Abraxas Petroleum Corp.
Annual Report 2016

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K(Mark One)ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the Fiscal Year Ended December 31, 2016rTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Commission File Number 001-16071ABRAXAS PETROLEUM CORPORATION(Exact name of Registrant as specified in its charter) Nevada 74-2584033(State or Other Jurisdiction ofIncorporation or Organization) (I.R.S. Employer Identification Number) 18803 Meisner DriveSan Antonio, TX 78258(Address of principal executive offices)(210) 490-4788Registrant’s telephone number, including area codeSECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:Title of each class: Name of each exchange on which registered:Common Stock, par value $.01 per share The NASDAQ Stock Market, LLCSECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:NoneIndicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. oYes No ýIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.Yes o No ýIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filingrequirements for the past 90 days.Yes ýNoIndicate by check mark if the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File requiredto be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files). Yes ý No oIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained,to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendmentto this Form 10-K. Yes x No oIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reportingcompany. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):Large accelerated filer ⃞Accelerated filer xNon-accelerated filer ⃞ (Do not check if a smaller reporting company)Smaller reporting company ⃞Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No ýAs of June 30, 2016, the last day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the common stockheld by non-affiliates of the registrant was $141,714,282 based on the closing sale price as reported on The NASDAQ Stock Market. As of March 10, 2017, there were 163,844,255 shares of common stock outstanding. Documents Incorporated by Reference:Document Parts Into Which IncorporatedPortions of the registrant’s Proxy Statement relating to the 2017Annual Meeting of Stockholders to be held on May 9, 2017. Part IIIABRAXAS PETROLEUM CORPORATIONFORM 10-KTABLE OF CONTENTS PagePart I Item 1.Business5Item 1A.Risk Factors15Item 1B.Unresolved Staff Comments32Item 2.Properties32Item 3.Legal Proceedings39Item 4.Mine Safety Disclosures39 Part II Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities40Item 6.Selected Financial Data42Item 7.Management’s Discussion and Analysis of Financial Condition and Resultsof Operations42Item 7A.Quantitative and Qualitative Disclosure about Market Risk56Item 8.Financial Statements and Supplementary Data57Item 9.Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure57Item 9A.Controls and Procedures57Item 9B.Other Information58 Part III Item 10.Directors, Executive Officers and Corporate Governance58Item 11.Executive Compensation58Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters59Item 13.Certain Relationships and Related Transactions, and Director Independence59Item 14.Principal Accountant Fees and Services59 Part IV Item 15.Exhibits and Financial Statement Schedules60 Item 16.Form 10-K Summary62Table of ContentsWe make forward-looking statements throughout this report. Whenever you read a statement that is not simply a statement of historical fact (such asstatements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “plan,” “seek,” “may,” “estimate,” “could,” “potentially” or similarexpressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they arereasonable. The forward-looking information contained in this report is generally located in the material set forth under the headings “Management’sDiscussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well. These forward-looking statementsgenerally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends. Thefactors that may affect our expectations regarding our operations include, among others, the following:•the prices we receive for our production and the effectiveness of our hedging activities;•the availability of capital including under our credit facility;•our success in development, exploitation and exploration activities;•declines in our production of oil and gas;•our indebtedness and the significant amount of cash required to service our indebtedness;•limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our bank creditfacility and restrictive debt covenants;•our ability to make planned capital expenditures;•ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices;•political and economic conditions in oil producing countries, especially those in the Middle East;•price and availability of alternative fuels;•our ability to procure services and equipment for our drilling and completion activities;•our acquisition and divestiture activities;•weather conditions and events;•the proximity, capacity, cost and availability of pipelines and other transportation facilities; and•other factors discussed elsewhere in this report.Initial production, or IP, rates, for both our wells and for those wells that are located near our properties, are limited data points in each well’sproductive history. These rates are sometimes actual rates and sometimes extrapolated or normalized rates. As such, the rates for a particular well may changeas additional data becomes available. Peak production rates are not necessarily indicative or predictive of future production rates, expected ultimaterecovery, or EUR, or economic rates of return from such wells and should not be relied upon for such purpose. Equally, the way we calculate and report peakIP rates and the methodologies employed by others may not be consistent, and thus the values reported may not be directly and meaningfully comparable.Lateral lengths described are indicative only. Actual completed lateral lengths depend on various considerations such as lease-line offsets. Abraxas 'standardlength laterals, sometimes referred to as 5,000 foot laterals, are laterals with completed length generally between 4,000 feet and 5,500 feet. Mid-lengthlaterals, sometimes referred to as 7,500 foot laterals, are laterals with completed length generally between 6,500 feet and 8,000 feet. Long laterals, sometimesreferred to as 10,000 foot laterals, are laterals with completed length generally longer than 8,000 feet.GLOSSARY OF TERMSUnless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the state or area in which the reserves are located at 60degrees Fahrenheit. Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil. 2Table of ContentsThe following definitions shall apply to the technical terms used in this report. Terms used to describe quantities of oil and gas: “Bbl” – barrel or barrels. “Bcf” – billion cubic feet of gas. “Bcfe” – billion cubic feet of gas equivalent. “Boe” – barrels of oil equivalent.“Boepd" - barrels of oil equivalents per day.“MBbl” – thousand barrels.“MBoe” – thousand barrels of oil equivalent. “Mcf” – thousand cubic feet of gas. “Mcfe” – thousand cubic feet of gas equivalent. “MMBbl” – million barrels. “MMBoe” – million barrels of oil equivalent. “MMBtu” – million British Thermal Units of gas. “MMcf” – million cubic feet of gas. “MMcfe” – million cubic feet of gas equivalent. “NGL” – natural gas liquids measured in barrels. Terms used to describe our interests in wells and acreage: “Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells. “Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth or stratigraphic horizon (rock layer orformation) noted to be productive for the purpose of extracting reserves. “Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justifycompletion. “Exploratory well” is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to beproducing in another reservoir, or to extend a known reservoir. “Gross acres” are the number of acres in which we own a working interest. “Gross well” is a well in which we own an interest. “Net acres” are the sum of fractional ownership working interests in gross acres (e.g., a 50% working interest in a lease covering 320 gross acresis equivalent to 160 net acres). “Net well” is the sum of fractional ownership working interests in gross wells. “Productive well” is an exploratory or a development well that is not a dry hole. 3Table of Contents“Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit theproduction of economic quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Terms used to assign a present value to or to classify our reserves: “Developed oil and gas reserves*” Developed oil and gas 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 relativelyminor 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 bymeans not involving a well.“Proved developed non-producing reserves*” are those quantities of oil and gas reserves that are developed behind pipe in an existing wellbore, from a shut-in well bore or that can be recovered through improved recovery only after the necessary equipment has been installed, orwhen the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at thetime of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wellsnot capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that willrequire additional completion work or future recompletion prior to the start of production.“Proved developed reserves*” Reserves that can be expected to be recovered through existing wells with existing equipment and operatingmethods.“Proved reserves*” Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years fromknown reservoirs under existing economic and operating conditions.“Proved undeveloped reserves” or “PUDs*” Reserves that are expected to be recovered from new wells on undrilled acreage or from existingwells, in each case where a relatively major expenditure is required. “PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation orde-escalation, calculated in accordance with guidelines promulgated by the Securities and Exchange Commission (“SEC”). “Standardized Measure” means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price orcost escalation or de-escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, “Disclosures About Oil andGas Producing Activities.”“Undeveloped oil and gas reserves*"” Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered fromnew wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the completedefinition, see: http://www.ecfr.gov/cgi-bin/retrieveECFR?gp=1&SID=7aa25d3cede06103c0ecec861362497d&ty=HTML&h=L&n=pt17.3.210&r=PART#se17.3.210_14_6104Table of ContentsPart I Information contained in this report represents the consolidated operations of Abraxas Petroleum Corporation. The terms “Abraxas,” “we,” “us,”“our,” or the “Company,” refer to Abraxas Petroleum Corporation, together with its consolidated subsidiaries including Raven Drilling, LLC which is awholly owned subsidiary that owns a drilling rig. On October 31, 2014, we sold our interest in Canadian Abraxas Petroleum, ULC (“ Canadian Abraxas”),an indirect wholly-owned Canadian subsidiary of Abraxas. As a result of the disposal of Canadian Abraxas, the results of operations of Canadian Abraxasare reflected in our Financial Statements and in this report as “Discontinued Operations” and our remaining operations are referred to in our FinancialStatements and in this report as “Continuing Operations” or “Continued Operations.” Unless otherwise noted, all disclosures are for ContinuingOperations.Item 1. Business General We are an independent energy company primarily engaged in the acquisition, exploration, development and production of oil and gas. At December 31,2016, our estimated net proved reserves were 44.7 MMBoe, of which 33.6% were classified as proved developed, 74% were oil and NGL and 95% of which(on a PV-10 basis) were operated by us. Our daily net production for the year ended December 31, 2016 was 6,181 Boepd, of which 61% was oil or liquids.Abraxas Petroleum Corporation was incorporated in Nevada in 1990. Our address is 18803 Meisner Drive, San Antonio, Texas 78258 and our phone numberis (210) 490-4788.Our oil and gas assets are located in three operating regions, the Permian/Delaware Basin, the Rocky Mountain, and South Texas. The following tablesets forth certain information related to our properties as of and for the year ended December 31, 2016: Estimated Net ProvedReserves NetProduction GrossProducingWells AverageWorkingInterest Total Net Acres (MBoe) %Oil/NGL (MBoe) %Oil/NGLPermian/Delaware Basin 182 84.26% 26,673 9,911 47.0% 262.0 52.8%Rocky Mountain (1) 780 10.31% 28,474 32,509 84.3% 1,696.2 82.7%South Texas 39 72.31% 13,238 2,237 35.3% 304.1 63.8%Total United States 1,001 26.17% 68,385 44,657 73.6% 2,262.3 77.0%_____________________(1) In January 2017, we sold our Brooks Draw assets in the Powder River Basin consisting of 14,229 net acres and no reserves as of December 31, 2016.The amounts set forth in the table reflect this sale.Our properties in the Permian/Delaware Basin region are primarily located in two sub-basins, the Delaware Basin and the Eastern Shelf. In the DelawareBasin, our wells are located in Pecos, Reeves, and Ward Counties, Texas and produce oil and gas from multiple stacked formations from the Bell Canyon at5,000 feet down to the Ellenburger at 16,000 feet. In the Eastern Shelf, our wells are principally located in Coke, Scurry, Mitchell and Nolan Counties, Texasand produce oil and gas from the Strawn Reef formation at 5,000 to 7,500 feet and oil from the shallower Clearfork formation at depths ranging from 2,300 to3,300 feet.Our properties in the Rocky Mountain region are located in the Williston Basin of North Dakota and Montana and in Powder River, Green River andUinta Basins of Wyoming and Utah. In this region, our wells produce oil and gas from various reservoirs, primarily the Turner, Bakken, Three Forks and RedRiver formations. Well depths range from 7,000 feet down to 14,000 feet. Our properties in the South Texas region are located along the Edwards trend in DeWitt and Lavaca Counties, Texas and the Eagle Ford shale and theAustin Chalk in Atascosa and McMullen Counties, Texas. In the Edwards trend, our wells produce gas from the Edwards formation at a depth of 14,000 feet.In the Eagle Ford, our wells produce from the Eagle Ford shale from 8,000 to 11,000 feet and from the Austin Chalk from 7,500 to 8,000 feet. StrategyOur business strategy is to focus our capital and resources on our core operated basins, maintain financial flexibility and to profitably grow productionand reserves. Key elements of our business strategy include:5Table of ContentsFocus our capital and resources on our core operated basins. Our core basins consist of the Permian/Delaware Basin (Bone Spring and Wolfcamp),Williston Basin (Bakken and Three Forks) and South Texas (Eagle Ford shale and Austin Chalk). Given the disparity which has existed during the pastseveral years and which continues currently between oil and gas prices, the economics of drilling oil wells is far superior to drilling gas wells. Thus,substantially all of our 2017 capital expenditures (approximately $110.0 million) will be used for drilling and completing seven gross (six net) horizontalwells targeting the Bone Spring and Wolfcamp formations in the Delaware Basin, drilling and completing seven gross (five net) wells in the Bakken/ThreeForks, drilling an additional four gross (two net) wells in the Bakken/Three Forks that will be completed in 2018, participating in the drilling and completingof five gross (one net) non-operated wells in the Bakken/Three Forks and drilling and completing two gross/net horizontal wells in the Austin Chalk/EagleFord in South Texas. As part of our efforts to focus our property portfolio, we are continually marketing assets we have deemed non-core. These include assetswith a low working interest that are non-operated and/or that fall outside of our three core basins. Any proceeds from these asset sales have been and willcontinue to be used to reduce our indebtedness and/or be redeployed into our core operating basins. Since January 1, 2016, we have received approximately$28.6 million from the sale of non-core properties.Maintain financial flexibility. Our primary sources of capital are availability under our bank credit facility and cash flow from operations.Availability under our bank credit facility is subject to a borrowing base which is determined semi-annually by our lenders. The next redetermination isscheduled for April 2017. On December 31, 2016, we had approximately $22.0 million of availability under our credit facility and for the year endedDecember 31, 2016, we generated approximately $26.9 million of cash flow from operations. After completion of the offering of 28.8 million shares of ourcommon stock in January 2017, we had approximately $ 95.0 million of availability under our credit facility.We seek to reduce the volatility of our cash flow from operations by hedging a portion of our production. As of December 31, 2016, we had NYMEX-based fixed price commodity swap arrangements, on approximately 70% of the oil production from our estimated net proved developed producing reserves(as of December 31, 2016) through December 31, 2017, 77% for 2018 and 64% for 2019. We have also entered into a NYMEX-based collar on approximately56% of the gas production from our estimated net proved developed producing reserves (as of December 31, 2016) through December 31, 2017 and a 500Bopd Midland-Cushing oil price differential swap at ($0.65)/Bbl.We plan on deploying our available capital in a cost-effective manner. We seek to operate a high percentage of our properties which allows us tobetter control costs. At December 31, 2016, we operated properties comprising 95% of our proved developed reserves on a PV-10 basis. We intend tomaintain our liquidity and the strength of our balance sheet during 2017 by adjusting our capital budget as necessary and seeking to reduce expenses.Profitably grow production and reserves. We have a substantial low-decline legacy production base as evidenced by our approximate 21-yearaverage reserve life as of year-end 2016. Our capital is currently being deployed largely into unconventional oil assets with relatively predictable productionprofiles, yet steep initial decline rates. Therefore, the economics of these oil wells are highly dependent on both near term commodity prices and strongoperational cost control. Cost savings achieved through efficiencies of using our own rig in the Williston Basin, and heightened focus on cost control in allof our operated positions both contribute to our historical success in adding low cost barrels to our production base.2017 Budget and Drilling Activities Our capital expenditure budget for 2017 is approximately $110.0 million. Approximately $52.5 million of the 2017 budget will be allocated todeveloping the Company’s Permian/Delaware Basin assets, including approximately $15.0 million dedicated to expanding our acreage position inthe Delaware Basin. The budget also allocates approximately $42.2 million for drilling and completion of wells in our Williston Basin Bakken/Three Forksplay in North Dakota, with the remaining amount allocated to the Austin Chalk/Eagle Ford area in South Texas as well as lease acquisition and generalcorporate purposes. The 2017 capital expenditure budget is subject to change depending upon a number of factors, including the availability of sufficientcapital resources including under our credit facility, the availability and costs of drilling and service equipment and crews, economic and industry conditionsat the time of drilling, prevailing and anticipated prices for oil and gas, the results of our exploitation efforts, our financial results and our ability to obtainpermits for drilling locations.Markets and Customers The revenue generated by our operations is highly dependent upon the prices we receive for our oil and gas. Historically, the markets for oil and gas havebeen volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations anddepend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector),foreign imports, political conditions in other petroleum6Table of Contentsproducing countries, the actions of the Organization of Petroleum Exporting Countries, domestic regulation, legislation and policies. Decreases in the priceswe receive for our oil and gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves, our revenue, profitabilityand cash flow from operations. Refer to “Risk Factors – Risks Related to Our Industry — Market conditions for oil and gas, and particularly volatility ofprices for oil and gas, could adversely affect our revenue, cash flows, profitability and growth” and “Management’s Discussion and Analysis of FinancialCondition and Results of Operations – Critical Accounting Policies” for more information relating to the effects that decreases in oil and gas prices have onus. To help mitigate the impact of commodity price volatility, we hedge a portion of our production through the use of fixed price swaps and three waycollars. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General – Commodity Prices and HedgingArrangements” and Note 11 of the notes to our consolidated financial statements for more information regarding our derivative activities. Substantially all of our oil and gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year endedDecember 31, 2016, two purchasers of production accounted for approximately 71% of our oil and gas sales. During the year ended December 31, 2015, onepurchaser of production accounted for approximately 54% of our oil and gas sales. We believe that there are numerous other purchasers available to buy ouroil and gas and that the loss of any of these purchasers would not materially affect our ability to sell our oil and gas. Furthermore, the largest purchasers of ouroil and gas have changed from year to year from 2014 to 2016.Regulation of Oil and Gas Activities The exploration, production and transportation of all types of hydrocarbons are subject to significant governmental regulations. Our properties areaffected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas productionoperations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental and other lawsrelating to the petroleum industry, and by changes in such laws and by periodically changing administrative regulations. Federal, state and local laws and regulations govern oil and gas activities. Operators of oil and gas properties are required to have a number of permitsin order to operate such properties, including operator permits and permits to dispose of salt water. We possess all material requisite permits required by thestates and other local authorities in which we operate properties. In addition, under federal law, operators of oil and gas properties are required to possesscertain certificates and permits in order to operate such properties such as hazardous materials certificates, which we have obtained. Development and Production The operations of our properties are subject to various types of regulation at the federal, state and local levels. These types of regulations includerequiring the operator of oil and gas properties to possess permits for the drilling and development of wells, post bonds in connection with various types ofactivities, and file reports concerning operations. Most states, and some counties and municipalities in which we operate, regulate one or more of thefollowing: •the location of wells;•the method of drilling and casing wells;•the flaring of gas;•the method of completing and fracture stimulating wells;•the surface use and restoration of properties upon which wells are drilled;•the plugging and abandoning of wells; and•the notice to surface owners and other third parties.Some states regulate the size and shape of development and spacing units or proration units for oil and gas properties. Some states allow forcedpooling or unitization of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling orunitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establishmaximum allowable rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding theratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or thelocations at which our wells can be drilled. Moreover, each state generally imposes a production or severance tax with respect to the production and sale ofoil, gas and NGLs within its jurisdiction.7Table of Contents Operations on Federal or Indian oil and gas leases must comply with numerous regulatory restrictions, including various non-discrimination statutes,and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various tribal and federalagencies, including the Bureau of Land Management and the Office of Natural Resources Revenue, which we refer to as ONRR, (formerly MineralsManagement Service). ONRR establishes the basis for royalty payments due under federal oil and gas leases through regulations issued under applicablestatutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and gas leases. The basis for royaltypayments established by ONRR and the state regulatory authorities is generally applicable to all federal and state oil and gas leases. Accordingly, we believethat the impact of royalty regulation on the operations of our properties should generally be the same as the impact on our competitors. We believe that theoperations of our properties are in material compliance with all applicable regulations as they pertain to Federal or Indian oil and gas leases. The failure to comply with these rules and regulations can result in substantial penalties, including lease suspension or termination in certain cases.The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oiland gas industry are subject to the same regulatory requirements and restrictions that affect us. Regulation of Transportation and Sale of Gas in the United States Historically, the transportation and sale for resale of gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, asamended, which we refer to as NGA, the Natural Gas Policy Act of 1978, as amended, which we refer to as NGPA, and regulations promulgated thereunder bythe Federal Energy Regulatory Commission, which we refer to as FERC, and its predecessors. In the past, the federal government has regulated the prices atwhich gas could be sold. Deregulation of wellhead gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas WellheadDecontrol Act, as amended, which we refer to as the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affectingwellhead sales of gas effective January 1, 1993. While sales by producers of gas can currently be made at unregulated market prices, Congress could reenactprice controls in the future. Since 1985, FERC has endeavored to make gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis.FERC has stated that open access policies are necessary to improve the competitive structure of the interstate gas pipeline industry and to create a regulatoryframework that will put gas sellers into more direct contractual relations with gas buyers by, among other things, unbundling the sale of gas from the sale oftransportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders, which we refer to collectively as OrderNo. 636, to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of gas have been significantly altered.The interstate pipelines’ traditional role as wholesalers of gas has been eliminated and replaced by a structure under which pipelines provide transportationand storage service on an open access basis to others who buy and sell gas. FERC continues to regulate the rates that interstate pipelines may charge for suchtransportation and storage services. Although FERC’s orders do not directly regulate gas producers, they are intended to foster increased competition withinall phases of the gas industry. In 2000, FERC issued Order No. 637 and subsequent orders, which we refer to, collectively, as Order No. 637, which imposed a number of additionalreforms designed to enhance competition in gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to schedulingprocedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld onjudicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect. The Energy Policy Act of 2005, which we refer to as EP Act 2005, gave FERC increased oversight and penalty authority regarding marketmanipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the NGPA to increase civiland criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. Inaddition, FERC issued a final rule effective January 26, 2006, regarding market manipulation, which makes it unlawful for any entity, in connection with thepurchase or sale of gas or transportation service subject to FERC jurisdiction, to defraud, make an untrue statement, or omit a material fact or engage in anypractice, act, or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority toprovide increased oversight of the gas marketplace.The gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach currentlypursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects othergas producers, gatherers and marketers. 8Table of ContentsGenerally, intrastate gas transportation is subject to regulation by state regulatory agencies, although FERC does regulate the rates, terms, andconditions of service provided by intrastate pipelines that transport gas subject to FERC’s NGA jurisdiction pursuant to Section 311 of the NGPA. The basisfor state regulation of intrastate gas transportation and the degree of regulatory oversight and scrutiny given to intrastate gas pipeline rates and services variesfrom state to state. Insofar as such regulation within a particular state will generally affect all intrastate gas shippers within the state on a comparable basis, webelieve that the regulation of similarly situated intrastate gas transportation in any states in which we operate and ship gas on an intrastate basis will notaffect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors.Gas Gathering in the United States Section 1(b) of the NGA exempts gas gathering facilities from the jurisdiction of the FERC. FERC has developed tests for determining which facilitiesconstitute jurisdictional transportation facilities under the NGA and which facilities constitute gathering facilities exempt from FERC’s NGA jurisdiction.From time to time, FERC reconsiders its test for defining non-jurisdictional gathering. FERC has also permitted jurisdictional pipelines to “spin down”exempt gathering facilities into affiliated entities that are not subject to FERC jurisdiction, although FERC continues to examine the circumstances in whichsuch a “spin down” is appropriate and whether it should reassert jurisdiction over certain gathering companies and facilities that previously had been “spundown.” We cannot predict the effect that FERC’s activities in this regard may have on the operations of our properties, but we do not expect these activitiesto affect the operations in any way that is materially different from the effect thereof on our competitors. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take or servicerequirements, but does not generally entail rate regulation. In the United States, gas gathering has received greater regulatory scrutiny at both the state andfederal levels in the wake of the interstate pipeline restructuring under FERC Order 636. For example, the Texas Railroad Commission enacted a Natural GasTransportation Standards and Code of Conduct to provide regulatory support for the state’s more active review of rates, services and practices associated withthe gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from undulydiscriminating in favor of their affiliates. Regulation of Transportation of Oil in the United States Sales of oil, condensate and gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrierpipelines is subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oilpipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certaincircumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oilthat allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by FERC in 2000 was successfullychallenged on appeal by an association of oil pipelines. On remand, FERC, in February 2003, increased the index slightly, effective July 2001. Intrastate oilpipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulations, and the degree ofregulatory oversight and scrutiny given to intrastate oil pipeline rates varies from state to state. Insofar as effective interstate and intrastate rates are equallyapplicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect the operations of our properties in any way thatis materially different from the effect of such regulation on our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard,common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity,access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportationservices generally will be available to us to the same extent as to our competitors.All of our oil is sold on lease, at which time custody transfers, either by truck or pipeline. We are not able to determine how much of our sold oil isultimately shipped to market centers using rail transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s (“U.S.DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) establishes safety regulations relating to transportation of oil by railtransportation. In addition, third party rail operators are subject to the regulatory jurisdiction of the Surface Transportation Board of the U.S. DOT, the FederalRailroad Administration (“FRA”) of the DOT, OSHA, as well as other federal regulatory agencies. Additionally, various state and local agencies havejurisdiction over disposal of hazardous waste and seek to regulate movement of hazardous materials in ways not preempted by federal law.In response to rail accidents occurring between 2002 and 2008, the U.S. Congress passed the Rail Safety and Improvement Act of 2008, whichimplemented regulations governing different areas related to railroad safety. Recently, in response to train9Table of Contentsderailments occurring in 2013, U.S. regulators have been implementing or considering new rules to address the safety risks of transporting oil by rail. OnJanuary 23, 2014, the National Transportation Safety Board (“NTSB”) issued a series of recommendations to the FRA and PHMSA to address safety risks,including (i) requiring expanded hazardous material route planning for railroads to avoid populated and other sensitive areas, (ii) developing an auditprogram to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-case discharges of the entire quantity ofproduct carried on a train, and (iii) auditing shippers and rail carriers to ensure they are properly classifying hazardous materials in transportation and thatthey have adequate safety and security plans in place. Additionally, on February 25, 2014 the DOT issued an emergency order requiring all persons, prior tooffering oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail of oil be handled as a Packing Group Ior II hazardous material.We do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing orhandling of shipments of oil by rail transportation could increase our costs of doing business and limit our ability to transport and sell our oil at favorableprices at market centers throughout the United States, the consequences of which could have a material adverse effect on our financial condition, results ofoperations and cash flows. At this time, it is not possible to estimate the potential impact on our business if new federal or state rail transportation regulationsare enacted.Environmental Matters Oil and gas operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, treatment, storage anddisposal of materials and the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws andregulations may: •require the acquisition of a permit or other authorization before construction or drilling commences;•impose design, construction and permitting requirements on facilities in conjunction with oil and gas operations, including the construction ofpollution control devices;•require protective measures to prevent drilling fluids from coming into contact with ground water;•restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling,production, and gas processing activities;•suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and areas inhabited bythreatened or endangered species and other protected areas;•require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;•require disclosure of chemicals injected into wells in conjunction with hydraulic fracturing operations;•restrict injection of liquids into subsurface strata that may contaminate groundwater;•restrict the availability of water necessary for hydraulic fracturing operations;•impose substantial penalties for violations of environmental rules or pollution resulting from our operations; and•curtail production in association with permit limits or exceeding gas flaring limits.Environmental permits that the operators of properties are required to possess may be subject to revocation, modification, and renewal by issuingauthorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civilfines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and thatwe will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws andregulations or interpretations thereof could have a significant impact on our operations as well as the oil and gas industry in general, and thus we are unableto predict the ultimate cost and effects of future changes in environmental laws and regulations. We are not currently involved in any administrative, judicial or legal proceedings arising under federal, state, or local environmental protection lawsand regulations, or under federal or state common law, which would have a material adverse effect on our respective financial positions or results ofoperations. Moreover, we maintain insurance against the costs of clean-up operations,10Table of Contentsbut we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area. The following is a discussion of the current relevant environmental laws and regulations that relate to our operations. Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation andLiability Act, also known as Superfund, and which we refer to as CERCLA, and comparable state statutes impose strict joint, and several liability, withoutregard to fault or legality of conduct, on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into theenvironment. These persons include among others, the current and former owners or operators of a disposal site or sites where a release occurred andcompanies that arranged for the transportation or disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies maybe retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources,and for the costs of certain health studies. CERCLA authorizes the Environmental Protection Agency ("EPA"), and in some cases third parties, to take actionsin response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, itis not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costsallegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, certain wastes may be generated that may fall within CERCLA’s definition of a “hazardous substance.” Wemay be liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.Although CERCLA currently contains a “petroleum exclusion” from the definition of “hazardous substance,” state laws affecting our operations imposecleanup liability relating to petroleum and petroleum related products, including oil cleanups.We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration andproduction of oil and gas. Although we have utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may havebeen disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. Inaddition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not underour control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA (as defined below), and analogous state laws. Under theselaws, we could be required to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators; to clean upcontaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination. Oil Pollution Act of 1990. Federal regulations also require certain owners and operators of facilities that store or otherwise handle oil to prepare andimplement spill response plans relating to the potential discharge of oil into surface waters. The Federal Oil Pollution Act, which we refer to as OPA, andanalogous state laws, contain numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. Afailure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminalenforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’sfinancial responsibility and other operating requirements will not have a material adverse effect on our financial position or results of operations. Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, which we refer to as RCRA, is the principal federal statutegoverning the treatment, storage and disposal of hazardous and non-hazardous solid wastes. RCRA imposes stringent operating requirements and liabilityfor failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardouswaste treatment, storage or disposal facility. Analogous state laws further impose requirements associated with the management of solid wastes. At present,RCRA includes a statutory exemption that allows most oil and gas exploration and production wastes to be classified and regulated as non-hazardous wastes.A similar exemption is contained in many of the state counterparts to RCRA. At various times in the past, proposals have been made to amend RCRA torescind the exemption that excludes oil and gas exploration and production wastes from regulation as hazardous wastes. Repeal or modification of theexemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume ofhazardous waste we are required to manage and dispose and would cause us to incur increased operating expenses. Also, in the ordinary course of ouroperations, we generate small amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardouswastes. We believe that our operations comply in all material respects with the requirements of RCRA and its state counterparts. Naturally Occurring Radioactive Materials, which we refer to as NORM, are materials not covered by the Atomic Energy Act, whose radioactivity isenhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and gas industry.NORM wastes are regulated under the RCRA framework, but primary responsibility11Table of Contentsfor NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste;management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that theoperations of our properties are in material compliance with all applicable NORM standards established by the various states in which we operate wells. Clean Water Act. The Clean Water Act, which we refer to as the CWA, and analogous state laws, impose restrictions and controls on the discharge ofpollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters isprohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil andgas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm waterrun-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and otherwaters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWArequire appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a petroleumhydrocarbon tank spill, rupture or leak. EPA and the U.S. Army Corps of Engineers have adopted a rule that arguably expands the scope of “waters of theUnited States” that are regulated under the CWA. This rule could impact our operations by subjecting new waters to regulation; however, enforcement of therule has been stayed while it is undergoing legal challenge in the federal courts and recently the U.S. Supreme Court agreed to take up jurisdiction issuesrelated to the rulemaking. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of oiland other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by therelease and for resource damages resulting from the release. We believe that the operations of our properties comply in all material respects with therequirements of the CWA and state statutes enacted to control water pollution.Safe Drinking Water Act. Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated bythe Safe Drinking Water Act, which we refer to as the SDWA, and analogous state and local laws. Underground injection is the subsurface placement of fluidthrough a well, such as the reinjection of brine produced and separated from oil and gas production. The main goal of the SDWA is the protection of usableaquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to preventmigration of fluids from the injection zone into underground sources of drinking water. Injection well operations are strictly controlled, and certain wastes,absent an exemption, cannot be injected into underground injection control wells. In most states, no underground injection may take place except asauthorized by permit or rule. In addition, subsurface injection of water or other produced fluids from drilling or hydraulic fracturing processes have comeunder increased public and governmental scrutiny. Some jurisdictions, Texas for example, have adopted new and more stringent rules for injection wellsaimed at reducing the potential for earthquakes associated with injection activities, including new restrictions on siting of such injection wells. We currentlyown and operate various underground injection wells. Failure to comply with our permits could subject us to civil and/or criminal enforcement. We believethat we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits. Clean Air Act. The Clean Air Act, which we refer to as the CAA, and state air pollution laws and regulations provide a framework for national, stateand local efforts to protect air quality. The operations of our properties utilize equipment that emits air pollutants which may be subject to federal and stateair pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient airquality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. In the past few years, EPAhas adopted new more restrictive regulations governing air emissions from oil and gas operations and has proposed rules that are still under review, includingregulations which impose new restrictions on emissions of methane, volatile organic compounds and hazardous air pollutants. Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regionalnon-attainment areas may require oil and gas exploration and production operators to incur future capital expenditures in connection with the addition ormodification of existing air emission control equipment and strategies. EPA has adopted a new ozone standard which will result in additional areas beingdesignated as nonattainment and therefore subject to more stringent rules and permitting requirements. In addition, some oil and gas facilities may beincluded within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with theserequirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil andgas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connectionwith obtaining and maintaining operating permits and approvals for air emissions. We believe that we are in compliance in all material respects with therequirements of applicable federal and state air pollution control laws. Hydraulic Fracturing. Most of our current operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. Thistechnology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of chemical additives—as well assand, or other proppants, into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Manyof our newer wells would not be economical without the12Table of Contentsuse of hydraulic fracturing to stimulate the formation to enhance production from the well. Hydraulic fracturing operations have historically been overseenby state regulators as part of their oil and gas regulatory programs. In December 2016, the EPA issued its final report “Hydraulic Fracturing for Oil and Gas:Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States” which assessed the potential impact of hydraulicfracturing on drinking water resources. The report acknowledged data gaps and uncertainties, removed the draft finding of no widespread systemic impactsfrom hydraulic fracturing, but concluded that the agency could not quantify the frequency or severity of such impacts on a national level, thereby leaving thedoor open to additional regulations to protect drinking water resources. The U.S. Department of the Interior, Bureau of Land Management (“BLM”) releasedfinal regulations, in 2015, concerning hydraulic fracturing on federal and tribal lands, including chemical disclosure. These rules are currently under judicialchallenge. In addition to these federal legislative and regulatory proposals, some states and local governments have considered imposing, or have adoptedvarious conditions and restrictions on hydraulic fracturing operations, including but not limited to requirements regarding chemical disclosure, casing andcementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, andrestrictions on the type of additives that may be used in hydraulic fracturing operations. In some states, including Texas, water use may also be regulated andpotentially curtailed by local groundwater management districts which could impact water available for hydraulic fracturing. If these types of restrictions arewidely adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells, and these laws could make it easier for thirdparties to initiate litigation against us in the event of perceived problems with water wells in the vicinity of an oil or gas well or other alleged environmentalproblems. Some states in which we operate have implemented disclosure requirements for chemicals used in hydraulic fracturing. Additional informationconcerning hydraulic fracturing is included under Item 1A. related to risk factors. Climate Change Legislation and Greenhouse Gas Regulation. Studies over recent years have indicated that emissions of certain gases may becontributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or“GHGs” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas,and carbon dioxide, a byproduct of the burning of oil, gas, and refined petroleum products, are considered “greenhouse gases” regulated by the KyotoProtocol. In December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change inParis, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. Ifratified, the Paris Agreement will take effect in 2020. It is possible that the Paris Agreement and subsequent domestic and international regulations will haveadverse effects on the market for oil, gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in theexploration for, and production of, oil, gas and other fossil fuel products. We are unable to predict the timing, scope and effect of any currently proposed orfuture investigations, laws, regulations or treaties regarding climate change and GHG emissions that may arise from the Paris Agreement, but the direct andindirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect our operations, financial condition andresults of operations. In addition, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissionsof methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. As a result of the U.S.Supreme Court decision in Massachusetts, et al. v. EPA, on December 7, 2009, the EPA issued a finding that serves as the foundation under the Clean Air Actto issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action.As part of this array of new regulations, the EPA has issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oiland gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. These regulations may apply to ouroperations. The EPA has adopted other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect sources inthe oil and gas exploration and production industry and the pipeline industry. Moreover, in May 2016 the EPA adopted rules to force the aggregation ofwells and facilities for air emission permitting purposes, and also rules to reduce methane emissions from equipment and leaks from new oil and gas facilities.Both were part of the Obama Administration's plans to reduce methane emissions from the oil and gas sector by 40 to 50 percent from 2012 emission levelsby 2025. The EPA’s finding, the greenhouse gas reporting rule, the methane rules and the other rules to regulate the emissions of greenhouse gases may affectthe cost of our operations and also affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to ourindustry. Although various climate change legislative measures have been under consideration by the U.S. Congress, it is not possible at this time to predictwhen, or if, Congress will act on climate change legislation or how and when the new Trump Administration will address the issues. Finally, some states,either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of GHGs, primarily through theplanned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular jurisdiction of our operations,we could be required to purchase and surrender allowances for GHG emissions resulting from our operations. Any of the climate change regulatory andlegislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations. Additionalinformation concerning climate change is included under Item 1A. related to risk factors. 13Table of ContentsNational Environmental Policy Act. Oil and gas exploration and production activities on federal lands are subject to the National EnvironmentalPolicy Act, which we refer to as NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having thepotential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses thepotential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement thatmay be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, thoseactivities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the developmentof oil and gas projects. Endangered Species Act. The Endangered Species Act, which we refer to as the ESA, restricts activities that may affect endangered or threatenedspecies or their habitats. While some of our properties may be located in areas that may be designated as habitat for endangered or threatened species, webelieve that we are in substantial compliance with the ESA. Looking forward, we expect more listings of such species to occur, in light of consent decreesinvolving the U.S. Fish and Wildlife Service which require the agency to decide whether or not to list, as endangered or threatened, approximately 251candidate species. Included in this group are a number of species which, if listed, could include habitat in areas where we operate or plan to operate. Further,some of the species could become subject to voluntary rangeland conservation plans that could affect our operations. Such listing of additional species, orthe discovery of previously unidentified endangered or threatened species, or the adoption of conservation plans, could cause us to incur additional costs orbecome subject to operating restrictions, construction delays, or bans on operating in the affected areas. Abandonment Costs. All of our oil and gas wells will require proper plugging and abandonment at some time in the future. We have posted bondswith most regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclamation ofthe surface site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that areno longer producing.Title to Properties As is customary in the oil and gas industry, we make only a cursory review of title to undeveloped oil and gas leases at the time we acquire them.However, before drilling commences, we make a thorough title search, and any material defects in title are remedied prior to the time actual drilling of a wellbegins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typicallyobligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent tocommence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to ourproperties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and gas properties we own are also typically subject toroyalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materiallyaffect our ownership or use of our properties. Competition We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leaseholdprospects under which oil and gas reserves may be discovered, drilling rigs and related equipment and services to explore for such reserves andknowledgeable personnel to conduct all phases of oil and gas operations. We must compete for such resources with both major oil and gas companies andindependent operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our currentoperating and financial resources are adequate to preclude any significant disruption of our near term operations, we cannot assure you that such materialsand resources will be available to us in the future. Employees As of March 10, 2017, we had 109 full-time employees. We retain independent geological, land, marketing engineering and health and safetyconsultants from time to time and expect to continue to do so in the future.Available Information We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You mayread and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Please callthe SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet web site that contains annual, quarterly and currentreports, proxy statements and other information that issuers (including Abraxas) file electronically with the SEC. The SEC’s web site is www.sec.gov.14Table of Contents Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments filed with the SECare available free of charge on our web site at www.abraxaspetroleum.com in the Investor Relations section as soon as practicable after such reports arefiled. Information on our web site is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing thatwe make with the SEC. Item 1A. Risk Factors Risks Related to Our BusinessDepressed oil and/or gas prices would have a material and adverse effect on us.Our financial results and the value of our properties are highly dependent on the general supply and demand for oil, gas and NGL, which impact theprices we ultimately realize on our sales of these commodities. Since the second half of 2014, there has been a significant decline in oil, gas and NGL prices,which adversely affected our 2015 and 2016 operating results and contributed to a reduction in our anticipated future capital expenditures. In addition, thisdecline in commodity prices adversely impacted our estimated proved reserves and resulted in a proved property impairment of $128.6 million to our oil andgas properties during 2015 and $67.6 million in 2016. We could record impairments in future periods, the amount of which will be dependent upon manyfactors such as future prices of oil, gas and NGL, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and gas propertyacquisitions.While oil and gas prices improved in late 2016, they have remained relatively low. A sustained weakness or further deterioration in commodity pricescould materially and adversely impact our business by resulting in, or exacerbating, the following effects:•reducing the amount of oil, gas and NGL that we can produce economically;•reducing the borrowing base of our credit facility;•limiting our financial flexibility, liquidity and access to sources of capital, such as equity and debt;•reducing our revenues, operating cash flows and profitability;•causing us to decrease our capital expenditures or maintain reduced capital spending for an extended period, resulting in lower future production ofoil, gas and NGL; and•reducing the carrying value of our properties, resulting in additional noncash write-downs.Market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control.These factors include:•the level of demand;•domestic and global supplies of oil, NGL and gas;•the price and quantity of imported and exported oil, NGL and gas;•the actions of other oil exporting nations;•weather conditions and changes in weather patterns;•the availability, proximity and capacity of appropriate transportation facilities, gathering, processing and compression facilities, storage facilitiesand refining facilities;•worldwide economic and political conditions, including political instability or armed conflict in oil and gas producing regions, competition formarkets and political initiatives disfavoring fossil fuels;•the price and availability of, and demand for, competing energy sources, including alternative energy sources;•the nature and extent of governmental regulation, including environmental regulation, regulation of derivatives transactions and hedging activities,tax laws and regulations and laws and regulations with respect to the import and export of oil, gas and related commodities;15Table of Contents•the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others, and;•the effect of worldwide energy conservation measures.Our cash flows from operations, the results of operations and the borrowing base under our credit facility depend to a great extent on the prevailing prices foroil and gas. Prolonged or substantial declines in oil and/or gas prices would materially and adversely affect our liquidity, the amount of cash flows we haveavailable for our capital expenditures and other operating expenses, our ability to access the credit and capital markets and our results of operations.Any significant reduction in the borrowing base under our credit facility as a result of a periodic borrowing base redetermination or otherwise willnegatively impact our liquidity and, consequently, our ability to fund our operations, and we may not have sufficient funds to repay borrowings under ourcredit facility or any other obligation if required as a result of a borrowing base redeterminationAvailability under our credit facility is currently subject to a borrowing base of $115.0 million. The borrowing base is subject to scheduled semiannual(April 1 and October 1) and other elective borrowing base redeterminations. The amount of the borrowing base is calculated by the lenders based upon theirvaluation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. The lenders under our credit facility canunilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. A number of factors could reduce ourborrowing base, including:•lower commodity prices or production;•a reduction in reserve estimates;•inability to drill or unfavorable drilling results;•increased operating and/or capital costs;•the lenders’ inability to agree to an adequate borrowing base; or•adverse changes in the lenders’ practices (including required regulatory changes) regarding estimation of reserves.As of March 10, 2017, we had $18.0 million of borrowings outstanding under our credit facility and availability of $97.0 million. Any significantreduction in our borrowing base as a result of borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund ouroperations and, as a result, would have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstandingborrowings under our credit facility were to exceed the borrowing base as a result of redetermination, we would be required to repay the excess amount orpledge additional assets. We may not have sufficient funds to make such repayment and we do not have any substantial unpledged assets. If we do not havesufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Anysuch sale could have a material adverse effect on our business and financial results.Lower oil and/or gas prices may also reduce the amount of oil and/or gas that we can produce economically.Sustained substantial declines in oil and/or gas prices may render uneconomic a significant portion of our exploration, development and exploitationprojects, which may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a prolonged or substantialdecline in oil and/or gas prices such as we have experienced since mid-2014 caused, and would likely in the future cause, a material and adverse effect on ourfuture business, financial condition, results of operations, liquidity and ability to finance capital expenditures. Additionally, if we experience significantsustained decreases in oil and gas prices such that the expected future cash flows from our oil and gas properties falls below the net book value of ourproperties, we may be required to write down the value of our oil and gas properties. Any such asset impairments could materially and adversely affect ourresults of operations and, in turn, the trading price of our common stock.We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.We must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have financed our capitalexpenditures primarily with cash flow from operations, borrowings under credit facilities, sales of properties, monetizing derivative contracts and sales ofdebt and equity securities and we expect to continue to utilize these sources in the future. We cannot assure you that we will have sufficient capital resourcesin the future to finance all of our planned capital expenditures.16Table of ContentsVolatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/orlower production could also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements,including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of capitalexpenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our capital expenditureswould, by necessity, be decreased.The borrowing base under our credit facility is determined from time to time by the lenders. Reductions in estimates of oil and gas reserves could resultin a reduction in the borrowing base, which would reduce the amount of financial resources available under our credit facility to meet our capitalrequirements and/or trigger certain repayment obligations. Such a reduction could be the result of lower commodity prices and/or production, an inability todrill or unfavorable drilling results, changes in oil and gas reserve engineering, the lenders’ inability to agree to an adequate borrowing base or adversechanges in the lenders’ practices regarding estimation of reserves.If cash flows from operations or our borrowing base decrease, our ability to undertake exploration and development activities could be adverselyaffected. As a result, our ability to replace production may be limited. In addition, if the borrowing base under our credit facility is reduced, we would berequired to reduce borrowings under our credit facility so that such borrowings do not exceed the borrowing base. This could further reduce the cashavailable to us for capital spending and, if we did not have sufficient capital to reduce our borrowing level, we may be in default under the credit facility.We have sold producing properties to provide us with liquidity and capital resources in the past and we may continue to do so in the future. After anysuch sale, we would expect to utilize the proceeds to reduce our indebtedness and/or to drill new wells on our remaining properties. If we cannot replace theproduction from the properties sold with production from our remaining properties, our cash flows from operations will likely decrease, which in turn, coulddecrease the amount of cash available for additional capital spending.We have indebtedness which may adversely affect our cash flow and business operations.At December 31, 2016, we had a total of $93.0 million of indebtedness under our credit facility and total indebtedness of $97.4 million (including thecurrent portion). While the amount borrowed under our credit facility at March 10, 2017 was $18.0 million (and total indebtedness was $21.8 million), thisamount will likely increase as we pursue drilling and completion of wells. Our indebtedness could have important consequences to us, including:•affecting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes which maybe impaired or not available on favorable terms or at all;•covenants contained in our credit facility and future debt arrangements will require us to meet financial tests that may affect our flexibility inplanning for and reacting to changes in our business, including future business opportunities;•a substantial portion of our cash flow from operations will be used to make principal and interest payments on our indebtedness, reducing the fundsthat would otherwise be available for operations and future business opportunities; and•making us more vulnerable to competitive pressures if there is a downturn in our business or the economy in general, than our competitors with lessdebt.Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected byprevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are notsufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying capital expenditures, acquisitionsand/or selling assets, restructuring or refinancing our indebtedness or seeking additional debt or equity capital or bankruptcy protection. We may not be ableto effect any of these remedies on satisfactory terms or at all.A breach of the terms and conditions of our credit facility, including borrowings in excess of the borrowing base or the inability to comply with therequired financial covenants, could result in an event of default. If an event of default occurs (after any applicable notice and cure periods), the lenders wouldbe entitled to terminate any commitment to make further extensions of credit under our credit facility and to accelerate the repayment of amounts outstanding(including accrued and unpaid interest and fees). Upon a default under our credit facility, the lenders could also foreclose against any collateral securingsuch obligations, which may be all or substantially all of our assets. If that occurred, we may not be able to continue to operate as a going concern.17Table of ContentsRestrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions andengage in other business activities that may be in our best interests.Our credit facility contains a number of significant covenants that, among other things, limit our ability to:•incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock;•transfer or sell assets;•create liens on assets;•pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capitalstock or subordinated debt or making certain investments or acquisitions;•engage in transactions with affiliates;•guarantee other indebtedness;•make any change in the principal nature of our business;•permit a change of control; or•consolidate, merge or transfer all or substantially all of our assets.In addition, our credit facility requires us to maintain compliance with specified financial covenants. Our ability to comply with these covenants may beadversely affected by events beyond our control, and we cannot assure you that we can maintain compliance with these covenants. These financialcovenants could limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy ingeneral or otherwise conduct necessary or desirable business activities. We are also required to use the proceeds from the termination of any derivativecontracts to repay outstanding amounts under the credit facility and to use any amount of cash on hand and liquid investments in excess of $10 million torepay outstanding amounts under the credit facility.A breach of any of these covenants could result in a default under our credit facility. A default, if not cured or waived, could result in all of ourindebtedness becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinanceit. Even if new financing were then available, it may not be on terms acceptable or favorable to us.Lower oil and gas prices increase the risk of ceiling limitation write-downs.We use the full cost method to account for our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop our oil andgas properties. Under full cost accounting rules, the net capitalized cost of our oil and gas properties may not exceed a “ceiling limit” which is based uponthe present value of estimated future net cash flows from our proved reserves, discounted at 10%. If the net capitalized costs of our oil and gas propertiesexceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This charge does not impactcash flow from operating activities, but it does reduce our stockholders’ equity and earnings. The risk that we will be required to write-down the carryingvalue of our oil and gas properties increases when oil and gas prices are low, which could be further impacted by the SEC’s modernized oil and gas reportingdisclosures, which require us to use an average price over the prior 12-month period, rather than the year-end price, when calculating the PV-10. In addition,write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not bereversed in a subsequent period even though oil and gas prices may have increased the ceiling applicable in the subsequent period.At December 31, 2015, the net capitalized costs of our oil and gas properties exceeded the present value of our proved reserves, resulting in recognitionof impairments totaling $128.6 million. During 2016 we recognized additional impairments of $67.6 million. If commodity prices decrease in the future, wewould likely be required to record further write downs.An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow fromoperations.Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oiland gas are typically lower than the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we receive iscalled a differential. Numerous factors may influence local pricing, such as refinery capacity, location to market, product quality, pipeline capacity andspecifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Additionally, insufficientpipeline capacity, lack of demand18Table of Contentsin any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example,production increases from competing Canadian and Rocky Mountain producers, combined with limited refining and pipeline capacity in the RockyMountain area, have gradually widened differentials in this area. In addition, we have a contract related to certain gas and NGL in the Rocky MountainRegion, that if certain margins of gas and NGL prices are not met by the purchaser, we receive no sales proceeds.During 2016, our differentials averaged $(6.33) per Bbl of oil and $(1.29) per Mcf of gas. Approximately 81% of our oil and NGL production during2016 was from the Rocky Mountain region. Historically, this region has experienced wider differentials than our Permian/Delaware Basin and South Texasproperties. If the percentage of our production from the Rocky Mountain region continues to increase, we expect that the effect of our price differentials onour revenues will also increase. Increases in the differential between the benchmark prices for oil and gas and the realized price we receive couldsignificantly reduce our revenues and our cash flow from operations.Our derivative contracts could result in financial losses or could reduce our cash flow.To achieve more predictable cash flow and reduce our exposure to adverse fluctuations in the prices of oil and gas, we enter into derivative contracts,which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealizedderivative contract losses. We have entered into NYMEX-based fixed price commodity swap arrangements on approximately 70% of the oil production fromour estimated net proved developed producing reserves (as of December 31, 2016) through December 31, 2017, 77% for 2018 and 64% for 2019. We havealso entered into a NYMEX-based collar on approximately 56% of the gas production from our estimated net proved developed producing reserves (as ofDecember 31, 2016) through December 31, 2017 and a 500 Bopd Midland-Cushing oil price differential swap at ($0.65)/Bbl. These arrangements may beinadequate to protect us from declines in oil and gas prices. Any new hedging arrangements will be priced at then-current market prices and may besignificantly lower than the commodity swaps we currently have in place. The extent of our commodity price exposure will be related largely to theeffectiveness and scope of our commodity price derivative contracts. For example, the prices utilized in our derivative contracts are currently NYMEX-based,which may differ significantly from the actual prices we receive for oil and gas which are based on the local markets where the oil and gas is produced. Theprices that we receive for our oil and gas production are typically lower than the relevant benchmark prices that are used for calculating commodityderivative positions. The difference between the benchmark price and the price we receive is called a differential, a significant portion of which is based onthe delivery location which is called the basis differential. As a result, our cash flow from operations could be affected if the basis differentials widen morethan we anticipate. Our cash flow from operations could also be affected based upon the levels of our production. If production is higher than we estimate, wewill have greater commodity price exposure than we intended. If production is lower than the nominal amount that is subject to our hedging arrangements,we may be forced to satisfy all or a portion of our hedging arrangements without the benefit of the cash flow from our sale of the underlying physicalcommodity, resulting in a substantial reduction in cash flows.If the prices at which we hedge our oil and gas production are less than current market prices, our cash flow opportunity from operations could beadversely affected.When our derivative contract prices are higher than market prices, we will incur realized and unrealized gains on our derivative contracts and conversely,when our contract prices are lower than market prices, we will incur realized and unrealized losses. For the year ended December 31, 2016, we recognized arealized gain on oil and gas derivative contracts of $1.8 million and an unrealized loss of $19.8 million. The realized gain resulted in an increase in cash flowfrom operations. We expect to continue to enter into similar hedging arrangements in the future to reduce our cash flow volatility.We cannot assure you that the derivative contracts that we have entered into, or will enter into, will adequately protect us from financial loss in the futuredue to circumstances such as:•highly volatile oil and gas prices;•our production being less than expected; or•a counterparty to one of our hedging transactions defaulting on its contractual obligations.The counterparties to our derivative contracts may be unable to perform their obligations to us which could adversely affect our cash flow.At times when market prices are lower than our derivative contract prices, we are entitled to cash payments from the counterparties to our derivativecontracts. Any number of factors may adversely affect the ability of our counterparties to fulfill19Table of Contentstheir contractual obligations to us. If one of our counterparties is unable or unwilling to make the required payments to us, it could adversely affect our cashflow.The Company's expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materiallyalter the occurrence or timing of such activities.The Company has identified drilling locations and prospects for future drilling opportunities, including development and exploratory drillingactivities. These drilling locations and prospects represent a significant part of the Company's future drilling plans. For example, the Company's provedreserves as of December 31, 2016 include proved undeveloped reserves and proved developed reserves that are behind pipe of 16,976 MBbls ofoil, 6,137 MBbls of NGLs and 45,597 MMcf of gas. The Company's ability to drill and develop these locations depends on a number of factors, including theavailability of capital, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment,services, resources and personnel and drilling results. There can be no assurance that the Company will drill these locations or that the Company will be ableto produce oil or gas reserves from these locations or any other potential drilling locations. Changes in the laws or regulations on which the Company reliesin planning and executing its drilling programs could adversely impact the Company's ability to successfully complete those programs. For example, undercurrent Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or moreunits and/or leases; a change in those laws or regulations could adversely impact the Company's ability to drill those wells. Because of these uncertainties,the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet theCompany's expectations for success. As such, the Company's actual drilling activities may materially differ from the Company's current expectations, whichcould have a significant adverse effect on the Company's proved reserves, financial condition and results of operations.A significant portion of the Company's total estimated proved reserves at December 31, 2016 were undeveloped, and those proved reserves may notultimately be developed.At December 31, 2016, approximately 66% of the Company's total estimated proved reserves on a Boe basis (33% on a PV-10 basis) wereundeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling. The Company's reserve dataassumes that the Company can and will make these expenditures and conduct these operations successfully, which assumptions may not prove correct. If theCompany chooses not to spend the capital to develop these proved undeveloped reserves, or if the Company is not otherwise able to successfully developthese proved undeveloped reserves, the Company will be required to write-off these reserves. In addition, under the SEC's rules, because proved undevelopedreserves may be booked only if they relate to wells planned to be drilled within five years of the date of booking, the Company may be required to write-offany proved undeveloped reserves that are not developed within this five-year timeframe. As with all oil and gas leases, the Company's leases require theCompany to drill wells that are commercially productive and to maintain the production in paying quantities, and if the Company is unsuccessful in drillingsuch wells and maintaining such production, the Company could lose its rights under such leases. The Company's future production levels and, therefore, itsfuture cash flow and income are highly dependent on successfully developing its proved undeveloped leasehold acreage.We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected. Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves thatare profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced. Unless weacquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identifyadditional behind-pipe zones or secondary recovery reserves, we cannot assure you that our exploration and development activities will result in increases inour proved reserves. Based on the reserve information set forth in our reserve report as of December 31, 2016, our average annual estimated decline rate forour net proved developed producing reserves is 40%; 15%; 12%; 11% and 9% in 2018, 2019, 2020, 2021 and 2022, respectively, 9% in the following fiveyears, and approximately 9% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While we have hadsome success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost fromnatural field declines and prior property sales. As our proved reserves and consequently our production decline, our cash flow from operations, and theamount that we are able to borrow under our credit facility could also decline. In addition, approximately 66% of our total estimated proved reserves on aBoe basis (33% on a PV-10 basis) at December 31, 2016 were classified as undeveloped. By their nature, estimates of undeveloped reserves are lesscertain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Even if we are successful in ourdevelopment efforts, it could take several years for a significant portion of these undeveloped reserves to generate positive cash flow.We may not find any commercially productive oil and gas reservoirs.20Table of Contents Drilling involves numerous risks, including the risk that the new wells we drill will be unproductive or that we will not recover all or any portion of ourcapital investment. Drilling for oil and gas may be unprofitable. Wells that are productive but do not produce sufficient net revenues after drilling, operatingand other costs are unprofitable. The inherent risk of not finding commercially productive reservoirs is compounded by the fact that 66% of our totalestimated proved reserves on a Boe basis (33% on a PV-10 basis) as of December 31, 2016 were classified as undeveloped. By their nature, estimates ofundeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and completionoperations. In addition, our properties may be susceptible to drainage from production by other operations on adjacent properties. If the volume of oil andgas we produce decreases, our cash flow from operations may decrease.The results of our drilling in unconventional formations, principally in emerging plays with limited drilling and production history using long laterals andmodern completion techniques, are subject to more uncertainties than our drilling program in the more established plays and may not meet ourexpectations for reserves or production. We drill wells in unconventional formations in several emerging plays. Part of our drilling strategy to maximize recoveries from these formationsinvolves the drilling of long horizontal laterals and the use of modern completion techniques of multi-stage fracture stimulations that have proven to besuccessful in other basins. Risks that we face include landing our well bore in the desired drilling zone, staying in the desired drilling zone, running casingthe entire length of the well bore and being able to run tools and recover equipment the entire length of the well bore during completion. Our experience withhorizontal drilling and multi-stage fracture stimulations of these formations to date, as well as the industry’s drilling and production history in theseformations, is relatively limited. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as morewells are drilled and longer term production profiles are established. In addition, based on reported decline rates in these emerging plays as well as theindustry’s experience in these formations, we estimate that the average monthly rates of production may decline as much as 95% during the first twelvemonths of production. Actual decline rates may differ significantly. Accordingly, the results of our drilling in these unconventional formations are moreuncertain than drilling results in other more established plays with longer reserve and production histories.We may not be able to keep pace with technological developments in our industry.The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using newtechnologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us toimplement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resourcesthat allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able torespond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we usenow or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financialcondition and results of operations could be materially adversely affected.We may not adhere to our proposed drilling schedule. Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:•prevailing and anticipated prices for oil and gas;•the availability and costs of drilling and service equipment and crews;•economic and industry conditions at the time of drilling;•the availability of sufficient capital resources;•the results of our exploitation efforts;•the acquisition, review and interpretation of seismic data;•our ability to obtain permits for and to access drilling locations;•continuous drilling obligations; and•lease expirations.Although we have identified or budgeted for numerous drilling locations, we may not be able to drill those locations within our expected time frame orat all. In addition, our drilling schedule may vary from our expectations because of future uncertainties.21Table of ContentsWe cannot control the activities on the properties we do not operate and are unable to ensure their proper operation and profitability. We currently do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over and controlthe risks associated with operation of these properties. The failure of an operator to adequately perform operations, an operator’s breach of the applicableagreements or an operator’s failure to act in our best interests could reduce our production and revenues. The success and timing of our drilling anddevelopment activities on properties operated by others therefore depends upon a number of factors outside of our control, including:•the operator could refuse to initiate exploitation or development projects and if we proceed with any of those projects, we may not receive anyfunding from the operator with respect to that project;•the operator may initiate exploitation or development projects on a different schedule than we would prefer;•the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a projectthan we have funds for, which may mean that we cannot participate in those projects and thus, not participate in the associated revenue stream; and•the operator may not have sufficient expertise or resources.Any of these events could significantly and adversely affect our anticipated exploitation and development activities.Seasonal weather conditions and other factors could adversely affect our ability to conduct drilling activities. Our operations could be adversely affected by weather conditions and wildlife restrictions on federal leases. In the Williston and the Powder RiverBasins, drilling and other oil and gas activities cannot be conducted as efficiently during the winter and spring months. Winter and severe weather conditionslimit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay ortemporarily halt our oil and gas operations and materially increase our operating and capital costs, which could have a material adverse effect on ourbusiness, financial condition and results of operations.The lack of availability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute ourexploitation and development plans on a timely basis and within our budget. Our industry is cyclical and, from time to time, there has been a shortage of drilling rigs, equipment, supplies, oil field services or qualified personnel.During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of,qualified drilling rig crews rise as the number of active rigs in service increases. During times and in areas of increased activity, the demand for oilfieldservices will also likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability orhigh cost of drilling rigs, equipment, supplies, oil field services or qualified personnel were particularly severe in any of our areas of operation, we could bematerially and adversely affected. Delays could also have an adverse effect on our results of operations, including the timing of the initiation of productionfrom new wells.Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors that are beyond our control. Our drilling operations are subject to a number of risks, including:•unexpected drilling conditions;•facility or equipment failure or accidents;•adverse weather conditions;•title problems;•unusual or unexpected geological formations;•fires, blowouts and explosions; and•uncontrollable pressures or flows of oil or gas or well fluids.22Table of ContentsAny of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damageto or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties,suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.We do not insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsuredor underinsured risks related to our oil and gas operations. We do not insure against all risks. Our oil and gas exploitation and production activities are subject to hazards and risks associated with drilling for,producing and transporting oil and gas, and any of these risks can cause substantial losses resulting from:•environmental hazards, such as uncontrollable flows of oil, gas, brine, well fluids, toxic gas or other pollution into the environment, includinggroundwater, shoreline contamination, underground migration and surface spills or mishandling of chemical additives;•abnormally pressured formations;•mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;•leaks of gas, oil, condensate, NGL and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completionoperations, or in the gathering and transportation of hydrocarbons, malfunctions of pipelines, measurement equipment or processing or other facilitiesin the Company’s operations or at delivery points to third parties;•fires and explosions;•personal injuries and death;•regulatory investigations and penalties; and•natural disasters.We might elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition,pollution and environmental risks generally are not fully insurable. Losses and liabilities arising from uninsured and underinsured events or in amounts inexcess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations. Hydraulic fracturing, the process used for extracting oil and gas from shale and other formations, has recently come under increased scrutiny and could bethe subject of further regulation that could impact the timing and cost of development. Hydraulic fracturing is the primary completion method used to extract reserves located in many of the unconventional oil and gas plays. Hydraulicfracturing involves the injection of water, sand and chemicals under pressure, usually down tubing or casing that is cemented in the wellbore, intohydrocarbon-bearing formations at depth to stimulate oil and gas production. We use this completion technique on substantially all of our wells. Dependingon the legislation that may ultimately be enacted or the regulations that may be adopted at the federal and state levels, exploration, exploitation andproduction activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Some states in which we operate,including Texas, have recently implemented disclosure requirements related to chemicals used in hydraulic fracturing, and the U.S. Department of theInterior, Bureau of Land Management (“BLM”) has adopted final rules governing hydraulic fracturing on federal and tribal lands, including requiringchemical disclosure. The BLM's rules have been struck down by a federal court, but that ruling is now on appeal to the Tenth Circuit Court of Appeals.Individually or collectively, such existing and new legislation or regulation could lead to operational delays or increased operating costs and could result inadditional burdens that could increase the costs and delay the development of unconventional oil and gas resources from formations which are notcommercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.Hydraulic fracturing is typically regulated by state oil and gas commissions; however, the EPA has asserted federal regulatory authority over hydraulicfracturing involving diesel fuels under the Underground Injection Control Program established under the Safe Drinking Water Act, or SDWA, and publishedpermitting guidance and an interpretive memorandum addressing the performance of such activities. In August 2012, the EPA published final rules under theCAA, which became effective October 15, 2012, that, among other things, require producers to reduce volatile organic compound emissions from certainsubcategories of fractured and refractured gas wells for which well completion operations are being conducted by routing flowback emissions23Table of Contentsto a gathering line or capturing and combusting flowback emissions using a combustion device, such as a flare, until January 1, 2015 or performing reducedemission completions, also known as “green completions,” with or without combustion devices, on or after January 1, 2015. In addition, the U.S. Congress,from time to time, has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of thechemicals used in the hydraulic-fracturing process. Moreover, the BLM has adopted final rules that impose more stringent technical requirements and thedisclosure of chemicals used in hydraulic fracturing operations on public and Native American lands. These rules are currently under judicial challenge. Inthe event that a new federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we currently or in the future plan tooperate, we may incur additional costs to comply with such federal requirements that may be significant in nature, become subject to additional permittingrequirements and experience added delays or curtailment in the pursuit of exploration, development or production activities.Certain states in which we operate, including Texas, have adopted, and other states are considering adopting, regulations that could impose new or morestringent permitting, disclosures, and/or well-construction requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011requiring disclosure to the Texas Railroad Commission and the public disclosure of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulicfracturing in particular. In some states, including Texas, water use may also be regulated and potentially curtailed by local groundwater management districtswhich could impact water available for hydraulic fracturing. We believe that we follow applicable standard industry practices and legal requirements forgroundwater protection in our hydraulic fracturing activities. Nonetheless, in the event state or local restrictions are adopted in areas where we are currentlyconducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature,experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling ofwells or in the amounts that we are ultimately able to produce from our reserves.Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. InDecember 2016 the EPA issued its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking WaterResources in the United States” which assessed the potential impact of hydraulic fracturing on drinking water resources. The report acknowledged data gapsand uncertainties, removed the draft finding of no widespread systemic impacts from hydraulic fracturing, but concluded that the agency could not quantifythe frequency or severity of such impacts on a national level, thereby leaving the door open to additional regulations to protect drinking water resources.Moreover, the EPA has adopted pre-treatment standards addressing the discharge of wastewater pollutants from hydraulic fracturing operations to publiclyowned treatment works. The EPA is also conducting a study of private wastewater treatment facilities that accept oil and gas extraction wastewater. Othergovernmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulicfracturing. These studies, or future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to furtherregulate hydraulic fracturing under the SDWA or other regulatory mechanisms. See “Item 1. Business – Environmental Matters – Hydraulic Fracturing”above for additional discussion related to environmental risks associated with our hydraulic fracturing activities.Studies noting a connection between increased seismic activity and the injection of wastewater from oil and gas operations could result in new laws orregulations which would increase our cost of operations.Some studies have noted an increase in localized frequency of seismic activity associated with underground disposal of wastewater from oil and gasoperations. If the results of these studies are confirmed, new legislative and regulatory initiatives could require additional monitoring, restrict the injection ofproduced water in certain disposal wells or modify or curtail hydraulic fracturing operations. These actions could lead to operational delays, increasedcompliance costs or otherwise adversely impact our operations.We face various risks associated with the trend toward increased anti-development activity.As new technologies have been applied to our industry, we have seen significant growth in oil and gas supply in recent years, particularly in the U.S.With this expansion of oil and gas development activity, opposition toward oil and gas drilling and development activity has been growing both in the U.S.and globally. Companies in the oil and gas industry, such as us, can be the target of opposition to development from certain stakeholder groups. These anti-development efforts could be focused on:•limiting oil and gas development;•reducing access to federal and state owned lands;•delaying or canceling certain projects such as offshore drilling, shale development, and pipeline construction;24Table of Contents•limiting or banning the use of hydraulic fracturing;•denying air-quality permits for drilling; and•advocating for increased regulations on shale drilling and hydraulic fracturing.Future anti-development efforts could result in the following:•blocked development;•denial or delay of drilling permits;•shortening of lease terms or reduction in lease size;•restrictions on installation or operation of gathering or processing facilities;•restrictions on the use of certain operating practices, such as hydraulic fracturing;•reduced access to water supplies or restrictions on water disposal;•limited access or damage to or destruction of our property;•legal challenges or lawsuits;•increased regulation of our business;•damaging publicity and reputational harm;•increased costs of doing business;•reduction in demand for our products; and•other adverse effects on our ability to develop our properties and expand production.Our need to incur costs associated with responding to these initiatives or complying with any new legal or regulatory requirements resulting fromthese activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results ofoperations. In addition, the use of social media channels can be used to cause rapid, widespread reputational harm.The marketability of our production depends largely upon the availability, proximity and capacity of oil and gas gathering systems, pipelines, storage andprocessing facilities. The marketability of our production depends in part upon processing, storage and transportation facilities. Transportation space on such gatheringsystems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such spacebeing utilized by other companies with priority transportation agreements. Our access to transportation options can also be affected by federal and state,regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availabilityof markets are beyond our control. If our access to these transportation and storage options dramatically changes, the financial impact on us could besubstantial and adversely affect our ability to produce and market our oil and gas.The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risksassociated with our business. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter, or OTC, derivatives and requires the Commodity Futures Trading Commission, or CFTC, and the SEC to enact further regulations affectingderivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and theSEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to befinalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, on November 5, 2013 (as modified and re-proposed on December 30,2016), the CFTC approved a proposed rule imposing position limits for certain futures and option contracts in various25Table of Contentscommodities (including gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are proposed to be exemptfrom these position limits, provided that such hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions.Similarly, on December 16, 2016, the CFTC issued a proposed rule regarding the capital that a swap dealer, or major swap participant, is required to post withrespect to its swap business, but has not yet issued a final rule. On January 6, 2016, the CFTC issued a final rule on margin requirements for uncleared swaptransactions, which includes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting theirbusiness, from any requirement to post margin to secure such swap transactions. In addition, on July 19, 2012, the CFTC issued a final rule authorizing anexception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-FrankAct to clear all swap transactions through a registered derivatives clearing organization and to trade all such swaps on a registered exchange. The Dodd-FrankAct also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of theabove regulations and requirements could increase the costs to us of entering into derivative contracts to hedge or mitigate our exposure to volatility in oil,gas and NGL prices and other commercial risks affecting our business.While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending onour ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate itscommercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements inconnection with our derivative activities. In addition, The Dodd-Frank Act may require our current counterparties to post additional capital as a result ofentering into uncleared derivative contracts with us, which could increase the cost to us of entering into such derivative contracts. When a final rule oncapital requirements is issued, the Dodd-Frank Act may require our current swap counterparties to post additional capital as a result of entering into unclearedderivatives with us, which could increase our costs of future derivative transactions. The Dodd-Frank Act may also require our current counterparties to spinoff some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities tocease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability ofcommercial end-users to have access to derivative contracts to hedge or mitigate their exposure to volatility in oil, gas and NGL prices. The Dodd-Frank Actand any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which couldadversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existingbilaterally negotiated derivative contracts, and reduce the availability of derivatives to protect us against commercial risks we encounter.In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel IIIAccord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirementson financial institutions active in physical commodities, such as oil and gas. If and when these proposed regulations are fully implemented, financialinstitutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under thefinancial derivatives and other contracts we may enter into with such financial institutions in order to reduce the amount of capital such financial institutionsmay have to maintain. Alternatively, financial institutions subject to these capital requirements may price transactions so that we will have to pay a premiumto enter into derivatives and other physical commodity transactions in an amount that will compensate the financial institutions for the additional capitalcosts relating to such derivatives and physical commodity transactions. Rules implementing the Basel III Accord and higher risk-weighted capitalrequirements could materially reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including throughrequirements to post collateral, which could adversely affect our available capital for other commercial operations purposes).If we reduce our use of derivative contracts as a result of any of the foregoing regulations or requirements, our results of operations may become morevolatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation wasintended, in part, to reduce the volatility of oil, gas, and NGL prices, which some legislators attributed to speculative trading in derivatives and commodityinstruments related to oil, gas, and NGLs. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lowercommodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations, or cash flows.If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change tooffset future taxable income. In addition, our ability to use net operating loss carry forwards to reduce future tax payments may be limited if our taxableincome does not reach sufficient levels.As of December 31, 2016, we had a net operating loss ("NOL") carryforward for federal income tax purposes of $230.5 million. If we were to experiencean "ownership change," as determined under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), our ability to offset taxable incomearising after the ownership change with NOLs arising prior to the ownership change would be limited, possibly substantially. An ownership change wouldestablish an annual limitation on the amount of our pre-change NOL we could utilize to offset our taxable income in any future taxable year to an amountgenerally26Table of Contentsequal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change willoccur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more "5% shareholders" (as defined in the Code) at anytime during a rolling three-year period. In addition, under the Code, NOL can generally be carried forward to offset future taxable income for a period of 20years. Our ability to use our NOL during this period will be dependent on our ability to generate taxable income, and the NOL could expire before wegenerate sufficient taxable income.Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. Wedepend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drillinginformation, and communicate with our employees and third-party partners. Unauthorized access to our seismic data, reserves information or otherproprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or productionoperations. In addition, computer technology controls nearly all of the oil and gas distribution systems in the United States and abroad, which are necessaryto transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or theenvironment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settletransactions.While we have not experienced significant cyber attacks, we may suffer such attacks in the future. Further, as cyber attacks continue to evolve, we maybe required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate anyvulnerability to cyber attacks. We rely on independent experts and technical or operational service providers over whom we may have limited control. We use independent contractors to provide us with certain technical assistance and services. We rely upon the owners and operators of rigs and drillingequipment, and upon providers of field services, to drill and develop our prospects to production. We also rely upon the services of other third parties toexplore and/or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control overthe activities and business practices of these service providers, any inability on our part to maintain satisfactory commercial relationships with them or theirfailure to provide quality services could materially adversely affect our business, results of operations and financial condition.We depend on our President, CEO and Chairman of the Board and the loss of his services could have an adverse effect on our operations. We depend to a large extent on Robert L.G. Watson, our President and Chief Executive Officer, for our management and business and financialcontacts. Mr. Watson may terminate his employment agreement with us at any time on 30 days' notice, but, if he terminates without good reason, he wouldnot be entitled to the severance benefits provided under the terms of that agreement. Mr. Watson is not precluded from working for, with or on behalf of acompetitor upon termination of his employment with us. If Mr. Watson were no longer able or willing to act as President, Chief Executive Officer andChairman of the Board, the loss of his services could have an adverse effect on our operations.Risks Related to Our Industry Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows, profitability andgrowth. Our revenue, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and gas. Prices also affect the amountof cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also make it uneconomical forus to increase or even continue current production levels of oil and gas.Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, marketuncertainty and a variety of other factors beyond our control, including:•changes in foreign and domestic supply and demand for oil and gas;•political stability and economic conditions in oil producing countries, particularly in the Middle East;•weather conditions;•price and level of foreign imports;•terrorist activity;27Table of Contents•availability of pipeline and other secondary capacity;•general economic conditions;•domestic and foreign governmental regulation; and•the price and availability of alternative fuel sources.Estimates of proved reserves and future net revenue are inherently imprecise. The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions in evaluatingthe available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gasprices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from thoseestimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates ofproved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which arebeyond our control.The estimates of our reserves as of December 31, 2016 are based upon various assumptions about future production levels, prices and costs that may notprove to be correct over time. In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the PV-10 thereof for our oil and gasproperties are based on the assumption that future oil and gas prices remain the same as the twelve month first-day-of-the-month average oil and gas prices forthe year ended December 31, 2016. The average realized sales prices as of such date used for purposes of such estimates were $1.41per Mcf of gas and $35.54per Bbl of oil. The December 31, 2016 estimates also assume that we will make future capital expenditures of approximately $267.8 million in the aggregateprimarily from 2017 through 2021, which are necessary to develop and realize the value of proved reserves on our properties. We cannot assure you that wewill have sufficient capital in the future to make these capital expenditures. In addition, approximately 66% of our total estimated proved reserves on a Boebasis (33% on a PV-10 basis) as of December 31, 2016 were classified as undeveloped. By their nature, estimates of undeveloped reserves are less certainthan proved developed reserves. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity andvalue of our reserves set forth or incorporated by reference in this report.The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. Anymaterial inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, whichcould adversely affect our business, results of operations and financial condition.As required by SEC regulations, we based the estimated discounted future net cash flows from our proved reserves as of December 31, 2016 on the twelvemonth first-day-of-the-month average oil and gas prices for the year ended December 31, 2016 and costs in effect on December 31, 2016, the date of theestimate. However, actual future net cash flows from our properties will be affected by factors such as:•supply of and demand for our oil and gas; •actual prices we receive for our oil and gas; •our actual operating costs; •the amount and timing of our capital expenditures; •the amount and timing of our actual production; and •changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating discounted future net cash flow, which is required by the SEC, may not be the mostappropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Any materialinaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adverselyaffect our business, results of operations and financial condition. Our operations are subject to the numerous risks of oil and gas drilling and production activities. 28Table of ContentsOur oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the risk offire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil and salt waterspills, gas leaks, ruptures, discharges of toxic gases, underground migration and surface spills or mishandling of any toxic fracture fluids, including chemicaladditives. In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipmentcould negatively affect our operations. If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial lossesalso may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, environmental damage, regulatoryinvestigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risksdescribed above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availabilityof insurance at premium levels that justify its purchase.We operate in a highly competitive industry which may adversely affect our operations. We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leaseholdprospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnelto conduct all phases of operations. We must compete for such resources with both major oil and gas companies and independent operators. Many of thesecompetitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources areadequate to preclude any significant disruption of our operations, we cannot assure you that such resources will be available to us in the future.Our oil and gas operations are subject to various U.S. federal, state and local regulations that materially affect our operations. In the oil and gas industry, matters regulated include permits for drilling and completion operations, drilling and abandonment bonds, reportsconcerning operations, the spacing of wells and unitization and pooling of properties, the disposal of wastes and taxation. At various times, regulatoryagencies have imposed price controls and limitations on production. In order to conserve supplies of oil and gas, these agencies have at times restricted therates of flow from oil and gas wells below actual production capacity. U.S. federal, state and local laws regulate production, handling, storage, transportationand disposal of oil and gas by-products and other substances and materials produced or used in connection with oil and gas operations. To date, ourexpenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant. We believe thatwe are in substantial compliance with all applicable laws and regulations. However, the requirements of such laws and regulations are frequentlychanged. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.Proposed federal legislation concerning tax deductions currently available with respect to oil and gas drilling may adversely affect our net earnings. Congress has recently considered, is considering, and may continue to consider, legislation that, if adopted in its proposed or similar form, would deprivesome companies involved in oil and gas exploration and production activities in certain U.S. federal income tax incentives and deductions currentlyavailable to such companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii)the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic productionactivities and (iv) an extension of the amortization period for certain geological and geophysical expenditures.It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective and whether suchchanges may apply retroactively. Although we are unable to predict whether any of these or other proposals will ultimately be enacted, the passage of anylegislation as a result of these proposals or any other similar changes to U.S. federal income tax laws could eliminate or postpone certain tax deductions thatare currently available to us, and any such change could negatively affect our financial condition and results of operations.Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas. Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to thesestudies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission ofgreenhouse gases. Methane, a primary component of gas, and carbon dioxide, a by-product of the burning of oil, gas and refined petroleum products, areconsidered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change and the Kyoto Protocol address greenhouse gasemissions, and several countries including the European Union have established greenhouse gas regulatory systems. In December 2015, the U.S. participatedin the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France.29Table of ContentsThe Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. If ratified, theParis Agreement will take effect in 2020. It is possible that the Paris Agreement and subsequent domestic and international regulations will have adverseeffects on the market for oil, gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in theexploration for, and production of, oil, gas and other fossil fuel products. In the United States, at the state level, several states, either individually or throughmulti-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planneddevelopment of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatoryprograms. At the federal legislative level, various climate change legislative measures have been considered by the U.S. Congress, but it is not possible at thistime to predict when, or if, Congress will act on climate change legislation, although any major initiatives in this area are unlikely to become law in the nearfuture due to opposition in Congress. We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws,regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (ifenacted) could materially and adversely affect our operations, financial condition and results of operations.As a result of the U.S. Supreme Court decision in Massachusetts, et al. v. EPA, on December 7, 2009, the EPA issued a finding that serves as thefoundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act,even without Congressional action. As part of this array of new regulations, the EPA has issued a GHG monitoring and reporting rule that requires certainparties, including participants in the oil and gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to theEPA. These regulations may apply to our operations. The EPA has adopted other rules that would regulate GHGs, one of which would regulate GHGs fromstationary sources, and may affect sources in the oil and gas exploration and production industry and the pipeline industry. In May 2016, the EPA adoptedrules to force the aggregation of wells and facilities for air emission permitting purposes, and also rules to reduce methane emissions from equipment andleaks from new oil and gas facilities. The EPA’s finding, the greenhouse gas reporting rule, and the rules to regulate the emissions of greenhouse gases mayaffect the cost of our operations and also affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorableto our industry.Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating andcompliance costs, and could have an adverse effect on demand for the oil and gas that we produce and as a result, our financial condition and results ofoperations could be adversely affected.EPA’s new ground-level ozone standards may result in more stringent regulation of air emissions from, and adverse economic impacts on, our operations.Effective December 2015, the EPA adopted a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (NAAQS) forground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards designed to provide protection of publichealth and welfare, respectively. Certain areas of the country in compliance with the ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification may make it more difficult to construct new or modified sources of air pollution, including those associated with ouroperations, in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations necessary to come intocompliance with the new NAAQS, which could apply to our operations. Compliance with these final rules could, among other things, require installation ofnew emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operatingcosts.Proposed legislation and regulation under consideration regarding rail transportation could increase our operating costs, reduce our liquidity, delay ouroperations or otherwise alter the way we conduct our business.We presently sell all of our oil production at the lease, either by truck or pipeline, where custody transfers to the purchaser, accordingly it is unknown tous how much of the oil production is ultimately shipped by rail. In response to recent train derailments occurring in the United States, U.S. regulators areimplementing or considering new rules to address the safety risks of transporting oil by rail. On January 23, 2014, the NTSB issued a series ofrecommendations to address safety risks, including (i) requiring expanded hazardous material route planning for railroads to avoid populated and othersensitive areas, (ii) developing an audit program to ensure rail carriers that carry petroleum products have adequate response capabilities to address worst-casedischarges of the entire quantity of product carried on a train, and (iii) auditing shippers and rail carriers to ensure they are properly classifying hazardousmaterials in transportation and that they have adequate safety and security plans in place. Additionally, on February 25, 2014 the DOT issued an emergencyorder requiring all persons, prior to offering oil into transportation, to ensure such product is properly tested and classed and to assure all shipments by rail ofoil be handled as a Packing Group I or II hazardous material. The introduction of these or other regulations that result in new requirements addressing thetype, design, specifications or construction of rail cars used to transport oil could result in severe transportation capacity constraints during the period inwhich new rail cars are retrofitted or constructed to meet new specifications.30Table of ContentsWe do not currently own or operate rail transportation facilities or rail cars; however, the adoption of any regulations that impact the testing or railtransportation of oil could increase our costs of doing business and limit our ability to transport and sell our oil at favorable prices at market centersthroughout the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.Risks Related to Our Common Stock Future issuance of additional shares of common stock could cause dilution of ownership interests and adversely affect our stock price. We are currently authorized to issue 200,000,000 shares of common stock with such rights as determined by our board of directors. In the future, we mayincrease our authorized shares of common stock or issue previously authorized and unissued securities, resulting in the dilution of the ownership interests ofcurrent stockholders. The potential issuance of any such additional shares of common stock may create downward pressure on the trading price of ourcommon stock. We may also issue additional shares of common stock or other securities that are convertible into or exercisable for common stock for capitalraising or other business purposes. Future sales of substantial amounts of common stock, or the perception that sales could occur, could have a materialadverse effect on the price of our common stock.We will not pay dividends on our common stock for the foreseeable future. We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to paycash dividends in the foreseeable future. In addition, our credit facility prohibits us from paying dividends and making other cash distributions.Shares eligible for future sale may depress our stock price. At December 31, 2016, we had 135,094,017 shares of common stock outstanding (163,844,017 shares after the completion of the offering of 28.8 millionshares of common stock in January 2017) of which 9,891,194 shares were held by affiliates and, in addition, 8,153,775 shares of common stock were subjectto outstanding options granted under stock option plans (of which 4,808,263 shares were vested at December 31, 2016).All of the shares of common stock held by affiliates are restricted or are control securities under Rule 144 promulgated under the Securities Act. Theshares of common stock issuable upon exercise of stock options have been registered under the Securities Act. Sales of shares of common stock under Rule144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of our commonstock and could impair our ability to raise additional capital through the sale of equity securities.The price of our common stock has been volatile and could continue to fluctuate substantially. Our common stock is traded on The NASDAQ Stock Market. The market price of our common stock has been volatile and could fluctuate substantiallybased on a variety of factors, including the following:•fluctuations in commodity prices;•variations in results of operations;•legislative or regulatory changes;•general trends in the oil and gas industry;•sales of common stock or other actions by our stockholders;•additions or departures of key management personnel;•commencement of or involvement in litigation;•speculation in the press or investment community regarding our business;•an inability to maintain the listing of our common stock on a national securities exchange;•market conditions; and•analysts’ estimates and other events in the oil and gas industry.We may issue shares of preferred stock with greater rights than our common stock. 31Table of ContentsSubject to the rules of The NASDAQ Stock Market, our articles of incorporation authorize our board of directors to issue one or more series of preferredstock and set the terms of the preferred stock without seeking any further approval from holders of our common stock. Any preferred stock that is issued mayrank ahead of our common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than our common stock. Anti-takeover provisions could make a third party acquisition of us difficult. Our articles of incorporation and bylaws provide for a classified board of directors, with each member serving a three-year term, and eliminate the abilityof stockholders to call special meetings or take action by written consent. Each of the provisions in our articles of incorporation and bylaws could make itmore difficult for a third party to acquire us without the approval of our board. In addition, the Nevada corporate statute also contains certain provisions thatcould make an acquisition by a third party more difficult.Item 1B. Unresolved Staff Comments None. Item 2. Properties Exploratory and Developmental Acreage Our principal oil and gas properties consist of producing and non-producing oil and gas leases, including reserves of oil and gas in place. The followingtable sets forth our developed and undeveloped acreage and fee mineral acreage as of December 31, 2016. DevelopedAcreage Undeveloped Acreage Fee MineralAcreage (1) GrossAcres NetAcres GrossAcres NetAcres GrossAcres NetAcres TotalNetAcres (2)Rocky Mountain 30,978 16,767 20,407 11,361 3,078 346 28,474Permian/Delaware Basin 15,945 13,392 10,432 8,010 12,008 5,272 26,673South Texas 7,958 7,476 5,010 4,890 2,939 872 13,238Total 54,881 37,635 35,849 24,261 18,025 6,490 68,385____________________________(1)Fee mineral acreage represents fee simple absolute ownership of the mineral estate or fraction thereof.