with Shell Energy and we recorded a liability of $41.5 million in “Liabilities subject to compromise” related to our current estimate of the allowed claim. The receivable for sales of oil and natural gas to Shell Energy in November and December 2017 and the estimate of the allowed claim for the rejection of the natural gas sales agreement with Shell Energy were presented as a net amount of $8.1 million in "Liabilities subject to compromise" as of December 31, 2018. See further discussion regarding this dispute with Shell Energy in "Item 3. Legal proceedings".


9.	Employee benefit plans

We sponsor a 401(k) plan for our employees ~~and matched~~which matches 100% of employee contributions ~~during 2015. Our~~up to certain limits. For the year ended December 31, 2018, the Company's matching ~~program~~contribution was ~~suspended during 2016 in response~~up to ~~depressed oil and natural gas prices which have negatively impacted our business and operations. The Company reinstated its~~a maximum of 4% of each employee's pay. For the year ended December 31, 2017, the Company's matching ~~program effective January 1, 2017 in which it matched 100% of employee contributions~~contribution was up to a maximum of 3% of each employee's pay. Our matching contributions were $0.7 million and $0.6 million for the years ended December 31, 2018 and 2017, respectively. Effective January 1, ~~2018,~~2019, the Company increased its matching contribution up to a maximum of 4%5% of each employee's pay. ~~Our matching contributions were $0.6 million and $5.2 million for the years ended December 31, 2017 and~~ ~~2015, respectively.~~


~~10.~~	~~Earnings per share~~

10.Earnings (loss) per share

The following table presents the basic and diluted earnings (loss) per share computations, adjusted to give effect to our reverse share split on June 12, 2017, for the years ended December 31, ~~2017~~, ~~2016~~2018 and ~~2015~~:

2017:


	Year Ended December 31,								Year Ended December 31,
(in thousands, except per share data)	2017		2016			2015			2018			2017
Basic net income (loss) per common share:
Net income (loss)	$	24,362	$	(225,258	)	$	(1,192,381	)	$	(182,697	)	$	24,362
Weighted average common shares outstanding	21,288		18,630			18,241			21,686			21,288
Net income (loss) per basic common share	$	1.14	$	(12.09	)	$	(65.37	)	$	(8.42	)	$	1.14
Diluted net income (loss) per common share:
Net income (loss)	$	24,362	$	(225,258	)	$	(1,192,381	)	$	(182,697	)	$	24,362
Weighted average common shares outstanding	21,288		18,630			18,241			21,686			21,288
Dilutive effect of:
Stock options	—		—			—
Restricted shares and restricted share units	—		—			—			—			—
Warrants	—		—			—
Weighted average common shares and common share equivalents outstanding	21,288		18,630			18,241			21,686			21,288
Net income (loss) per diluted common share	$	1.14	$	(12.09	)	$	(65.37	)	$	(8.42	)	$	1.14



Texas (State of incorporation)		74-1492779 (I.R.S. Employer Identification No.)

12377 Merit Drive, Suite 1700, Dallas, Texas (Address of principal executive offices)		75251 (Zip Code)



Large accelerated filer o		Accelerated filer o
Non-accelerated filer oþ		Smaller reporting company þ
Emerging growth company o



PART I. I.
Item 1.	Business	21
Item 1A.	Risk Factors	2928
Item 1B.	Unresolved Staff Comments	4544
Item 2.	Properties	4544
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	4647

PART II. II.
Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	4648
Item 6.	Selected Financial Data	48
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	7466
Item 8.	Financial Statements and Supplementary Data	7667
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	~~132~~119
Item 9A.	Controls and Procedures	~~132~~119
Item 9B.	Other Information	~~133~~120

PART ~~III~~. III.
Item 10.	Directors, Executive Officers and Corporate Governance	~~134~~120
Item 11.	Executive Compensation	~~134~~120
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~134~~120
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~134~~120
Item 14.	Principal Accountant Fees and Services	~~134~~120

Part IV. IV.
Item 15.	Exhibits and Financial Statement Schedules	~~134~~120
Item 16.	Form 10-K Summary	128


Areas	Total Proved Reserves (Bcfe) (1)	PV-10 (in millions) (1) (2)		Average daily net production (Mmcfe/d) (3)	Total Proved Reserves (Bcfe) (1)	PV-10 (in millions) (1) (2)		Average daily net production (Mmcfe/d) (3)
North Louisiana	318.3	$	226.8	175	285.5	$	280.0	163
East Texas	68.1	65.8		36	59.4	58.0		24
South Texas	66.3	132.5		18	90.1	304.9		28
Appalachia and other	114.2	57.7		26	225.6	114.5		51
Total	566.9	$	482.7	255	660.6	$	757.4	266