(2)Includes 1,217 net acres in the Permian Basin region that are included in both developed and fee mineral acres.The following table sets forth Abraxas’ net undeveloped acreage subject to expire by year: 20172018201920202021Rocky Mountain—6473426—Permian/Delaware Basin9———704South Texas1,9423591,27010013 Productive Wells The following table sets forth our gross and net productive wells, expressed separately for oil and gas, as of December 31, 2016: Productive Wells Oil Gas Gross Net Gross NetRocky Mountain 366.0 69.2 414.0 11.0Permian/Delaware Basin 138.0 126.6 44.0 26.832Table of ContentsSouth Texas 17.0 8.0 22.0 20.2Total 521.0 203.8 480.0 58.0Reserves Information The estimation and disclosure requirements we employ conform to the definition of proved reserves with the Modernization of Oil and GasReporting rules, which were issued by the SEC at the end of 2008. This accounting standard requires that the average first-day-of-the-month price during the12-month period preceding the end of the year be used when estimating reserve quantities and permits the use of reliable technologies to determine provedreserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. For the year ended December 31, 2016, DeGolyer and MacNaughton, of Dallas, Texas estimated reserves for Abraxas’ properties comprisingapproximately 99% of the PV-10 of our proved oil and gas reserves. Proved reserves for the remaining 1% of our properties were estimated by Abraxaspersonnel because we determined that it was not practical for DeGolyer and MacNaughton to prepare reserve estimates for these properties as they are locatedin a widely dispersed geographic area and have relatively low value. DeGolyer and MacNaughton’s reserve report as of December 31, 2016 included a totalof 313 properties and our internal report included 326 properties. The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications,independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Informationpromulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists,and petrophysicists. They do not own an interest in any of our properties and are not employed on a contingent fee basis. All reports by DeGolyer andMacNaughton were developed utilizing their own geological and engineering data, supplemented by data provided by Abraxas. The report of DeGolyer andMacNaughton dated February 13, 2017, which contains further discussions of the reserve estimates and evaluations prepared by DeGolyer and MacNaughtonas well as the qualifications of DeGolyer and MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached asExhibit 99.1 to this report. Estimates of reserves at December 31, 2016 were based on studies performed by the engineering department of Abraxas which is directly responsiblefor Abraxas’ reserve evaluation process. The Vice President of Engineering manages this department and is the primary technical person responsible for thisprocess. The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and is a Registered Professional Engineer in theState of Texas; he has 38 years of experience in reserve evaluations. The operations department of Abraxas assisted in the process. Reserve information aswell as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, include oil and gasprices, production costs, future capital expenditures and Abraxas’ net ownership percentages which are obtained from other departments within Abraxas. Oil and gas reserves and the estimates of the present value of future net revenues therefrom were determined based on prices and costs as prescribed bySEC and FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future netrevenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable anduncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certaintyto be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are thoseexpected to be recovered through existing wells with existing equipment and operating methods. Proved reserves were estimated in accordance withguidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with noprovision for price and cost escalations or de-escalations except by contractual arrangements. For the year ended December 31, 2016, commodity prices overthe prior 12-month period and year end costs were used in estimating future net cash flows. The following table sets forth certain information regarding estimates of our oil and gas reserves as of December 31, 2016. All of our reserves arelocated in the United States. Summary of Oil, NGL and Gas ReservesAs of December 31, 2016 Reserve Category Oil(MBbls) NGL(MBbls) Gas(MMcf) OilEquivalents (MBoe)33Table of ContentsProved Developed 7,818 2,568 27,792 15,018Undeveloped 16,391 6,076 43,037 29,639Total Proved 24,209 8,644 70,829 44,657Our estimates of proved developed reserves, proved undeveloped reserves, and total proved reserves at December 31, 2014, 2015, and 2016, andchanges in proved reserves during the last three years are presented in the Supplemental Oil and Gas Disclosures under Item 8 of this Report. Also presentedin the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves. We have not filed information with a federal authority or agency with respect to our estimated total proved reserves at December 31, 2016. We reportgross proved reserves of operated properties in the United States to the U.S. Department of Energy on an annual basis; these reported reserves are derived fromthe same data used to estimate and report proved reserves in this report. The process of estimating oil and gas reserves is complex and involves decisions and assumptions in evaluating the available geological,geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes,capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significantvariance could materially affect the estimated quantities and present value of our reserves set forth or incorporated by reference in this report. We may alsoadjust estimates of reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many ofwhich are beyond our control. In particular, estimates of oil and gas reserves, future net revenue from reserves and the PV-10 thereof for the oil and gasproperties described in this report are based on the assumption that future oil and gas prices remain the same as oil and gas prices utilized in the December 31,2016 report. The average realized sales prices used for purposes of such estimates were $35.54 per Bbl of oil and $1.41 per Mcf of gas. It is also assumed thatwe will make future capital expenditures of approximately $267.8 million in the aggregate primarily in the years 2017 through 2021, which are necessary todevelop and realize the value of proved reserves on our properties. Any significant variance in actual results from these assumptions could also materiallyaffect the estimated quantity and value of reserves set forth herein. You should not assume that the present value of future net revenues referred to in this report is the current market value of our estimated oil and gasreserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are calculated using the average first-day-of-the-month price over the prior 12-month period. Costs used in the estimated discounted future net cash flows are costs as of the end of the period. Becausewe use the full cost method to account for our oil and gas operations, we are susceptible to significant non-cash charges during times of volatile commodityprices because the full cost pool may be impaired when prices are low. This is known as a “ceiling limitation write-down.” This charge does not impact cashflow from operating activities but does reduce our stockholders’ equity and reported earnings. We have experienced ceiling limitation write-downs in thepast and we cannot assure you that we will not experience additional ceiling limitation write-downs in the future. As of December 31, 2016, the Company’snet capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves, however, during the first three quarters of2016, we incurred a proved property impairment of $67.6 million. If commodity prices decrease further, we could be required to further write down thecarrying value of our reserves during 2017 which would also reduce our net income.For more information regarding the full cost method of accounting, you should read the information under “Management’s Discussion and Analysisof Financial Condition and Results of Operations – Critical Accounting Policies.” Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate. Any changes in consumption by gaspurchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses fromthe development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. Inaddition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is notnecessarily the most accurate discount factor. Our effective interest rate on borrowings at various times and the risks associated with us or the oil and gasindustry in general will affect the accuracy of the 10% discount factor. Proved Undeveloped Reserves Changes in PUDs. Significant changes to PUDs occurring during 2016 are summarized in the table below. Revisions of prior estimates reflect theaddition of new PUDs associated with current development plans, revisions to prior PUDs, revisions34Table of Contentsto infill drilling development plans, as well as the transfer of PUDs to unproved reserve categories due to changes in development plans during the year. Ouryear-end development plans are consistent with SEC guidelines for PUDs development within five years unless specific circumstances warrant a longerdevelopment time horizon. There are no PUDs as of December 31, 2014, 2015 and 2016, included in this report that are not planned to be developed withinfive years. MMBoePUDs at December 31, 201525,996Revisions of prior estimates2,855Extensions, discoveries, and other additions823Conversion to developed—Sales(35)PUDs at December 31, 201629,639 The following is a summary of the changes to the Company’s proved undeveloped reserves that occurred during 2016.Revisions of prior estimates:An increase of 5,005 MBoe of reserves was attributed to the Company’s Bakken and Three Forks proved undeveloped locations in McKenzieCounty, ND, due to continuing improvement in the Company's producing well production results. Well results improved as a result of the application ofoptimized completion methods. A decrease of 329 MBoe of reserves was attributed to two Porcupine Field proved undeveloped locations in CampbellCounty, WY. This decrease was due to poorer-than-anticipated performance of the Hedgehog State 16-2H producing well which offsets the two provedundeveloped locations. There was also a reduction in this category of 1,821 MBoe of reserves attributable to shortened economic life calculations at thelower commodity pricing experienced during 2016.Extensions, discoveries and other additions:The Company added five new proved undeveloped Wolfcamp locations in Ward County, TX, accounting for 805 MBoe of net reserves. Theselocations are direct offsets to the Caprito 99 302H, a new Wolfcamp producer developed during 2016. The Company also added eight new provedundeveloped Bakken/Three Forks locations on non-operated units in McKenzie County, ND, accounting for 18 MBoe of net reserves. These locations wereadded in response to operator well proposals.Conversion to developed:The Company did not convert any proved undeveloped locations to proved developed reserves during 2016.Sales:The Company sold one proved undeveloped location in connection with the sale of its Portilla Field located in San Patricio County, TX. Thislocation accounted for 35 MBoe of net reserves.Reconciliation of Standardized Measure to PV-10PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10%discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as isrequired in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used toevaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gascompanies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-taxmeasure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting incometaxes. 35Table of ContentsThe following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 at December 31, 2015 and2016: December 31, 2015 2016 (In thousands)Standardized measure of discounted future net cash flows $197,251 $160,600Present value of future income taxes discounted at 10% — —PV-10 $197,251 $160,600 Oil and Gas Production, Sales Prices and Production Costs The following table presents our net oil, gas and NGL production, the average sales price per Bbl of oil and NGLs and per Mcf of gas produced and theaverage cost of production per Boe of production sold, for the three years ended December 31, by our major operating regions: 2014 2015 2016Oil production (Bbls) Rocky Mountain 816,323 1,000,425 1,102,852Permian/Delaware Basin 86,614 76,391 85,966South Texas 491,142 363,404 183,543Total 1,394,079 1,440,220 1,372,361Gas production (Mcf) Rocky Mountain 1,057,759 1,146,953 1,756,462Permian/Delaware Basin 1,003,018 973,840 742,280South Texas 856,928 894,039 660,978Total 2,917,705 3,014,832 3,159,720NGL production (Bbls) Rocky Mountain 95,384 132,846 300,669Permian/Delaware Basin 79,321 54,877 52,294South Texas 32,592 50,392 10,376Total 207,297 238,115 363,339Total production (MBoe) (1) 2,088 2,181 2,262Average sales price per Bbl of oil (2) Rocky Mountain $78.59 $39.23 $36.31Permian/Delaware Basin $84.38 $44.69 $41.30South Texas $88.44 $45.71 $40.13Composite $82.42 $41.15 $37.14Average sales price per Mcf of gas (2) Rocky Mountain $4.41 $1.46 $0.61Permian/Delaware Basin $4.29 $2.24 $2.25South Texas $3.73 $2.24 $1.87Composite $4.17 $1.94 $1.26Average sales price per Bbl of NGL Rocky Mountain $36.41 $5.49 $2.64Permian/Delaware Basin $31.10 $13.03 $12.70South Texas $21.41 $8.60 $8.94Composite $32.02 $7.89 $4.27Average sales price per Boe (2) $64.04 $30.72 $24.97Average cost of production per Boe produced (3) 36Table of ContentsRocky Mountain $7.36 $6.43 $3.68Permian/Delaware Basin $15.15 $15.76 $13.97South Texas $9.30 $12.71 $16.54Composite $9.22 $9.31 $6.60__________________(1)Oil and gas were combined by converting gas to Boe on the basis of 6 Mcf of gas to 1 Bbl of oil.(2)Before the impact of hedging activities.(3)Production costs include controllable direct lease operating costs but exclude ad valorem taxes, production taxes and non-recurring lease operatingcosts.Within the above major operating regions, the Rocky Mountain and the Permian/Delaware regions represented more than 15% of our provedreserves as of December 31, 2016. The following is a summary, by product sold, for each primary field in these regions, which represented 15% of more of ourtotal proved reserves as of December 31, 2016, for the three years ended December 31: 2014 2015 2016Rocky Mountain Region Oil production (Bbls) Bakken/Three Forks 660,447 862,458 997,641 Gas production (Mcf) Bakken/Three Forks 570,792 687,200 1,437,965 NGL production (Bbls) Bakken/Three Forks 77,120 116,392 286,232 Average sales price per Bbl of oil (1) Bakken/Three Forks $78.01 $39.15 $36.38 Average sales price per Mcf of gas (1) Bakken/Three Forks $4.60 $1.07 $0.40 Average sales price per Bbl of NGL Bakken/Three Forks $34.86 $3.78 $2.00 Average cost of production per Boe produced (2) Bakken/Three Forks $6.88 $4.05 $2.40 Permian/Delaware Region Oil production (Bbls) Montoya 552 601 1,121 Gas production (Mcf) Montoya 376,857 317,077 237,892 NGL production (Bbls) Montoya 11,180 8,852 7,748 Average sales price per Bbl of oil (1) Montoya $80.96 $42.95 $38.57 Average sales price per Mcf of gas (1) Montoya $4.32 $2.47 $2.41 Average sales price per Bbl of NGL Montoya $33.29 $13.66 $12.99 Average cost of production per Boe produced (2) Montoya $1.611.61 $2.60 $2.75 (1) Before the impact of hedging activities.(2) Production costs include direct lease operating costs but exclude ad valorem taxes and production taxes.37Table of ContentsDrilling Activities The following table sets forth our gross and net interests in exploratory and development wells drilled during the three years ended December 31: 2014 2015 2016 Gross Net Gross Net Gross Net Exploratory Productive RockyMountain — — — — — —Permian/DelawareBasin — — — — 1.0 1.0SouthTexas — — — — 1.0 1.0Total — — — — 2.0 2.0Dry wells Permian/DelawareBasin — — — — — —Total — — — — — — Development Productive RockyMountain 10.0 6.4 21.0 6.8 6.0 4.7Permian/DelawareBasin — — — — — —SouthTexas 10.0 10.0 4.0 4.0 — —Total 20.0 16.4 25.0 10.8 6.0 4.7In addition to the above drilling activity, as of December 31, 2016 we had 4.0 gross (3.0) operated wells and 6.0 gross (0.38 net) non-operated well that weredrilled and uncompleted that are not represented in the above table.Present ActivitiesPermian/Delaware BasinIn Ward County, Texas, we are currently drilling a two well pad in the Caprito 98-201H and Caprito 98-301HR. The Caprito 98-301HR will target theWolfcamp A2 zone and replaces the Caprito 98-301H, which was abandoned due to a surface issue. The Caprito 98-201H will target an additionalprospective zone in the Wolfcamp A1. Abraxas owns a working interest of approximately 88% in the Caprito 98-201H and 98-301HR, respectively. Following the drilling of the Caprito 98-201H and 301HR we will drill a second two well pad targeting the Wolfcamp A2 and the Wolfcamp B. Following these two completions, Abraxas will drill a third two well pad targeting the Wolfcamp A1 and Third Bone Spring. Following the results of thesewells we believe that we will have potentially derisked four prospective horizons allowing for an efficient development of our Caprito acreage in theDelaware Basin assets.Williston BasinAt our North Fork prospect, in McKenzie County, North Dakota, we have drilled the lateral sections of the Stenehjem 6H, 8H and 9H. We are currentlydrilling the lateral section of the Stenehjem 7H. Our working interest in the Stenehjem 6H-9H is approximately 75%. Following the completion of these wells, we plan to mobilize the rig to our Yellowstone unit to spud a three well pad. We anticipate having a 52%working interest in these wells.Eagle Ford/Austin ChalkIn Atascosa County, Texas, we plan to combine our Shut Eye and Red Eye units. The new combined unit will be the Shut Eye unit where we plan todrill the Shut Eye 1H targeting the Eagle Ford with a 100% working interest. We are currently sourcing a rig to drill this well.Office Facilities 38Table of ContentsOur executive and administrative offices are located at 18803 Meisner Drive, San Antonio, Texas 78258, and consist of approximately 21,000 squarefeet. We own the building which is subject to a real estate lien note. The note bears interest at a fixed rate of 4.25%, and is payable in monthly installments ofprincipal and interest of $34,354. Beginning August 20, 2018, the interest rate will adjust to the current bank prime rate plus 1.00% with a maximum rate of7.25%. The note matures in July 2023. The note is secured by a first lien deed of trust on the property and improvements. As of December 31, 2016, $3.9million was outstanding on the note. We lease office space in Dickinson, North Dakota for a monthly rental of $2,320 through October 2018. The leaseexpires on October 31, 2018. We lease office space in Lusk, Wyoming for a monthly rental of $750. The lease expires on December 31, 2017. We also leaseoffice space in Denver, Colorado for a monthly rental of $1,107. The lease expires on December 31, 2017. Other Properties We own an office building, workshop, warehouse and house in San Patricio County, Texas, 613 acres of land and an office building in Scurry County,Texas, 50 acres of land in DeWitt County, Texas, 582 acres of land in McKenzie County, North Dakota and 12,178 acres of land in Pecos County, Texas.We own 23 vehicles which are used in the field by employees. We own two workover rigs, which are used for servicing our wells. Raven Drilling owns a2000 HP drilling rig, primarily to be used for drilling wells in the Williston Basin. We own three houses in North Dakota and a man-camp in North Dakota tohouse rig crews. Item 3. Legal Proceedings From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31,2016, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financialcondition. Item 4.Mine Safety Disclosures Not applicable.39Table of ContentsPart IIItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our common stock is traded on The NASDAQ Stock Market under the symbol "AXAS." The following table sets forth certain information as to thehigh and low sales price quoted for our common stock. Period High Low2015 First Quarter $3.56 $2.60 Second Quarter 3.98 2.82 Third Quarter 2.95 1.20 Fourth Quarter 1.95 0.842016 First Quarter $1.31 $0.65 Second Quarter 1.58 0.89 Third Quarter 1.73 1.07 Fourth Quarter 2.70 1.522017 16First Quarter (Through March 10, 2017) $2.99 $1.67Holders As of March 10, 2017, we had 163,844,255 shares of common stock outstanding and approximately 990 stockholders of record. Dividends We have not paid any cash dividends on our common stock and it is not presently determinable when, if ever, we will pay cash dividends in thefuture. In addition, our credit facility prohibits the payment of cash dividends on our common stock.Performance GraphSet forth below is a performance graph comparing yearly cumulative total stockholder return on our common stock with (a) the monthly index ofstocks included in the Standard and Poor’s 500 Index and (b) a market capitalization weighted index of comparable companies based on 1) companies ofsimilar size, 2) other similar companies in the oil and gas exploration industry, and 3) similar operations in comparable geographies compiled in 2015 byLongnecker & Associates ("L&A"). L&A then analyzed each company based on:•Market capitalization;•Revenue;•Assets;•Enterprise value; and•Operational similarities.Using these criteria, the following is a list of comparable companies utilized in the graph below: Approach Resources, Inc. (AREX), CallonPetroleum Company (CPE), Comstock Resources, Inc. (CRK), Contango Oil & Gas Company (MCF), Earthstone Energy Inc. (ESTE), Evolution PetroleumCorp. (EPM), Gastar Exploration Inc. (GST), Northern Oil and Gas, Inc (NOG) and Ring Energy Inc.(REI). The following companies which were utilized in the2015 graph were eliminated in the 2016 graph as a result of bankruptcy filings or other corporate events or transactions during the year: Clayton WilliamsEnergy, Inc. (CWEI), Emerald Oil, Inc. (EOX), Magnum Hunter Resources Corporation (MHR), Penn Virginia Corporation (PVA), Swift Energy Co. (SFY),Triangle Petroleum Corporation (TPLM) and Warren Resources, Inc. (WRES). We added Earthstone Energy, Inc. and Ring Energy, Inc. utilizing the samecriteria as L&A in 201640Table of ContentsAll of these cumulative total returns are computed assuming the value of the investment in our common stock and each index as $100.00 onDecember 31, 2011, and the reinvestment of dividends at the frequency with which dividends were paid during the applicable years. The years compared are2012, 2013, 2014, 2015 and 2016. 12/31/2011 12/31/2012 12/31/2013 12/31/2014 12/31/2015 12/31/2016Small Cap Index$100.00$83.02$104.73$60.43$43.59$70.21S&P 500$100.00$113.41$146.98$163.72$162.53$178.02AXAS$100.00$66.36$98.82$89.09$32.12$77.882015 Peer Group$100.00$64.66$90.18$44.41$20.86$41.02The information contained above under the caption “Performance Graph” is being “furnished” to the SEC and shall not be deemed to be “solicitingmaterial” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, asamended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate it by reference into such filing.41Table of ContentsItem 6. Selected Financial Data The following selected financial data is derived from our Consolidated Financial Statements as of and for the years ended December 31, 2012 through2016. The data should be read in conjunction with our Consolidated Financial Statements and Notes thereto and other financial information included herein.See “Financial Statements and Supplementary Data” in Item 8. Year Ended December 31, 20122013 2014 2015 2016 (In thousands, except per share data)Total revenue - continuing operations $65,664 $92,324 $133,776 $67,030 $56,555 Net (loss) income $(18,791) $38,647 $63,269 $(127,110) $(96,378) Net income (loss) from continuing operations $3,106 $46,841(2)$61,951 $(127,090)(5)$(96,378)(6)Net (loss) income from discontinuedoperations - net of tax $(21,897)(1)$(8,194)(3)$1,318(4)$(20) $— Net income (loss) per common share – diluted- continuing operations $0.04 $0.50 $0.61 $(1.21) $(0.79) Weighted average shares outstanding –diluted 91,914 93,538 101,468 104,605 122,132 Total assets $240,607 $223,650 $374,899 $267,872 $161,648 Long-term debt, excluding current maturities $124,101 $41,790 $76,554 $138,402 $96,616 Total stockholders’ equity $46,700 $86,906 $207,495 $84,465 $18,505 ___________________________ (1)Includes proved property impairment of $19.8 million related to discontinued operations.(2)Includes a gain on the sale of properties of $33.4 million.(3)Includes proved property impairment of $6.0 million related to discontinued operations.(4)Includes a gain of $1.9 million on the sale of our Canadian subsidiary.(5)Includes proved property impairment of $128.6 million.(6)Includes proved property impairment of $67.6 million.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion excludes theresults of our Canadian subsidiary which was sold on October 31, 2014. The results of these foreign operations are included as discontinued operations in theaccompanying Consolidated Financial Statements and Notes thereto.This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See “Financial Statements andSupplementary Data” in Item 8.General We are an independent energy company primarily engaged in the acquisition, exploration, exploitation, development and production of oil and gas inthe United States. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principallythrough the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismicsurveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition,we intend to expand upon our development activities with complementary acreage acquisitions in our core areas of operation. Success in our developmentand exploration activities is critical in the maintenance and growth of our current production levels and associated reserves. While we have attained positive net income in two of the last five years, there can be no assurance that operating income and net earnings will beachieved in future periods. Our financial results depend upon many factors which significantly affect our results of operations including the following: 42Table of Contents•commodity prices and the effectiveness of our hedging arrangements;•the level of total sales volumes of oil and gas;•the availability of and our ability to raise additional capital resources and provide liquidity to meet cash flow needs;•the level of and interest rates on borrowings; and•the level and success of exploration and development activity.Commodity Prices and Hedging Arrangements. The results of our operations are highly dependent upon the prices received for our oil and gasproduction. The prices we receive for our production are dependent upon spot market prices, differentials and the effectiveness of our derivative contracts,which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts basedon spot market prices, and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependentupon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition,results of operations, cash flows and quantities of reserves recoverable on an economic basis. Oil and gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world politicalenvironment, worldwide supplies of oil, NGL and gas, the availability of other worldwide energy supplies and the relative competitive relationships of thevarious energy sources in the view of consumers, we are unable to predict what changes may occur in oil, NGL, and gas prices in the future. The market priceof oil and condensate, NGL and gas in 2017 will impact the amount of cash generated from operating activities, which will in turn impact our financialposition. As of March 10, 2017, the NYMEX oil and gas price was $48.49 per Bbl of oil and $3.00 per Mcf of gas, respectively, representing increases of 12%and 18%, respectively, from the average NYMEX prices in 2016.During 2016, the NYMEX future price for oil averaged $43.47 per barrel as compared to $48.76 per barrel in 2015. During 2016 the NYMEX future spotprice for gas averaged $2.55 per MMBtu compared to $2.63 per MMBtu in 2015. Prices closed on December 31, 2016 at $53.72 per Bbl of oil and $3.72 perMMBtu of gas. If commodity prices decline from these levels, our revenue and cash flow from operations will also likely decline. In addition, lowercommodity prices could also reduce the amount of oil and gas that we can produce economically. If oil and gas prices remain depressed or continue todecline, our revenues, profitability and cash flow from operations will also likely decrease which could cause us to alter our business plans, includingreducing our drilling activities. Such declines could also require us to write down the carrying value of our oil and gas assets which would also cause areduction in net income. Finally, low commodity prices will likely cause a reduction of the borrowing base under our credit facility. The borrowing baseunder our credit facility is scheduled to be redetermined on April 1, 2017. The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to: •basis differentials which are dependent on actual delivery location;•adjustments for BTU content;•quality of the hydrocarbons; and•gathering, processing and transportation costs.The following table sets forth our average differentials for the years ended December 31, 2014, 2015 and 2016: Oil Gas 2014 2015 2016 2014 2015 2016Average realized price (1) $82.42 $41.15 $37.14 $4.17 $1.94 $1.26Average NYMEX price $92.91 $48.76 $43.47 $4.26 $2.63 $2.55Differential $(10.49) $(7.61) $(6.33) $(0.09) $(0.69) $(1.29)_______________________(1)Average realized prices are before the impact of hedging activities. The Company’s derivative contracts as of December 31, 2016 consisted of NYMEX-based fixed price swaps, basis differential swaps and costless collars.Under fixed price swaps, we receive a fixed price for our production and pay a variable market price to the contract counter-party. Under a costless collarcontract, we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floorprice (long put).43Table of ContentsOur hedging arrangements equate to approximately 70% of the oil production of our estimated net proved developed producing reserves (as of December31, 2016) through December 31, 2017, 77% for 2018 and 64% for 2019. As of December 31, 2016, we also had NYMEX-based costless collar commodityarrangements on approximately 56% of our estimated net proved developed producing gas reserves (as of December 31, 2016) through December 31, 2017and a 500 Bopd Midland - Cushing oil price differential swap at ($0.65)/Bbl. By removing a portion of price volatility on our future oil and gas production,we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for thoseperiods. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the productionthat has been hedged. We have in the past and will in the future sustain realized and unrealized losses on our derivative contracts if market prices are higherthan our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains on ourcommodity derivative contracts. In 2014, we incurred a net gain of $25.2 million, consisting of a gain of $0.3 million related to closed contracts and a gain of$24.9 million related to open contracts. In 2015, we incurred a gain of $19.3 million, consisting of a gain of $9.5 million on closed contracts and a gain of$9.8 million related to open contracts. In 2016, we incurred a loss of $18.0 million, consisting of a gain of $1.8 million on closed contracts and a loss of$19.8 million related to open contracts. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules. The following table sets forth our derivative contracts at December 31, 2016:Fixed Price Swaps: Oil - WTIContract Periods Daily Volume (Bbl) Swap Price (perBbl)Fixed Swaps 2017 2,401 $54.532018 1,796 $47.482019 1,200 $54.54 Basis Swap 2017 500 $0.65Collar contracts: Daily Volume(Bbl) Floor (LongPut) Ceiling(Short Call) 2017 5,000 $3.00 $3.90 At December 31, 2016, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $9.0 million.Production Volumes. Our proved reserves will decline as oil and gas is produced, unless we find, acquire or develop additional properties containingproved reserves or conduct successful exploration and development activities. Based on the reserve information set forth in our reserve report as ofDecember 31, 2016, our average annual estimated decline rate for our net proved developed producing reserves is 40%; 15%; 12%; 11% and 9% in 2018,2019, 2020, 2021 and 2022, respectively, 9% in the following five years, and approximately 9% thereafter. These rates of decline are estimates and actualproduction declines could be materially higher. While we have had some success in finding, acquiring and developing additional reserves, we have notalways been able to fully replace the production volumes lost from natural field declines and property sales. Our ability to acquire or find additional reservesin the future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects.We had capital expenditures during 2016 of $31.7 million related to our exploration and development activities. We have a capital expenditure budgetfor 2017 of approximately $110.0 million. Approximately $52.5 million of the 2017 budget will be allocated to developing our Permian and DelawareBasin assets including approximately $15.0 million dedicated to expanding our acreage position in the Delaware Basin. The 2017 budget also allocatesapproximately $42.2 million for drilling and completion of wells in our Bakken/Three Forks play in North Dakota, with the remaining amount allocated tothe Austin Chalk/Eagle Ford area in South Texas as well as lease acquisition and general corporate expenses. The 2017 capital expenditure budget is subject44Table of Contentsto change depending upon a number of factors, including the availability and costs of drilling and service equipment and crews, economic and industryconditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficient capital resources including under our creditfacility, the results of our exploitation efforts, our financial results and our ability to obtain permits for drilling locations. The following table presents historical net production volumes for the years ended December 31, 2014, 2015 and 2016: Year Ended December 31, 2014 2015 2016Total production (MBoe) 2,088 2,181 2,262Average daily production (Boepd) 5,720 5,975 6,181% Oil 67% 66% 61%Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, our sources of capital are cash flow from operatingactivities, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments, and if an appropriateopportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. Asof December 31, 2016, we had approximately $22.0 million of availability under our credit facility. As of March 10, 2017, we had approximately $97.0million available under our credit facility. The availability under our credit facility is subject to a borrowing base determined by our lenders. This borrowingbase is subject to semi-annual redeterminations. The next redetermination becomes effective on April 1, 2017. Borrowings and Interest. At December 31, 2016, we had a total of $93.0 million outstanding under our credit facility and total indebtedness of $97.4million (including the current portion). As of March 10, 2017, we had a total of $18.0 million outstanding under our credit facility and total indebtedness of$21.8 million (including the current portion). If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow fromoperations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund thedevelopment of our drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices.Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projectsposition us for future growth. At December 31, 2016, we operated properties accounting for approximately 95% of our PV-10, giving us substantial controlover the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations on our existing leaseholds,the successful development of which we believe could significantly increase our production and proved reserves. Over the five years ended December 31,2016, we drilled or participated in 124 gross (46.2 net) wells of which 97% were commercially productive. Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that areprofitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless weacquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identifyadditional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases inour proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations and theamount that we are able to borrow under our credit facility may also decline. In addition, approximately 66% of our estimated proved reserves on a BOE basis(33% on a PV-10 basis) at December 31, 2016 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of suchreserves will require significant capital expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves, in whichcase our results of operations and financial condition could be adversely affected.2017 OutlookMarket prices for oil, gas and NGL are inherently volatile. Accordingly, we cannot predict with certainty the future prices for the commodities weproduce and sell. Current market fundamentals indicate prices for oil, gas and NGL will be higher than experienced during much of 2016, although remainingmuch lower than prices prior to mid 2014. Lower prices for oil and gas have had and will likely continue to have a material adverse effect on our results ofoperations and liquidity.Our primary sources of liquidity are cash flow from operations and borrowings under our credit facility. Cash flow from operations is sensitive to manyvariables, the most volatile of which is the price of the oil, gas and NGL we produce and sell. Lower prices and/or lower production will cause our cash flowfrom operations to decrease. Availability under our credit facility is currently subject to a borrowing base of $115.0 million. The borrowing base is subject toscheduled semiannual (April 1 and45Table of ContentsOctober 1) and other elective borrowing base redeterminations. The amount of the borrowing base is calculated by the lenders based upon their valuation ofour proved reserves securing the facility utilizing these reserve reports and their own internal decisions. The lenders under our credit facility can unilaterallyadjust the borrowing base and the borrowings permitted to be outstanding under our credit facility. As a result of the decline in commodity prices for oil, gasand NGL, our borrowing base was reduced in 2016. If prices were to decline again in 2017, we would likely experience a further decrease in the borrowingbase.In 2015, as a result of the sharp decline in commodity prices, we incurred an impairment to our proved properties of $128.6 million. We incurredadditional impairments of our oil and gas properties of $67.6 million during 2016. If commodity prices decrease in the future, we would likely incuradditional impairments.Results of OperationsSelected Operating Data. The following table sets forth operating data from continuing operations for the periods presented. Year Ended December 31, (In thousands, except per unit data) 2014 2015 2016Operating revenue (1): Oil sales $114,898 $59,270 $50,965Gas sales 12,166 5,854 3,978NGL sales 6,637 1,878 1,550Total operating revenues $133,701 $67,002 $56,493Operating income (loss) $39,922 $(141,805) $(73,387)Oil sales (MBbls) 1,394 1,440 1,372Gas sales (MMcf) 2,918 3,015 3,160NGL sales (MBbls) 207 238 363Oil equivalents (MBoe) 2,088 2,181 2,262Average oil sales price (per Bbl)(1) $82.42 $41.15 $37.14Average gas sales price (per Mcf)(1) $4.17 $1.94 $1.26Average NGL sales price (per Bbl) $32.02 $7.89 $4.27Average oil equivalent sales price (per Boe) $64.04 $30.72 $24.97___________________(1)Revenue and average sales prices are before the impact of hedging activities.Comparison of Year Ended December 31, 2016 to Year Ended December 31, 2015 Operating Revenue. During the year ended December 31, 2016, operating revenue decreased to $56.5 million from $67.0 million in 2015. The decreasein revenue was primarily due to lower commodity prices in 2016 and lower oil sales, partially offset by slightly higher gas and NGL sales in 2016 ascompared to 2015. Lower commodity prices had a negative impact on revenue of $9.0 million in 2016. The lower volume of oil sales negatively impactedrevenue by $2.8 million partially offset by higher gas and NGL sales which added $1.3 million. During 2016, we experienced a decline in the averagerealized oil price of approximately 10% from 2015 levels. Average realized gas prices declined by approximately 35% and average realized NGL pricesdeclined approximately 46% from 2015 levels.Oil sales volumes decreased to 1,372 MBbls for the year ended December 31, 2016 from 1,440 MBbls for the same period of 2015. The decrease in oilsales volumes was due to natural field declines, sales of non-core properties and a significant reduction in drilling and completion activity in 2016. Six wellsthat were drilled in late 2015 were not completed until the latter part of the third quarter of 2016. New production brought on line added 357.8 Mboe to salesin 2016. Gas sales volumes increased to 3,160 MMcf for the year ended December 31, 2016 from 3,015 MMcf for the year ended December 31, 2015. During2015, we were subject to pipeline constraints and gas plant capacity issues that improved somewhat in 2016. New wells brought onto production during2016 contributed 427 MMcf to production for the year ended December 31, 2016. NGL sales increased to 363 MBbls for the year ended December 31, 2016from 238 MBbls for the same period of 2015. The increase in NGL sales was primarily due to increased gas production from fields in West Texas, Wyomingand North Dakota that have a higher NGL content than our historical gas production.46Table of Contents Lease Operating Expenses (“LOE”). LOE for the year ended December 31, 2016 decreased to $18.2 million from $23.1 million in 2015. The decrease inLOE was primarily due to lower cost of services, and less non-recurring LOE in 2016 compared to 2015. Additionally, due to the continued weakness incommodity prices, marginal wells were temporarily shut in to control costs. LOE per Boe for the year ended December 31, 2016 was $8.05 compared to$10.58 for the same period of 2015. The decrease in LOE per Boe was attributable to lower cost as well as slightly higher sales volumes in 2016.Production and Ad Valorem Taxes. Production and ad valorem taxes for the year ended December 31, 2016 decreased to $5.5 million from $6.7 millionin 2015. The decrease was primarily due to lower realized prices and a lower volume of oil sales in 2016 as compared to 2015, partially offset by increasedgas and NGL sales volumes in 2016 as compared to 2015. Production and ad valorem taxes as a percentage of oil and gas revenue remained constant at 10%in 2016 and 2015. General and Administrative (“G&A”) Expense. G&A expense, excluding stock-based compensation, increased to $10.4 million for the year endedDecember 31, 2016 from $7.9 million in 2015. The increase was primarily due to incentive bonuses earned in 2016. G&A expense per Boe was $4.58 for theyear ended December 31, 2016 compared to $3.61 for the same period of 2015. Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the optionsvesting period. In addition to options, restricted shares of common stock have been granted and are valued at the date of grant and expense is recognized overtheir vesting period. Stock-based compensation for the year ended December 31, 2016 decreased to $3.2 million from $3.9 million in 2015. The decrease wasdue to lower grant prices in 2016 as compared to 2015. Depreciation, Depletion, and Amortization (“DD&A”) Expenses. DD&A expense decreased to $24.4 million for the year ended December 31, 2016 from$38.7 million in 2015. DD&A decreased primarily due to proved property impairments recognized in 2015 and the first three quarters of 2016, as well asdecreased future development costs included in the 2016 reserve reports. DD&A per Boe for 2016 was $10.80 compared to $17.76 in 2015. The decrease inDD&A per Boe was due to a lower depletable base as the result of impairments as well as lower future development cost in 2016 as compared to 2015. Interest Expense. Interest expense increased to $4.3 million in 2016 from $3.9 million for 2015. The increase was primarily due to higher interest rates in2016 as compared to 2015.Income Taxes. In 2015 an income tax benefit was recognized as the result of an overpayment of state income taxes in 2014 that was refunded in 2015, aswell as a benefit of a capital loss carryback which resulted in a refund of prior year federal taxes of $242,000. Due to losses incurred and loss carry forwards,we did not recognize any income tax expense for the year ended December 31, 2016.Loss (Gain) on Derivative Contracts. Derivative gains or losses are determined by actual derivative settlements during the period and by periodic markto market valuation of derivative contracts in place. We have elected not to apply hedge accounting to our derivative contracts as prescribed by AccountingStandards Codification 815, Derivatives and Hedging "ASC 815"; therefore, fluctuations in the market value of the derivative contracts are recognized inearnings during the current period. Our derivative contracts consisted of fixed price swaps, basis differential swaps and collar contracts in 2016 and fixedprice swaps and three way collar contracts in 2015. The net estimated value of our commodity derivative contracts was a liability approximately $9.0 millionas of December 31, 2016. When our derivative contract prices are higher than prevailing market prices, we incur gains and conversely, when our derivativecontract prices are lower than prevailing market prices, we incur losses. For the year ended December 31, 2016, we recognized a loss on our derivativecontracts of approximately $18.0 million, consisting of a gain of $1.8 million on closed contracts and a loss of $19.8 million on the mark to market valuationof open contracts. For the year-ended December 31, 2015, we incurred a gain of $19.3 million, consisting of a gain of $9.5 million on closed contracts and again of $9.8 million related to open contracts.Monetization of Derivative Contracts. During 2016, we monetized certain of our derivative contracts. Proceeds from the monetization wereapproximately $14.4 million. During 2015, proceeds from the monetization of derivative contracts were approximately $4.6 million. Ceiling Limitation Write-Down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gasproperties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the netcapitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined asthe sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not beingamortized, if any,47Table of Contentsplus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the netcapitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceilinglimitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount ofour stockholders' equity and reported earnings. As of December 31, 2015, the net capitalized cost of our oil and gas properties exceeded the present value ofour estimated proved reserves, resulting in the recognition of an impairment of $128.6 million in 2015. During 2016 we incurred impairments of $67.6million. The year-end amount was calculated in accordance with SEC rules utilizing the twelve month first-day-of-the-month average oil and gas prices forthe year ended 2016 which were $42.74 per Bbl for oil and $2.50 per Mcf for gas as adjusted to reflect the expected realized prices for our oil and gasreserves.Comparison of Year Ended December 31, 2015 to Year Ended December 31, 2014 Operating Revenue. During the year ended December 31, 2015, operating revenue decreased to $67.0 million from $133.7 million in 2014. The decreasein revenue was primarily due to a significant decline in commodity prices in 2015. Lower commodity prices had a negative impact on revenue of $69.0million in 2015. During 2015 we experienced a decline in the average realized oil price of approximately 50% from 2014 levels. Average realized gas pricesdeclined by approximately 53% and average realized NGL prices declined approximately 75% from 2014 levels. Higher sales volumes of all products added$2.3 million to revenue in 2015 as compared to 2014. Oil sales volumes increased to 1,440 MBbls for the year ended December 31, 2015 from 1,394 MBbls for the same period of 2014. The increase in oilsales volumes was due to new production brought on line in 2015. New wells brought onto production in 2015 contributed 298 MBbls to production for theyear ended December 31, 2015, offset by natural field declines and property sales. Gas sales volumes increased to 3,015 MMcf for the year ended December31, 2015 from 2,918 MMcf for the year ended December 31, 2014. The increase in gas production was due to new wells being brought on line, offset bynatural field declines. New wells brought onto production during 2015 contributed 299 MMcf to production for the year ended December 31, 2015. NGLsales increased to 238 MBbls for the year ended December 31, 2015 from 207 MBbls for the same period of 2014. The increase in NGL sales was primarilydue to increased gas production from fields in West Texas, Wyoming and North Dakota that have a higher NGL content than our historical gas production. Lease Operating Expenses. LOE for the year ended December 31, 2015 decreased to $23.1 million from $25.9 million in 2014. The decrease in LOE wasprimarily due to lower cost of services, and less non-recurring LOE in 2015 compared to 2014. Additionally, due to the significant decline in commodityprices, marginal wells were temporarily shut in to control costs. LOE per Boe for the year ended December 31, 2015 was $10.58 compared to $12.39 for thesame period of 2014. The decrease in LOE per Boe was attributable to higher sales volumes in 2015 as well as lower costs.Production and Ad Valorem Taxes. Production and ad valorem taxes for the year ended December 31, 2015 decreased to $6.7 million from $11.5million in 2014. The decrease was primarily due to significantly lower realized prices in 2015 as compared to 2014 which was partially offset by increasedproduction in 2015 as compared to 2014. Production and ad valorem taxes as a percentage of oil and gas revenue increased to 10% in 2015 from 9% in 2014.The increase was due primarily to a higher production in the Rocky Mountain region that has a higher tax rate. General and Administrative Expense. G&A expense, excluding stock-based compensation, decreased to $7.9 million for the year ended December 31,2015 from $10.7 million in 2014. G&A expense per Boe was $3.61 for the year ended December 31, 2015 compared to $5.11 for the same period of 2014.The decrease in G&A was primarily due to performance bonuses in 2014 that did not occur in 2015. Additionally, as a result of the depressed priceenvironment, emphasis was placed on reducing cost. Stock-Based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the optionsvesting period. In addition to options, restricted shares of common stock have been granted and are valued at the date of grant and expense is recognized overtheir vesting period. Stock-based compensation for the year ended December 31, 2015 increased to $3.9 million from $2.7 million in 2014. The increase wasdue to the grant of a greater number of options in 2015 as compared to 2014. Depreciation, Depletion, and Amortization (“DD&A”) Expenses. DD&A expense decreased to $38.7 million for the year ended December 31, 2015 from$43.1 million in 2014. DD&A decreased primarily due to decreased future development costs included in the 2015 reserve reports. DD&A per Boe for 2015was $17.76 compared to $20.66 in 2014. The decrease in DD&A per BOE was due to lower future development cost in 2015 as compared to 2014. 48Table of ContentsInterest Expense. Interest expense increased to $3.9 million in 2015 from $2.6 million for 2014. The increase was primarily due to higher levels of debtduring 2015 as compared to 2014.Income Taxes. An income tax benefit was recognized in 2015 as the result of an overpayment of state income taxes in 2014 that was refunded in 2015,as well as a benefit of a capital loss carryback which resulted in a refund of prior year federal taxes of $242,000.Loss (Gain) on Derivative Contracts. Gains or losses are determined by actual derivative settlements during the period and by the periodic mark tomarket valuation of derivative contracts in place. We have elected not to apply hedge accounting to our derivative contracts as prescribed by ASC 815;therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. The net estimated value of ourcommodity derivative contracts was an asset of approximately $27.4 million as of December 31, 2015. When our derivative contract prices are higher thanprevailing market prices, we incur gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For theyear ended December 31, 2015, we realized a gain on our derivative contracts of $19.3 million, consisting of a gain of $9.5 million on our closed contractsand a gain of $9.8 million related to open contracts. For the year-ended December 31, 2014, we incurred a gain of $25.2 million, consisting of a gain of $0.3million on closed contracts and a gain of $24.9 million related to our open contracts. Monetization of Derivative Contracts. During 2015, we monetized certain of our derivative contracts. Proceeds from the monetization wereapproximately $4.6 million. During 2014, proceeds from the monetization of derivative contracts were approximately $0.2 million.Ceiling Limitation Write-Down. As of December 31, 2015, the net capitalized cost of our oil and gas properties exceeded the present value of ourestimated proved reserves, resulting in the recognition of an impairment of $128.6 million. The year-end amount was calculated in accordance with SEC rulesutilizing the twelve month first-day-of-the-month average oil and gas prices for the year ended 2015 which were $50.12 per Bbl for oil and $2.63 per Mcf forgas as adjusted to reflect the expected realized prices for our oil and gas reserves. As of December 31, 2014, the net capitalized cost of our oil and gasproperties did not exceed the present value of our estimated proved reserves.Liquidity and Capital ResourcesGeneral. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligationsto service debt and to fund the following:•the development and exploration of existing properties, including drilling and completion costs of wells;•acquisition of interests in additional oil and gas properties; and•production and gathering facilities.The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, willdirectly affect our ability to service our debt obligations and to grow the business through the development of existing properties and the acquisition of newproperties. Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties,and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financings on terms acceptable to us,if at all.Operating Cash Flow. Our operating cash flow is sensitive to many variables, the most volatile of which is the prices of the oil, gas and NGL we produceand sell. Our consolidated cash flow from operations increased in 2016, primarily due to the monetization of derivative positions of $14.4 million. We expectcash flow from operations to continue to be a primary source of liquidity in 2017.Commodity Prices. Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and othersubstantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and arebeyond our control. We have entered into NYMEX-based fixed price commodity swap arrangements on approximately 70% of the oil production of ourestimated net proved developed producing reserves (as of December 31, 2016) through December 31, 2017, 77% for 2018 and 64% for 2019. We have alsoentered into a NYMEX-based collar on approximately 56% of the gas production of our estimated net proved developed producing reserves (as of December31, 2016) through December 31, 2017 and a 500 Bopd Midland-Cushing oil price differential swap at ($0.65)/Bbl.49Table of ContentsThe key terms of our derivative financial instruments as of December 31, 2016 are presented in Note 11 in “Item 8. Financial Statements andSupplementary Data” of this report.Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases canlead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease,causing a positive impact on our cash flow as the prices paid for services and equipment decline. Working Capital (Deficit). At December 31, 2016, our current liabilities of $31.1 million exceeded our current assets of $23.9 million resulting in aworking capital deficit of $7.2 million. This compares to a working capital deficit of $2.4 million at December 31, 2015. Current assets at December 31, 2016primarily consisted of accounts receivable of $13.5 million, assets held for sale of $9.7 million other current assets of $0.6 million and the current portion ofour derivative asset of $0.1 million. Current liabilities at December 31, 2016 primarily consisted of trade payables of $18.4 million, revenues due thirdparties of $8.9 million, current maturities of long-term debt of $0.8 million, the current amount of our derivative liability of $2.4 million and accruedexpenses of $0.6 million. The working capital deficit is expected to be funded by cash flow from operations and borrowings under our credit facility. Capital Expenditures. Capital expenditures in 2014, 2015 and 2016 were $192.8 million, $69.4 million, and $31.7 million, respectively. The tablebelow sets forth the components of these capital expenditures: Year Ended December 31, 2014 2015 2016 (In thousands)Expenditure category: Exploration/Development $189,210 $68,631 $30,787Facilities and other 3,589 760 876Total $192,799 $69,391 $31,663During 2014, 2015 and 2016 our expenditures were primarily for exploration and for the development of our existing properties, as well as acquisitionsof leaseholds. We anticipate making capital expenditures in 2017 of approximately $110.0 million. Approximately $52.5 million of the 2017 budget will be allocatedto developing our Permian/Delaware Basin assets including approximately $15.0 million dedicated to expanding our acreage position in the Delaware Basin.The 2017 budget also allocates approximately $42.2 million for drilling and completion of wells in our Williston Basin/Bakken/Three Forks play in NorthDakota, with the remaining amount allocated to the Austin Chalk/Eagle Ford area in South Texas as well as lease acquisition and general corporate expenses.The 2017 capital expenditure budget is subject to change depending upon a number of factors, including the availability and costs of drilling and serviceequipment and crews, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the availability of sufficientcapital resources, our financial results and our ability to obtain permits for drilling locations. Our capital expenditures could also include expenditures for theacquisition of producing properties, if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending oneconomic and industry conditions and commodity prices. Should the prices of oil and gas decline and if our costs of operations increase or if our productionvolumes decrease, our cash flows will decrease which may result in a reduction of the capital expenditure budget. If we decrease our capital expenditurebudget, we may not be able to offset oil and gas production decreases caused by natural field declines.Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the followingtable and discussed in further detail below: Year Ended December 31, 2014 2015 2016 (In thousands)Net cash provided by operating activities $94,462 $6,999 $26,872Net cash used in investing activities (186,800) (69,253) (14,071)Net cash (used in) provided by financing activities 87,857 62,042 (16,341)Total $(4,481) $(212) $(3,540)50Table of Contents Operating activities for the year ended December 31, 2016 provided $26.9 million in cash. Non-cash expense items and net changes in operating assetsand liabilities and the monetization of derivative positions accounted for most of these funds. Investing activities used $14.1 million. Financing activitiesused $16.3 million primarily for reductions of amount due under our credit facility, offset by proceeds from long term borrowings and proceeds from theissuance 28.8 million shares of common stock in May 2016.Operating activities for the year ended December 31, 2015 provided $7.0 million in cash. Non-cash expense items and net changes in operating assetsand liabilities accounted for most of these funds. Investing activities used $69.3 million. Financing activities provided $62.0 million primarily from long-term borrowings offset by payments on long-term debt. Operating activities for the year ended December 31, 2014 provided $94.5 million in cash. Non-cash expense items and net changes in operating assetsand liabilities accounted for most of these funds. Investing activities used $186.8 million. Financing activities provided $87.9 million, primarily from theissuance of 11.5 million shares of common stock in June 2014, and proceeds from long-term borrowings offset by payments on long-term debt. Future Capital Resources. Our principal sources of capital going forward are cash flow from operations, borrowings underour credit facility, cash on hand, proceeds from the sale of properties, monetizing of derivative instruments and if an opportunity presents itself, the sale ofdebt or equity securities, although we may not be able to complete financing on terms acceptable to us, if at all. In January 2017 we completed an offering of28.8 million shares of common stock for net proceeds of approximately $65.3 million. Proceeds from the offering were used to reduce amounts outstandingunder our credit facility. Cash from operating activities is dependent upon commodity prices and production volumes. A decrease in commodity prices from current levels wouldlikely reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and developmentplans. Unless we otherwise expand and develop reserves, our production volumes may decline as reserves are produced. In the future we may continue to sellproducing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines andsales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify anddevelop additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase ourproduction volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil and gas reservoirswill be found. If our proved reserves decline in the future, our production will also decline and, consequently, our cash flow from operations and the amountthat we are able to borrow under our credit facility will also decline. The availability under our credit facility is subject to a borrowing base determined byour lenders. This borrowing base is subject to semi-annual redeterminations. The next redetermination becomes effective on April 1, 2017. The risk of notfinding commercially productive reservoirs will be compounded by the fact that 66% of our total estimated proved reserves on a Boe basis (33% on a PV-10basis) at December 31, 2016 were classified as undeveloped. We have in the past, and may in the future, sell properties and/or monetize derivative instruments. We have also sold debt and equity securities in thepast, and may sell additional debt and equity securities in the future when the opportunity presents itself.Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements:•Long-term debt; and•Operating leases for office facilities.Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2016: Payments due in twelve month periods ending:Contractual Obligations(In thousands) Total December 31, 2017 December 31,2018-2019 December 31,2020-2021 ThereafterLong-term debt (1) $97,402 $786 $93,534 $582 $2,500Interest on long-term debt (2) 5,408 3,206 1,810 241 151Lease obligations (3) 73 50 23 — —Total $102,883 $4,042 $95,367 $823 $2,651___________________________51Table of Contents(1)These amounts represent the balances outstanding under our credit facility, the rig loan agreement and the real estate lien note. These paymentsassume that we will not borrow additional funds.(2)Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates.(3)Lease on office space in Dickinson, North Dakota, which expires on October 31, 2018, office space in Lusk, Wyoming, which expires on December 31,2017 and office space in Denver, Colorado which expires on December 31, 2017.We maintain a reserve for costs associated with the retirement of tangible long-lived assets. At December 31, 2016, our reserve for these obligationstotaled $8.6 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of the Notes toConsolidated Financial Statements. Off-Balance Sheet Arrangements. At December 31, 2016, we had no existing off-balance sheet arrangements, as defined under SEC regulations thathave, or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity,capital expenditures or capital resources that are material to investors. Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. AtDecember 31, 2016, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us. Long-Term Indebtedness. Long-term debt consisted of the following: December 31, 2015 December 31, 2016 (In thousands)Credit facility $134,000 $93,000Rig loan agreement 2,620 535Real estate lien note 4,112 3,867 140,732 97,402Less current maturities (2,330) (786) $138,402 $96,616Credit Facility We have a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to asthe credit facility. As of December 31, 2016, $93.0 million was outstanding under the credit facility. As of March 10, 2017, $18.0 million was outstandingunder the credit facility.The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At December 31, 2016, we had aborrowing base of $115.0 million. The borrowing base is determined semi-annually by the lenders based upon our reserve reports, one of which must beprepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by thelenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, thelenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduledredeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. The next redeterminationwill be effective on April 1, 2017. Outstanding borrowings in excess of the borrowing base must be repaid immediately or we must pledge additional oil andgas properties or other assets as collateral. We do not currently have any substantial unpledged assets and we may not have the financial resources to makeany mandatory principal payments. In addition, a reduction of the borrowing base could also cause us to fail to be in compliance with the financial covenantsdescribed below. The borrowing base will be automatically reduced in connection with any sales of producing properties with a market value of 5% or moreof our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing basecan never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the credit facility bear interest at (a) the greater of (1) thereference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as thedaily one-month LIBOR plus, in each case, (b) 0.75%—1.75%, depending on the utilization of the borrowing base, or, if we elect LIBOR plus1.75%—2.75%, depending on the utilization of the borrowing base. At December 31, 2016, the interest rate on the credit facility was 3.27% based on 1-month LIBOR borrowings and level of utilization.52Table of ContentsSubject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2018. Interest is payable quarterly onreference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, topermanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility aresecured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material propertyand assets. The collateral is required to include properties comprising at least 90% of the PV-10 of our proven reserves. We have also granted our lenders asecurity interest in our headquarters building and a ranch that we own in West Texas.Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required tomaintain a current ratio, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. We are alsorequired as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 4.00 to 1.00. The current ratio is defined as the ratio ofconsolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing basewhich is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arisingfrom the application of ASC 815 and ASC 410-20 and current liabilities exclude the current portion of long-term debt and any liabilities representing avaluation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX toconsolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, EBITDAX is defined as the sumof consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise or margin taxes, depreciation, amortization, depletionand other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC 815 and ASC 410-20 plus all realized net cashproceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred in connection with the negotiation, execution, deliveryand performance of the Credit Facility plus expenses incurred in connection with any acquisition permitted under the Credit Facility plus expenses incurredin connection with any offering of senior unsecured notes, subordinated debt or equity plus up to $1.0 million of extraordinary expenses in any 12-monthperiod plus extraordinary losses minus all non-cash items of income which were included in determining consolidated net income, including all non-cashitems resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expensesincurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscalquarters ended on the calculation date. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associatedwith the office building, Raven Drilling’s rig loan and obligations with respect to surety bonds and derivative contracts.At December 31, 2016, we were in compliance with all of our debt covenants. As of December 31, 2016, the interest coverage ratio was 10.49 to 1.00, thetotal debt to EBITDAX ratio was 2.32 to 1.00, and our current ratio was 1.64 to 1.00.The credit facility contains a number of covenants that, among other things, restrict our ability to: •incur or guarantee additional indebtedness;•transfer or sell assets;•create liens on assets;•engage in transactions with affiliates other than on an “arm’s length” basis;•make any change in the principal nature of our business; and•permit a change of control.The credit facility also contains certain additional covenants including:•100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and•if the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to payamounts outstanding under the credit facility.The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default andcross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. 53Table of ContentsRig Loan Agreement On September 19, 2011 Raven Drilling entered into a rig loan agreement, secured by our Oilwell 2000 HP diesel electric drilling rig (the“Collateral”). The original principal amount of the note was $7.0 million and bears interest at 4.26%. The note is payable in monthly interest and principalpayments in the amount of $179,695. Subject to earlier prepayment provisions and events of default, the stated maturity date of the note is February 14,2017. As of December 31, 2016, $0.5 million, was outstanding under the rig loan agreement. This loan was repaid in full in March 2017.Real Estate Lien Note We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. Thenote bears interest for five years at a fixed rate of 4.25% and is payable in monthly installments of $34,354. Beginning August 20, 2018, the interest rate willadjust to the current bank prime rate plus 1.00% with a maximum rate of 7.25%. The maturity date of the note is July 20, 2023. As of December 31, 2015 and2016, $4.1 million and $3.9 million, respectively, were outstanding on the note. Hedging ActivitiesOur results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedgingour production through swaps, options and other commodity derivative instruments. We have entered into NYMEX-based fixed price commodity swaparrangements on approximately 70% of the oil production of our estimated net proved developed producing reserves (as of December 31, 2016) throughDecember 31, 2017, 77% for 2018 and 64% for 2019. We have also entered into a NYMEX-based collar on approximately 56% of the gas production of ourestimated net proved developed producing reserves (as of December 31, 2016) through December 31, 2017 and a 500 Bopd Midland-Cushing oil pricedifferential swap at ($0.65)/Bbl.The Company’s derivative contracts consist of NYMEX-based fixed price swaps, basis differential swaps and collar contracts. Under fixed price swaps,we receive a fixed price for our production and pay a variable market price to the contract counter-party. Collar contracts combine a long put, a short put anda short call. Under a collar, we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price isbelow the floor price (short put).By removing a portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the potential effects ofchanging commodity prices on our cash flow from operations. However, when prevailing market prices are higher than our contract prices, we will not realizeincreased cash flow on the portion of the production that has been hedged. We have sustained, and in the future will sustain losses on our derivativecontracts when market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustaingains on our commodity derivative contracts. For the year ended December 31, 2016, we incurred a loss of $18.0 million, consisting of a gain of $1.8 millionon our closed contracts and a loss of $19.8 million related to our open contract positions. For the year ended December 31, 2015, we incurred a gain of $19.3million, consisting of a gain of $9.5 million on closed contracts and a gain of $9.8 million related to our open contract positions. For the year endedDecember 31, 2014, we incurred a net gain of $25.2 million, consisting of a gain of $0.3 million on our closed contracts and a gain of $24.9 million related toour open contract positions. If the disparity between our contract prices and market prices continues, we will sustain gains or losses on our derivativecontracts. While gains and losses resulting from the periodic mark to market of our open contracts do not impact our cash flow from operations, gains andlosses from settlements of our closed contracts do impact our cash flow from operations. In addition, as our derivative contracts expire over time, we expectto enter into new derivative contracts at then-current market prices. If the prices at which we hedge future production are significantly lower than our existingderivative contracts, our future cash flow from operations would likely be materially lower. In addition, borrowings under our credit facility bear interest atfloating rates. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meetdebt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our drilling opportunitieswhich, in turn, will be dependent upon the level of our production volumes and commodity prices.See “—Quantitative and Qualitative Disclosures about Market Risk—Hedging Sensitivity” for further information.Net Operating Loss CarryforwardsAt December 31, 2016, we had, subject to the limitation discussed below, $230.5 million of net operating loss carryforward for tax purposes. The losscarryforward will expire through 2036, if not utilized. 54Table of ContentsUncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10 “Income Taxes”.Therefore, we have established a valuation allowance of $137.8 million for deferred tax assets at December 31, 2016.Related Party TransactionsWe have adopted a policy that transactions between us and our officers, directors, principal stockholders, or affiliates of any of them, will be on terms noless favorable to us than can be obtained on an arm’s length basis in transactions with third parties and must be approved by our audit committee. There wereno related party transactions in 2014, 2015 or 2016. Critical Accounting Policies The preparation of financial statements in conformity with U.S. generally accepted accounting principles (“GAAP”) requires that management applyaccounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financialstatements. The following represents those policies that management believes are particularly important to the financial statements and that require the use ofestimates and assumptions to describe matters that are inherently uncertain. Full Cost Method of Accounting for Oil and Gas Activities. SEC Regulation S-X Rule 4-10 and ASC 932 defines the financial accounting and reportingstandards for companies engaged in oil and gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We havechosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We alsocapitalize internal costs that can be directly identified with our acquisition, exploration and development activities but do not include any costs related toproduction, general corporate overhead or similar activities. Sales of oil and gas properties are treated as a reduction of the full cost pool with no gain or lossbeing recognized, except under certain circumstances. Under the successful efforts method, geological and geophysical costs and costs of carrying andretaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged toexpense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basisversus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and gas properties under the successful efforts method.As a result, our financial statements will differ from those of companies that apply the successful efforts method since we will generally reflect a higher levelof capitalized costs as well as a higher depreciation, depletion and amortization rate on our oil and gas properties. At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under thesuccessful efforts method. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity pricesbecause the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. We have experiencedthis situation several times over the years. Our oil and gas reserves have a relatively long life. However, temporary drops in commodity prices can have amaterial impact on our business including impact from impairment testing procedures associated with the full cost method of accounting as discussed below. Under full cost accounting rules, the net capitalized cost of oil and gas properties, less related deferred taxes, may not exceed a “ceiling limit” which isbased upon the present value of estimated future net cash flows from proved reserves on a pool by pool basis, discounted at 10%, plus the lower of cost or fairmarket value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of oil and gas properties exceedthe ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This charge does not impact cashflow from operating activities, but does reduce our stockholders’ equity and reported earnings. The risk that we will be required to write down the carryingvalue of oil and gas properties increases when oil and gas prices are depressed. In addition, write-downs may occur if we experience substantial downwardadjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gasprices may have increased the ceiling applicable to the subsequent period. We apply the full cost ceiling test on a quarterly basis on the date of the latestbalance sheet presented.Estimates of Proved Oil and Gas Reserves. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SECguidelines. The accuracy of a reserve estimate is a function of: • the quality and quantity of available data; • the interpretation of that data; • the accuracy of various mandated economic assumptions; and55Table of Contents • the judgment of the persons preparing the estimate. Our proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by theengineering and operations departments of Abraxas. Reserve estimates were made by our independent petroleum engineers. Estimates prepared by other thirdparties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ fromfuture actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testingand production after the date of an estimate may justify material revisions to the estimate. You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance withSEC requirements, we based the estimated discounted future net cash flows from proved reserves on costs on the date of the estimate and for the years endedDecember 31, 2014, 2015 and 2016 oil and gas prices were based on the average 12-month first-day-of-the-month pricing. Actual future prices and costs maybe materially higher or lower than the prices and costs used in the estimate. The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&Aexpense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for andproduce higher cost fields. Asset Retirement Obligations. The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset’sretirement obligation is recorded in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of therelated long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the relatedasset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and weamortize these costs as a component of our depletion expense. Accounting for Derivatives. Gains or losses are determined by actual derivative settlements during the period and on the periodic mark to marketvaluation of derivative contracts in place. The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil andgas prices realized in our operations. We have elected not to apply hedge accounting to our derivative contracts. As a result, fluctuations in the market valueof the derivative contract are recognized in earnings during the current period. Our derivative contracts consisted of commodity swaps and three way collarsand fixed price swaps in 2015 and fixed price swaps, basis swaps and a costless collar in 2016. Due to the volatility of oil and gas prices, our financialcondition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2015 and2016, the net market value of our commodity derivatives was a net asset of $27.4 million and a liability of $9.0 million, respectively.Share-Based Payments. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted toemployees and directors. Additional information about management’s assumptions can be found in Note 5 to the consolidated financial statements. Optionsgranted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. Restricted stock awards areawards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior tothe lapse of the restrictions. The value of such stock is determined using the market price on the grant date and expense is recognized over the vestingperiod. For the years ended December 31, 2014, 2015 and 2016, stock-based compensation was approximately $2.7 million, $3.9 million, and $3.2 million,respectively.New Accounting Standards and Disclosures.See Note 1, "Organization and Significant Accounting Policies," to our consolidated financial statements in Item 8 of this report for a discussion of newaccounting requirements.Item 7A. Quantitative and Qualitative Disclosures about Market RiskCommodity Price Risk As an independent oil and gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital andfuture rate of growth are substantially dependent upon the prevailing prices of oil and gas. Declines in commodity prices will adversely affect our financialcondition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produceeconomically. Prevailing prices for such commodities56Table of Contentsare subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such asglobal, political and economic conditions. Historically, prices received for our oil and gas production have been volatile and unpredictable, and suchvolatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indices fall, the price that we receive for ourproduction will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the productionlevels we attained during the year ended December 31, 2016, a 10% decline in oil and gas prices would have reduced our operating revenue and cash flow byapproximately $5.6 million for the year. If commodity prices remain at their current levels the impact on operating revenues and cash flow, could be muchmore significant. However, we do have derivative contracts in place that will mitigate the impact of low commodity prices.Derivative Instrument Sensitivity At December 31, 2016, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $9.0 million. The fairmarket value of our commodity derivative contracts is sensitive to changes in the market price for oil and gas. When our derivative contract prices are higherthan prevailing market prices, we incur gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur losses. For the year ended December 31, 2016, we recognized a loss of $18.0 million, consisting of a gain of $1.8 million on our closed contracts and a loss of$19.8 million related to our open contract positions. We have not designated any of these derivative contracts as a hedge as prescribed by applicableaccounting rules. Interest Rate Risk We are subject to interest rate risk associated with borrowings under our credit facility. As of December 31, 2016, we had $93.0 million of outstandingindebtedness under our credit facility. Outstanding amounts under the credit facility bear interest at (a) the greater of (1) the reference rate announced fromtime to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, ineach case, (b) 0.75%—1.75%, depending on the utilization of the borrowing base, or, if we elect LIBOR plus 1.75%—2.75%, depending on the utilization ofthe borrowing base. At December 31, 2016, the interest rate on the credit facility was 3.27% based on 1-month LIBOR borrowings and level of utilization. Anincrease in the interest rate of 1% would increase our interest expense by $0.9 million on an annual basis, based on the outstanding balance at December 31,2016.Item 8. Financial Statements and Supplementary Data For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and ProceduresUnder the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and ourChief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer andour Chief Financial Officer believe that the disclosure controls and procedures as of December 31, 2016 were effective to ensure that information we arerequired to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periodsspecified in the SEC’s rules and forms and are effective to ensure that information required to be disclosed by us is accumulated and communicated to ourmanagement, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.Changes in Internal ControlsThere were no changes in our internal control over financial reporting during the year ended December 31, 2016 that materially affected, or arereasonably likely to materially affect, our internal control over financial reporting.Management’s Annual Report on Internal Control Over Financial Reporting57Table of Contents Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financialreporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and implemented by theCompany’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies andprocedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assetsof the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance withgenerally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations ofmanagement and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, useor disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control overfinancial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk thatcontrols may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, weconducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — IntegratedFramework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our managementconcluded that our internal control over financial reporting was effective as of December 31, 2016.The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by BDO USA, LLP, an independentregistered public accounting firm, as stated in their report which is included herein. Item 9B. Other Information None.PART IIIItem10. Directors, Executive Officers and Corporate Governance There is incorporated in this Item 10 by reference to that portion of our definitive proxy statement for the 2017 Annual Meeting of Stockholders whichappears therein under the caption “Election of Directors – Board of Directors and Executive Officers,” “– Code of Ethics” and “– Committees of the Board ofDirectors.” Audit Committee and Audit Committee Financial Expert The Audit Committee of our board of directors consists of Brian L. Melton., W. Dean Karrash, Paul A. Powell, Jr. and Jerry J. Langdon. The board ofdirectors has determined that each of the members of the Audit Committee is independent as determined in accordance with the listing standards of TheNASDAQ Stock Market and Item 407(a) of Regulation S-K. In addition, the board of directors has determined that Brian L. Melton and W. Dean Karrash, asdefined by SEC rules, are audit committee financial experts. Section 16(a) Compliance Section 16(a) of the Exchange Act requires our directors and executive officers and persons who own more than 10% of a registered class of Abraxasequity securities to file with the SEC and The NASDAQ initial reports of ownership and reports of changes in ownership of Abraxas common stock. Officers,directors and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all such forms they file. Based solely on a review ofthe copies of such reports furnished to us and written representations that no other reports were required, we believe that all our directors and executiveofficers complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act during 2016. Item 11. Executive Compensation There is incorporated in this Item 11 by reference that portion of our definitive proxy statement for the 2017 Annual Meeting of Stockholders whichappears therein under the captions “Election of Directors – Committees of the Board of Directors” and “Executive Compensation.” 58Table of ContentsItem 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters There is incorporated in this Item 12 by reference that portion of our definitive proxy statement for the 2017 Annual Meeting of Stockholders whichappears therein under the caption “Securities Holdings of Principal Stockholders, Directors, Nominees and Officers.”Item 13. Certain Relationships and Related Transactions, and Director Independence There is incorporated in this Item 13 by reference that portion of our definitive proxy statement for the 2017 Annual Meeting of Stockholders whichappears therein under the captions “Certain Relationship and Related Party Transactions” and “Election of Directors – Director Independence.” Item 14. Principal Accountant Fees and Services There is incorporated in this Item 14 by reference that portion of our definitive proxy statement for the 2017 Annual Meeting of Stockholders whichappears therein under the caption “Principal Auditor Fees and Services.”59Table of ContentsPART IV Item 15. Exhibits and Financial Statement Schedules (a)1. Consolidated Financial Statements Page Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements F-2 Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting F-3 Consolidated Balance Sheets at December 31, 2015 and 2016 F-4 Consolidated Statements of Operations for the years ended December 31, 2014, 2015 and 2016 F-6 Consolidated Statements of Other Comprehensive Income (Loss) for the years endedDecember 31, 2014, 2015 and 2016 F-7 Consolidated Statements of Stockholders’ Equity (Deficit) for the years endedDecember 31, 2014, 2015 and 2016 F-8 Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2015 and 2016 F-9 Notes to Consolidated Financial Statements F-11 (a)2. Financial Statement Schedules All schedules have been omitted because they are not required, not applicable, or the information required is included in the Consolidated FinancialStatements or related notes thereto. (a)3. Exhibits The following Exhibits have previously been filed by the Registrant or are included following the Index to Exhibits. Exhibit Number Description 3.1Articles of Incorporation of Abraxas dated August 30, 1990. (Filed as Exhibit 3.1 to our Registration Statement on Form S-4, No. 33-36565. (the “S-4Registration Statement”)). 3.2Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration Statement). 3.3Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement). 3.4Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on Form S-3, No. 333-00398). 3.5Articles of Amendment to the Articles of Incorporation of Abraxas dated as of August 12, 2000. (Filed as Exhibit 3.5 to our Annual Report on Form10-K filed on April 2, 2001). 3.6Certificate of Correction dated February 24, 2011 (Filed as Exhibit 3.6 to our Annual Report on Form 10-K filed on March 15, 2012).3.7Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.1 to our Current Report on Form 8-K filed on November 17, 2008). 4.1Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement). 4.2Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to our Annual Report on Form 10-K filed on March 31, 1995). 60Table of Contents*10.1Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to our Registration Statement on Form S-4, No. 333-18673 filed onDecember 24, 1996). *10.2Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.4 to our Annual Report on Form 10-K filedMarch 14, 2007). *10.3Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19 to the Registration Statement on Form S-1, No. 333-95281 filed on January 24, 2000 (the “2000 S-1 Registration Statement”)). *10.4Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the Registration Statement on Form S-3, No. 333-127480 filed on September 16, 2005 (the “S-3 Registration Statement”)). *10.5Employment Agreement between Abraxas and William H. Wallace. (Filed as Exhibit 10.27 to the S-3 Registration Statement). *10.6Employment Agreement between Abraxas and G. William Krog, Jr. (Filed as Exhibit 10.9 to our Annual Report on Form 10-K filed March 15, 2012). *10.7Employment Agreement between Abraxas and Geoffrey R. King (Filed as Exhibit 10.9 to our Annual Report on Form 10-K filed March 18, 2013). *10.8Amended and Restated Abraxas Petroleum Corporation Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Appendix B to ourProxy Statement filed on April 2, 2015). *10.9Form of Stock Option Agreement under the Abraxas Petroleum Corporation Amended and Restated 2005 Non-Employee Directors Long-TermEquity Incentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed June 6, 2005). *10.10Abraxas Petroleum Corporation Senior Management Incentive Bonus Plan 2006. (Filed as Exhibit 10.17 to our Annual Report on Form 10-K filedMarch 23, 2006). *10.11Amended and Restated Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan. (Filed as Appendix A to our ProxyStatement filed on April 6, 2016). *10.12Form of Employee Stock Option Agreement under the Amended and Restated Abraxas Petroleum Corporation 2005 Employee Long-Term EquityIncentive Plan. (Filed as Exhibit 10.2 to our Current Report on Form 8-K filed August 26, 2006).*10.13Form of Restricted Stock Agreement under the Amended and Restated Abraxas Petroleum Corporation 2005 Employee Long-Term Equity IncentivePlan (Filed as Exhibit 10.1 to our Annual Report on Form 10-K filed on March 13, 2015). 10.14Third Amended and Restated Credit Agreement dated as of June 11, 2014 among Abraxas Petroleum, as Borrower, the lenders party thereto andSociété Générale, as Administrative Agent and as Issuing Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K/A filed on June 13,2014). 10.15Promissory Note dated November 13, 2008 by Abraxas Properties Incorporated and Abraxas Petroleum Corporation, payable to the order of PlainsCapital Bank, as Lender. (Filed as Exhibit 10.1 to our Current Report on Form 8-K filed on August 8, 2014.)10.16Second Modification, Renewal and Extension of Promissory Note and Deed of Trust Liens by and between Plains Capital Bank, Abraxas PropertiesCorporation and Abraxas Petroleum Corporation effective March 13, 2013. (Previously filed as Exhibit 10.2 to our Current Report on Form 8-K filedon August 8, 2014).10.17Third Modification, Renewal and Extension of Promissory Note and Deed of Trust Liens by and between Plains Capital Bank, Abraxas PropertiesIncorporated and Abraxas Petroleum Corporation effective as of July 13, 2013. (Previously filed as Exhibit 10.3 to our Current Report on Form 8-Kfiled on August 8, 2014).61Table of Contents10.18Amendment No. 2 to Third Amended and Restated Credit Agreement dated as of April 20, 2016 among Abraxas Petroleum, as Borrower, the lendersparty thereto and Société Générale, as Administrative Agent and as Issuing Lender (Previously filed as Exhibit 10.1 to our Current Report on Form 8-K filed on April 20, 2016). 14.1Abraxas Petroleum Corporation Code of Business Conduct and Ethics. (Filed as Exhibit 14.1 to our Annual Report on Form 10-K filed March 22,2006). 21.1Subsidiaries of Abraxas. (Previously filed as Exhibit 21.1 to our Annual Report on Form 10-K filed on March 15, 2016).23.1Consent of BDO USA, LLP. (Filed herewith). 23.2Consent of DeGolyer and MacNaughton. (Filed herewith). 31.1Certification – Chief Executive Officer. (Filed herewith). 31.2Certification – Chief Financial Officer. (Filed herewith). 32.1Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(Filed herewith).32.2Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(Filed herewith). 