Areas	Total gross acreage	Total net acreage	Total gross acreage	Total net acreage
North Louisiana	102,300	56,000	101,400	55,500
East Texas	111,600	42,100	110,000	41,100
South Texas	103,000	49,700	100,800	48,500
Appalachia and other	398,300	180,700	382,200	342,800
Total	715,200	328,500	694,400	487,900



þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE FISCAL YEAR ENDED DECEMBER 31, ~~2017~~2018



o		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		FOR THE TRANSITION PERIOD FROM __________TO __________


(1)	The total Proved Reserves and PV-10 as of December 31, ~~2017~~2018 were prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC").


(3)	The average daily net production rate was calculated based on the average daily rate during the final month of the year ended December 31, ~~2017.~~2018.


	As of December 31,						As of December 31,
	2017 (3)		2016 (3)		2015		2018 (3)		2017 (3)		2016 (3)
Oil (Mbbls)
Developed	9,412		10,168		12,056		13,302		9,412		10,168
Undeveloped	—		—		8,383		—		—		—
Total	9,412		10,168		20,439		13,302		9,412		10,168

Natural gas (Mmcf)
Developed	510,451		415,719		364,932		580,781		510,451		415,719
Undeveloped	—		—		419,742		—		—		—
Total	510,451		415,719		784,674		580,781		510,451		415,719

Equivalent reserves (Mmcfe)
Developed	566,924		476,727		437,268		660,590		566,924		476,727
Undeveloped	—		—		470,040		—		—		—
Total	566,924		476,727		907,308		660,590		566,924		476,727

PV-10 (in millions) (1)
Developed	$	482.7	$	310.9	$	359.4	$	757.4	$	482.7	$	310.9
Undeveloped	—		—		42.7		—		—		—
Total	$	482.7	$	310.9	$	402.1	$	757.4	$	482.7	$	310.9

Standardized Measure (in millions) (2)	$	482.7	$	310.9	$	402.1	$	757.4	$	482.7	$	310.9


(1)	The PV-10 is based on the following average spot prices, in each case adjusted for historical differentials. Prices presented on the table below are the trailing 12 month simple average spot price at the first of the month for natural gas at Henry Hub and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma.


	Average spot prices				Average spot prices
	Oil (per Bbl)		Natural gas (per Mmbtu)		Oil (per Bbl)		Natural gas (per Mmbtu)
December 31, 2018					$	65.56	$	3.10
December 31, 2017	$	51.34	$	2.98	51.34		2.98
December 31, 2016	42.75		2.48		42.75		2.48
December 31, 2015	50.28		2.59


	Oil (Mbbls)		Natural gas (Mmcf)		Equivalent natural gas (Mmcfe)		Oil (Mbbls)		Natural gas (Mmcf)		Equivalent natural gas (Mmcfe)
Proved Developed Reserves	9,412		510,451		566,924		13,302		580,781		660,590
Proved Undeveloped Reserves	—		—		—		—		—		—
Total Proved Reserves	9,412		510,451		566,924		13,302		580,781		660,590
The changes in reserves for the year are as follows:
January 1, 2017	10,168		415,719		476,727
January 1, 2018							9,412		510,451		566,924
Purchases of reserves in place	—		50,456		50,456		—		118,415		118,415
Discoveries and extensions	13		21,880		21,958		1,387		22,482		30,804
Revisions of previous estimates:
Changes in price	679		30,200		34,274		690		5,726		9,866
Other factors	(290	)	72,332		70,593
Performance and other factors							3,170		22,486		41,502
Sales of reserves in place	—		—		—		—		—		—
Production	(1,158	)	(80,136	)	(87,084	)	(1,357	)	(98,779	)	(106,921	)
December 31, 2017	9,412		510,451		566,924
December 31, 2018							13,302		580,781		660,590


	Year Ended December 31,						Year Ended December 31,
(in thousands, except production and per unit amounts)	2017		2016		2015		2018		2017		2016
Revenues, production and prices:
Oil:
Revenue	$	57,693	$	67,317	$	102,787	$	90,614	$	57,693	$	67,317
Production sold (Mbbls)	1,158		1,769		2,342		1,357		1,158		1,769
Average sales price per Bbl	$	49.82	$	38.05	$	43.89	$	66.78	$	49.82	$	38.05
Natural gas:
Revenue	$	201,137	$	181,332	$	226,471	$	281,977	$	201,137	$	181,332
Production sold (Mmcf)	80,136		93,829		109,926		98,779		80,136		93,829
Average sales price per Mcf	$	2.51	$	1.93	$	2.06	$	2.85	$	2.51	$	1.93
Costs and expenses:
Oil and natural gas operating costs per Mcfe	$	0.40	$	0.33	$	0.43	$	0.39	$	0.40	$	0.33


	At December 31, 2017						At December 31, 2018
	Gross wells (1)			Net wells			Gross wells (1)			Net wells
	Oil	Natural gas	Total	Oil	Natural gas	Total	Oil	Natural gas	Total	Oil	Natural gas	Total
Producing region:
North Louisiana	—	644	644	—	246.7	246.7	—	677	677	—	251.2	251.2
East Texas	—	151	151	—	51.5	51.5	—	157	157	—	50.3	50.3
South Texas	243	1	244	100.3	0.1	100.4	255	1	256	111.3	0.1	111.4
Appalachia and other	2	140	142	0.1	41.4	41.5	1	156	157	—	85.5	85.5
Total	245	936	1,181	100.4	339.7	440.1	256	991	1,247	111.3	387.1	498.4


	At December 31, 2017				At December 31, 2018
	Developed		Undeveloped		Developed		Undeveloped
Area	Gross	Net	Gross	Net	Gross	Net	Gross	Net
North Louisiana	76,700	37,000	25,600	19,000	77,700	37,700	23,700	17,800
East Texas	45,900	20,300	65,700	21,800	46,900	20,500	63,100	20,600
South Texas	95,400	45,900	7,600	3,800	94,300	45,400	6,500	3,100
Appalachia and other	48,700	18,200	349,600	162,500	53,300	38,100	328,900	304,700
Total	266,700	121,400	448,500	207,100	272,200	141,700	422,200	346,200


(1)	As of December 31, ~~2017,~~2018, we did not hold interests in any wells with multiple completions.



	Development wells
	Gross			Net
	Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2017 (1)	10	—	10	6.8	—	6.8
Year ended December 31, 2016 (2)	15	—	15	9.2	—	9.2
Year ended December 31, 2015 (3)	63	—	63	25.3	—	25.3
	Exploratory wells
	Gross			Net
	Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2017 (1)	2	—	2	1.6	—	1.6
Year ended December 31, 2016	—	—	—	—	—	—
Year ended December 31, 2015 (3)	5	—	5	3.9	—	3.9


(1)	Our development wells in 2018 primarily included the Haynesville shale in the Holly area of North Louisiana and the Eagle Ford shale of South Texas. None of the wells completed during the period were classified as exploratory.


(2)	Our development wells in 2017 primarily included the Haynesville shale in the Holly area of North Louisiana. Our exploratory wells included the Bossier shale in the Holly area of North Louisiana.


~~(2)~~(3)	Our development ~~wells~~ in 2016 primarily included the Haynesville and Bossier shales in the Shelby area of East Texas and the Haynesville shale in the Holly area of North Louisiana.


~~(1)~~	~~The office lease in Dallas, Texas contains a right on our behalf to terminate the lease agreement early on June 30, 2020 or June 30, 2022.~~



Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (1)
October 1 - October 31	—	$	—	—	$	192.5
November 1 - November 30	—	—		—	192.5
December 1 - December 31	—	—		—	192.5
Total	—	—		—



	Year Ended December 31,
(in thousands, except per share amounts)	2017			2016			2015			2014			2013
Statement of operations data (1):
Total revenues	$	283,646		$	271,001		$	355,700		$	695,917		$	663,090
Operating income (loss) (2)	(40,556		)	(220,949		)	(1,339,875		)	126,875			179,221
Net income (loss) (3)(4)(5)	$	24,362		$	(225,258	)	$	(1,192,381	)	$	120,669		$	22,204
Basic net income (loss) per share	$	1.14		$	(12.09	)	$	(65.37	)	$	6.75		$	1.55
Diluted net income (loss) per share	$	1.14		$	(12.09	)	$	(65.37	)	$	6.74		$	1.44
Cash dividends declared per share	$	—		$	—		$	—		$	2.25		$	3.00
Weighted average common shares and common share equivalents outstanding:
Basic	21,288			18,630			18,241			17,884			14,334
Diluted	21,288			18,630			18,241			17,892			15,394
Statement of cash flow data:
Net cash provided by (used in):
Operating activities	$	54,411		$	(414	)	$	134,027		$	362,093		$	350,634
Investing activities	(182,551		)	(55,009		)	(300,833		)	(221,588		)	(252,478		)
Financing activities	158,669			52,244			132,748			(144,683		)	(93,317		)
Balance sheet data:
Current assets	$	167,830		$	110,617		$	149,801		$	330,766		$	305,854
Total assets	840,347			661,414			954,126			2,304,942			2,399,836
Current liabilities (6)	1,666,970			258,363			252,919			329,436			349,170
Long-term debt (6)	—			1,258,538			1,320,279			1,430,516			1,850,120
Shareholders' equity	(846,199		)	(871,906		)	(662,323		)	510,004			147,905
Total liabilities and shareholders' equity	840,347			661,414			954,126			2,304,942			2,399,836


(1)	Mmcfe is calculated by converting one barrel of oil into six Mcf of natural gas.


(2)	Equity-based compensation included in general and administrative expense was expense of $2.1 million and income of $11.4 million for the years ended December 31, 2018 and 2017, respectively.


(in thousands)	December 31, 2017		February 28, 2018		December 31, 2018
DIP Credit Agreement	$	—	$	156,406	$	156,406
EXCO Resources Credit Agreement	126,401		—
1.5 Lien Notes	316,958		316,958		316,958
1.75 Lien Term Loans	708,926		708,926		708,926
Exchange Term Loan	17,246		17,246
Second Lien Term Loans					17,246
2018 Notes	131,345		131,345		131,576
2022 Notes	70,169		70,169		70,169
Total principal balance of debt	$	1,371,276	$	1,401,050
Total debt					$	1,401,281
Net debt	$	1,316,408	$	1,295,884	$	1,338,691
Borrowing base	$	150,000	$	250,000	$	250,000
Unused borrowing base (1)	$	605	$	69,600	$	81,600
Cash (2)	$	54,868	$	105,166	$	62,590
Unused borrowing base plus cash	$	55,473	$	174,766	$	144,190


(1)	Net of ~~$23.0 million and $24.0~~$12.0 million in letters of credit ~~as of~~at December 31, ~~2017 and February 28, 2018, respectively.~~2018.


(2)	Includes restricted cash of ~~$15.3 million and $7.4~~$16.0 million at December 31, ~~2017 and February 28, 2018, respectively.~~2018.


(in thousands)	2018 Capital Budget		2019 Capital Budget
Lease purchases and seismic	$	4,000	$	4,000
Development capital expenditures	113,000		136,800
Field operations, gathering and water pipelines	3,000		6,600
Corporate and other	4,000		4,000
Total capital expenditures	$	124,000	$	151,400



	NYMEX gas volume - Bbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Mbbl	Weighted average contract price per Bbl
Swaps:
2018	3,650	$	3.15	—	—



	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
EXCO Resources Credit Agreement (1)	$	126,401	$	—	$	—	$	—	$	126,401
1.5 Lien Notes (2)	—		—		316,958		—		316,958
1.75 Lien Term Loans (3)	—		708,926		—		—		708,926
Exchange Term Loan (4)	—		17,246		—		—		17,246
Senior Notes (5)	131,576		—		70,169				201,745
Gathering and firm transportation services (6)	87,621		94,004		66,612		94,443		342,680
Other fixed commitments (7)	3,222		4,364		1,601		—		9,187
Drilling contracts (8)	1,138		—		—		—		1,138
Operating leases and other	3,760		4,771		36		—		8,567
Total contractual obligations	$	353,718	$	829,311	$	455,376	$	94,443	$	1,732,848


~~(4)~~	The Exchange Term Loan matures on October 26, 2020. Based on the outstanding principal balance as of December 31, 2017, the annual interest obligation on the Exchange Term Loan is $2.2 million based on the interest rate of 12.5% per annum.


~~(5)~~	The 2018 Notes are due on September 15, 2018 and the 2022 Notes are due on April 15, 2022. Based on the outstanding principal balance at December 31, 2016, the annual interest obligation on the 2018 Notes and 2022 Notes is $7.0 million and $6.0 million, respectively.


~~(7)~~	~~Other fixed commitments are primarily related to minimum sales commitments under marketing contracts.~~


~~(8)~~	Drilling contracts represent the contractual rate for our operated rigs through the term of the contracts as of December 31, 2017. The actual drilling costs under these contracts will be incurred by working interest owners in the development of the related properties.