99.1 Report of DeGolyer and MacNaughton with respect to oil and reserves of Abraxas Petroleum. (Filed herewith). *Management Compensatory Plan or Agreement.Item 16. 10-K SummaryNoneINDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Abraxas Petroleum Corporation and Subsidiaries Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements F-2 Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting F-3 Consolidated Balance Sheets at December 31, 2015 and 2016 F-4 Consolidated Statements of Operations for the years ended December 31, 2014, 2015 and 2016 F-6 Consolidated Statements of Other Comprehensive Income (Loss) for the years ended December 31, 2014,2015 and 2016 F-7 Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2014,2015 and 2016 F-8 Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2015 and 2016 F-9 Notes to Consolidated Financial Statements F-11 All schedules are omitted because they are not required, are not applicable or the information required is included in the Consolidated Financial Statementsor the related notes thereto.62Table of ContentsReport of Independent Registered Public Accounting Firm Board of Directors and StockholdersAbraxas Petroleum CorporationSan Antonio, TexasWe have audited the accompanying consolidated balance sheets of Abraxas Petroleum Corporation as of December 31, 2015 and 2016 and the relatedconsolidated statements of operations, comprehensive income (loss), stockholders’ equity (deficit), and cash flows for each of the three years in the periodended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion onthese financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used andsignificant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide areasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Abraxas PetroleumCorporation at December 31, 2015 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31,2016, in conformity with accounting principles generally accepted in the United States of America.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Abraxas PetroleumCorporation's internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 16, 2017 expressed anunqualified opinion thereon./s/ BDO USA, LLPSan Antonio, TexasMarch 16, 2017F-63Table of ContentsReport of Independent Registered Public Accounting Firm Board of Directors and StockholdersAbraxas Petroleum CorporationSan Antonio, TexasWe have audited Abraxas Petroleum Corporation’s internal control over financial reporting as of December 31, 2016, based on criteria established in InternalControl – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). AbraxasPetroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of theeffectiveness of internal control over financial reporting, included in the accompanying Item 9A, “Management’s Annual Report on Internal Control OverFinancial Reporting”. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all materialrespects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, andtesting and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such otherprocedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate.In our opinion, Abraxas Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31,2016, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheetsof Abraxas Petroleum Corporation as of December 31, 2015 and 2016, and the related consolidated statements of operations, comprehensive income (loss),stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2016 and our report dated March 16, 2017expressed an unqualified opinion thereon. /s/ BDO USA, LLP San Antonio, TexasMarch 16, 2017F-64Table of ContentsABRAXAS PETROLEUM CORPORATIONCONSOLIDATED BALANCE SHEETSASSETS December 31, 2015 2016 (In thousands)Current assets: Cash and cash equivalents $3,540 $—Accounts receivable: Joint owners - net 1,552 677Oil and gas production sales 6,713 11,595Other 1,241 1,252 9,506 13,524 Derivative assets 18,902 54Assets held for sale — 9,685Other current assets 726 676Total current assets 32,674 23,939 Property and equipment: Oil and gas properties, full cost method of accounting: Proved 787,683 794,634Other property and equipment 41,444 38,569Total 829,127 833,203Less accumulated depreciation, depletion, amortization and impairment (604,289) (696,892)Total property and equipment, net 224,838 136,311 Deferred financing fees, net 1,642 818Derivative asset 8,463 —Other assets 255 580Total assets $267,872 $161,648See accompanying notes to consolidated financial statementsF-65Table of ContentsABRAXAS PETROLEUM CORPORATIONCONSOLIDATED BALANCE SHEETS (CONTINUED)LIABILITIES AND STOCKHOLDERS’ EQUITY December 31, 2015 2016 (In thousands, except per share andshare data)Current liabilities: Accounts payable $24,825 $18,397Joint interest oil and gas production payable 7,177 8,937Accrued interest 115 44Other accrued expenses 622 571Derivative liability — 2,382Current maturities of long-term debt 2,330 786Total current liabilities 35,069 31,117 Long-term debt – less current maturities 138,402 96,616Derivative liability — 6,630Other liabilities 257 157Future site restoration 9,679 8,623Total liabilities 183,407 143,143 Commitments and contingencies (Note 7) Stockholders’ Equity: Preferred stock, par value $.01 per share – authorized 1,000,000 shares; -0- shares issued and outstanding — —Common stock, par value $.01 per share – authorized 200,000,000 shares; issued and outstanding 106,346,678and 135,094,017, respectively 1,063 1,351Additional paid-in capital 313,852 343,982Accumulated deficit (230,450) (326,828)Total stockholders’ equity 84,465 18,505Total liabilities and stockholders’ equity $267,872 $161,648See accompanying notes to consolidated financial statementsF-66Table of ContentsABRAXAS PETROLEUM CORPORATIONCONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31, 2014 2015 2016 (In thousands, except per share data)Revenues: Oil and gas production revenues $133,701 $67,002 $56,493Other 75 28 62 133,776 67,030 56,555Operating costs and expenses: Lease operating 25,875 23,074 18,205Production taxes 11,462 6,679 5,454Rig expense — — 664Depreciation, depletion, and amortization 43,139 38,721 24,431Proved property impairment — 128,573 67,626General and administrative (including stock-based compensation of $2,703, $3,912 and$3,194, respectively) 13,378 11,788 13,562 93,854 208,835 129,942Operating income (loss) 39,922 (141,805) (73,387) Other (income) expense: Interest income (2) (2) (1)Interest expense 2,570 3,906 4,319Amortization of deferred financing fees 934 643 1,019(Gain) on sale of properties — — (374)(Gain) loss on derivative contracts (25,237) (19,301) 18,028Other (7) 318 — (21,742) (14,436) 22,991Income (loss) from continuing operations before income tax 61,664 (127,369) (96,378)Income tax benefit 287 279 —Net income (loss) from continuing operations 61,951 (127,090) (96,378)Net income (loss) from discontinued operations - net of tax 1,318 (20) — $63,269 $(127,110) $(96,378) Net income (loss) per common share - basic Continuing operations $0.63 $(1.21) $(0.79) Discontinued operations 0.01 — — $0.64 $(1.21) $(0.79)Net income (loss) per common share - diluted Continuing operations $0.61 $(1.21) $(0.79) Discontinued operations 0.01 — — $0.62 $(1.21) $(0.79)Weighted average shares outstanding: Basic 98,835 104,605 122,132Diluted 101,468 104,605 122,132See accompanying notes to consolidated financial statementsF-67Table of ContentsABRAXAS PETROLEUM CORPORATIONCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Years Ended December 31, 2014 2015 2016 (In thousands)Net income (loss) $63,269 $(127,110) $(96,378)Other comprehensive income (loss): Foreign currency translation adjustment 607 — —Other comprehensive income (loss) 607 — —Comprehensive income (loss) $63,876 $(127,110) $(96,378) See accompanying notes to consolidated financial statementsF-68Table of ContentsABRAXAS PETROLEUM CORPORATIONCONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)(In thousands except number of shares) Common Stock Shares Amount AdditionalPaid inCapital AccumulatedDeficit Accumulated OtherComprehensiveIncome (Loss) TotalBalance at December 31, 201392,906,049 $929 $253,193 $(166,609) $(607) $86,906Net income— — — 63,269 — 63,269Foreign currency translation adjustment— — — — 607 607Stock issuance11,500,000 115 53,640 — — 53,755Stock-based compensation— — 2,703 — — 2,703Stock options exercised238,157 3 252 — — 255Restricted stock issued, net of forfeitures1,542,472 15 (15) — — —Balance at December 31, 2014106,186,678 1,062 309,773 (103,340) — 207,495Net loss— — — (127,110) — (127,110)Stock-based compensation— — 3,912 — — 3,912Stock options exercised164,400 1 167 — — 168Restricted stock issued, net of forfeitures(5,077) — — — — —Balance at December 31, 2015106,346,001 1,063 313,852 (230,450) — 84,465Net loss— — — (96,378) — (96,378)Stock issuance28,750,000 287 26,848 — — 27,135Stock-based compensation— — 3,194 — — 3,194Stock issued for compensation41,102 — 40 — — 40Stock options exercised55,716 1 48 — — 49Restricted stock forfeitures(98,802) — — — — —Balance at December 31, 2016135,094,017 $1,351 $343,982 $(326,828) $— $18,505See accompanying notes to consolidated financial statementsF-69Table of ContentsABRAXAS PETROLEM CORPORATIONCONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31, 2014 2015 2016 (In thousands)Operating Activities Net income (loss) $63,269 $(127,110) $(96,378)Income (loss) from discontinued operations 1,318 (20) —Income (loss) from continuing operations 61,951 (127,090) (96,378)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Gain on sale of properties — — (374)Net (gain) loss on derivative contracts (25,237) (19,301) 18,028Derivative contract settlements 361 9,495 1,790Monetization of derivative contracts 152 4,610 14,370Depreciation, depletion, and amortization 43,139 38,721 24,431Proved property impairment — 128,573 67,626Accretion of future site restoration 559 565 491Amortization of deferred financing fees 934 643 1,019Stock-based compensation 2,703 3,912 3,194Non-cash compensation — — 40Changes in operating assets and liabilities: Accounts receivable - net of allowance 11,881 12,097 (4,018)Other assets and liabilities (2,717) 1,466 627Accounts payable 1,596 (45,970) (3,535)Accrued expenses (860) (722) (439)Net cash provided by continuing operations 94,462 6,999 26,872Net cash provided by (used in) discontinued operations 1,741 (20) —Net cash provided by operating activities 96,203 6,979 26,872 Investing Activities Capital expenditures, including purchasesand development of properties (192,799) (69,391) (31,663)Proceeds from the sale of oil and gas properties 5,999 138 13,570Proceeds from the sale of non-oil and gas properties — — 4,022Net cash used in continuing operations (186,800) (69,253) (14,071)Net cash provided by discontinued operations 332 — —Net cash used in investing activities (186,468) (69,253) (14,071) Financing Activities Proceeds from exercise of stock options 255 168 49Proceeds from issuance of common stock, net of offering costs 53,755 — 27,135Proceeds from long-term borrowings 82,000 68,007 22,000Payments on long-term borrowings (47,143) (6,064) (65,330)Deferred financing fees (1,010) (69) (195)Net cash provided by (used in) continuing operations 87,857 62,042 (16,341)Net cash provided by discontinued operations 975 — —Net cash provided by (used in) financing activities 88,832 62,042 (16,341) F-70Table of Contents Years Ended December 31, 2014 2015 2016 (In thousands)Decrease in cash (1,433) (232) (3,540)Cash and cash equivalents at beginning of year 5,205 3,772 3,540Cash and cash equivalents at end of year $3,772 $3,540 $— Supplemental disclosures of cash flow information: Interest paid $1,970 $3,298 $3,899 Income taxes paid $— $— $—Non-cash investing activities: Asset retirement obligation cost and liabilities $198 $30 $285Properties classified as held for sale $——$— $9,685Asset retirement obligations associated with property acquisitions and dispositions $(406) $410 $(1,832)See accompanying notes to consolidated financial statementsF-71Table of ContentsABRAXAS PETROLEUM CORPORATIONNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1. Organization and Significant Accounting PoliciesNature of OperationsWe are an independent energy company primarily engaged in the acquisition, exploitation, development and production of oil and gas in theUnited States. Our oil and gas assets are located in three operating regions in the United States, the Rocky Mountain, Permian Basin and South Texas.The terms “Abraxas,” “Abraxas Petroleum,” “we,” “us,” “our” or the “Company” refer to Abraxas Petroleum Corporation and all of its subsidiaries,including Raven Drilling LLC (“Raven Drilling”). Rig Accounting In accordance with SEC Regulation S-X, no income is recognized in connection with contractual drilling services performed in connection withproperties in which the Company or its affiliates holds an ownership, or other economic interest. Any income not recognized as a result of this limitation iscredited to the full cost pool and recognized through lower amortization as reserves are produced. Use of EstimatesThe preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America(“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingentassets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reportingperiod. Actual results could differ from those estimates.The process of estimating oil and gas reserves in accordance with SEC requirements is complex and involves decisions and assumptions inevaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oiland gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from thoseestimated. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates ofproved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which arebeyond our control.The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oiland gas properties, the fair value of assets and liabilities acquired in business combinations, derivative contracts, asset retirement obligations, accrued oil andgas revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ fromthose estimates.Concentration of Credit RiskFinancial instruments which potentially expose the Company to credit risk consist principally of trade receivables and derivativecontracts. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing creditevaluations and, generally, requires no collateral from its customers. The counterparties to our derivative contracts are the same financial institutions fromwhich we have outstanding debt; accordingly, we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well asthe current overall financial condition of the counterparties.The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by theCompany to be of high credit quality.Cash and EquivalentsCash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less. F-72Table of ContentsAccounts ReceivableAccounts receivable are reported net of an allowance for doubtful accounts of approximately $296,000 and $228,000 at December 31, 2015 and2016, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts.Accounts are charged off when collection efforts have failed and the account is deemed uncollectible.Industry Segment and Geographic InformationThe Company operates in one industry segment, which is the exploration, development and production of oil and gas with all of the Company’soperational activities having been conducted in the U.S. The Company’s current operational activities and the Company’s consolidated revenues aregenerated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.Oil and Gas PropertiesThe Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costsassociated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation,depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on theunit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to thelower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based onunescalated prices discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unprovedproperties included in the costs being amortized, if any, less related income taxes. Costs in excess of the present value of estimated future net revenues arecharged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties for full cost accountingcompanies with proceeds accounted for as an adjustment of capitalized cost. An exception to this rule occurs when the adjustment to the full cost pool resultsin a significant alteration of the relationship between capitalized cost and proved reserves. The Company applies the full cost ceiling test on a quarterly basison the date of the latest balance sheet presented. For the year ended December 31, 2015, our capitalized cost of oil and gas properties exceeded the presentvalue of our estimated proved reserves by $128.6 million, resulting in the recognition of a proved property impairment of $128.6 million. As of December 31,2016, our capitalized cost of oil and gas properties did not exceed the present value of our estimated proved reserves. However, we incurred proved propertyimpairments in each of the first three quarters of 2016 in the amount of $67.6 million. The impairment calculations did not consider the impact of ourcommodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.Other Property and EquipmentOther property and equipment are recorded on the basis of cost. Depreciation of other property and equipment is provided over the estimated usefullives using the straight-line method. Major renewals and improvements are recorded as additions to the property and equipment accounts. Repairs that donot improve or extend the useful lives of assets are expensed. Assets Held for SaleThe Company entered into an agreement to sell certain non-core assets in late 2016 that are presented separately as “Assets held for sale" in theconsolidated balance sheet at December 31, 2016. Assets held for sale were measured at the lower of its carrying amount or estimated fair value less costs tosell. The amount allocated to assets held for sale were recorded as a reduction to the full cost pool. The transaction closed and proceeds were received onJanuary 3, 2017. See Note 14. Subsequent Events.Estimates of Proved Oil and Gas Reserves Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserveestimate is a function of: •the quality and quantity of available data; •the interpretation of that data;•the accuracy of various mandated economic assumptions; and•the judgment of the persons preparing the estimate. F-73Table of ContentsOur proved reserve information included in this report was based on studies performed by our independent petroleum engineers assisted by theengineering and operations departments of Abraxas. Estimates prepared by other third parties may be higher or lower than those included herein. Becausethese estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from thequantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may cause materialrevisions to the estimate. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on the average of oil and gasprices based on the unweighted average 12 month first-day-of-month pricing. Future prices and costs may be materially higher or lower than these prices andcosts which would impact the estimated value of our reserves.The estimates of proved reserves materially impact depreciation, depletion and amortization, or DD&A expense. If the estimates of proved reservesdecline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower commodity prices, whichmay make it uneconomic to drill for and produce higher cost fields. Derivative Instruments and Hedging ActivitiesThe Company enters into agreements to hedge the risk of future oil and gas price fluctuations. Such agreements are in the form of fixed price swapsand three way collars, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. While it is never management’s intentionto hold or issue derivative instruments for speculative trading purposes, conditions could arise where actual production is less than estimated which could,result in overhedged volumes.All derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities basedon their anticipated settlement date. The derivative instruments the Company utilizes are based on index prices that may and often do differ from the actualoil and gas prices realized in its operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualifyfor hedge accounting rules as prescribed by Accounting Standards Codification (“ASC”) 815. Accordingly, the Company does not account for its derivativeinstruments as cash flow hedges for financial reporting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earningsand included in net gains (losses) on commodity derivative contracts in the Consolidated Statements of Operations.Fair Value of Financial InstrumentsThe Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments ismaterially different from the carrying value. The carrying value of those financial instruments that are classified as current approximates fair value because ofthe short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are noavailable quoted market prices, market prices for similar instruments.Share-Based Payments Options granted are valued at the date of grant and expense is recognized over the vesting period. The Company currently utilizes a standardoption pricing model (Black-Scholes) to measure the fair value of stock options granted to employees and directors. Restricted stock awards are awards ofcommon stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapseof the restrictions. The value of such restricted stock is determined using the market price on the grant date and expense is recorded over the vesting period.For the years ended December 31, 2014, 2015 and 2016, stock-based compensation was approximately $2.7 million, $3.9 million and $3.2 million,respectively. Restoration, Removal and Environmental LiabilitiesThe Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials intothe environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at varioussites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing conditioncaused by past operations and that have no future economic benefit are expensed.Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can bereasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliablydeterminable.F-74Table of ContentsThe fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalizedby increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period and the capitalized cost isdepreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment anddismantlement in our full cost amortization base and we amortize these costs as a component of our depletion expense in the accompanying consolidatedfinancial statements. Each year, the Company reviews, and to the extent necessary, revises its asset retirement obligation estimates.The following table summarizes the Company’s asset retirement obligations during the two years ended December 31: 2015 2016 (in thousands)Beginning asset retirement obligation $9,495 $9,679New wells placed on production and other 307 119Deletions related to property disposals and plugging costs (793) (1,832)Accretion expense 565 491Revisions 105 166Ending asset retirement obligation $9,679 $8,623Revenue Recognition and Major PurchasersThe Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. TheCompany utilizes the sales method to account for gas production imbalances. Under this method, income is recorded based on the Company’s net revenueinterest in production taken for delivery. The Company had no material gas imbalances at December 31, 2015 and 2016.During 2014, two purchasers accounted for 62% of oil and gas revenues. During 2015, one purchaser accounted for 54% of oil and gas revenues.During 2016, two purchasers accounted for 71% of our oil and gas revenues.Deferred Financing FeesDeferred financing fees are being amortized on the effective yield basis over the term of the related debt arrangements.Income TaxesDeferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carryingamounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities aremeasured using enacted tax rates expected to be in effect with respect to taxable income in the years in which those temporary differences are expected to berecovered or settled. Uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, we have established a valuation allowanceof $137.8 million for deferred tax assets at December 31, 2016. Accounting for Uncertainty in Income Taxes Evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will besustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is tomeasure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A taxposition is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period inwhich the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the firstsubsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense. The Company had nouncertain income tax positions as of December 31, 2016.New Accounting Standards and DisclosuresF-75Table of ContentsIn May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-09, Revenue from Contracts withCustomers ("ASU 2014-09"). The objective of ASU 2014-09 is greater consistency and comparability across industries by using a five-step model torecognize revenue from customer contracts. ASU 2014-09 also contains some new disclosure requirements under GAAP. In August 2015, the FASB issuedAccounting Standards Update No. 2015-14, Deferral of the Effective Date ("ASU 2015-14"). ASU 2015-14 defers the effective date of the new revenuestandard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reportingperiod. In 2016, the FASB issued additional accounting standards updates to clarify the implementation guidance of ASU 2014-09. We are currentlyevaluating the impact, if any, of the standard by comparing historical accounting policies and practices to the new standard and will evaluate guidance fromaccounting regulatory agencies as it becomes available.The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-CreditArrangements. These ASUs require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to bepresented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effectivebeginning January 1, 2016 and have been applied using the retrospective approach. These ASUs did not have a material impact on Abraxas's consolidatedfinancial statements and related disclosures.In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-CreditArrangements”, codifies an SEC staff announcement that entities are permitted to defer and present debt issuance costs related to line-of-credit arrangementsas assets. The ASU clarifies that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequentlyamortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowingson the line-of-credit arrangement. The ASU is effective immediately for both public business entities and non-public entities. Abraxas has elected to followthis presentation guidance.The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, alongwith any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in2017 and can be applied prospectively or retrospectively, with early adoption permitted. We have adopted and applied this standard using the retrospectiveapproach. This ASU did not have an impact on our consolidated financial statements and related disclosures.In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-PeriodAdjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination byeliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognizeadjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment is effective.In February 2016, the FASB issued ASU 2016-02 “Leases," which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." This updaterequires lessees to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balancesheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginningafter December 15, 2018 and interim periods within those fiscal years, with earlier application permitted. This update will be applied using a modifiedretrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financialstatements. We are currently evaluating the effect of this update on our consolidated financial statements and related disclosures.In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-BasedPayment Accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted forand presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, andearly adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's consolidated financial statements.In August 2016, FASB issued amended guidance to address diversity in how certain cash receipts and cash payments are presented and classified inthe statement of cash flows. The amendments provide guidance on the following eight specific cash flow issues: Debt prepayment or debt extinguishmentcosts; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interestrate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceedsfrom the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitizationtransactions; and separately identifiable cash flows and application of the predominance principle.F-76Table of ContentsIn August 2014, the FASB issued updated guidance related to determining whether substantial doubt exists about an entity's ability to continue as agoing concern. The amendment provides guidance for determining whether conditions or events give rise to substantial doubt that an entity has the abilityto continue as a going concern within one year following issuance of the financial statements, and requires specific disclosures regarding the conditions orevents leading to substantial doubt. The updated guidance is effective for annual reporting periods ending after December 15, 2016, and to annual andinterim periods thereafter. Earlier adoption is permitted. The Company has adopted this guidance as of December 31, 2016 and there is no impact on itsconsolidated financial statements.2. Divestiture of PropertiesBeginning in the third quarter of 2012 and continuing through the present, the Company's business plan has been to divest various properties considerednon-core, and primarily non-operated to focus on its core basins in the Eagle Ford, Bakken and Permian Basin. In total the Company divested a number ofnon-core assets for total net proceeds of $169.9 million from 2012-2016. The net proceeds were used to repay outstanding indebtedness under theCompany's credit facility, for capital expenditures and general corporate purposes. 3. Long-Term DebtThe following is a description of the Company’s debt as of December 31, 2015 and 2016, respectively: December 31, 2015 December 31, 2016 (In thousands)Senior secured credit facility $134,000 $93,000Rig loan agreement 2,620 535Real estate lien note 4,112 3,867 140,732 97,402Less current maturities (2,330) (786) $138,402 $96,616Maturities of long-term debt are as follows:Year ending December 31, (In thousands) 2017$786201893,261201927320202852021297Thereafter 2,500 $97,402 Credit Facility We have a senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer toas the credit facility. As of December 31, 2016, $93.0 million was outstanding under the credit facility.The credit facility has a maximum commitment of $300.0 million and availability is subject to a borrowing base. At December 31, 2016, we had aborrowing base of $115.0 million. The borrowing base is determined semi-annually by the lenders based upon our reserve reports, one of which must beprepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base is calculated by thelenders based upon their valuation of our proved reserves securing the facility utilizing these reserve reports and their own internal decisions. In addition, thelenders, in their sole discretion, are able to make one additional borrowing base redetermination during any six-month period between scheduledredeterminations and we are able to request one redetermination during any six-month period between scheduled redeterminations. The next redeterminationwill be effective on April 1, 2017. Outstanding borrowings in excess of the borrowing base must be repaidF-77Table of Contentsimmediately or we must pledge additional oil and gas properties or other assets as collateral. We do not currently have any substantial unpledged assets andwe may not have the financial resources to make any mandatory principal payments. In addition, a reduction of the borrowing base could also cause us to failto be in compliance with the financial covenants described below. The borrowing base will be automatically reduced in connection with any sales ofproducing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which couldreduce the collateral value by 5% or more. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amountsunder the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rateplus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 0.75%—1.75%, depending on the utilizationof the borrowing base, or, if we elect LIBOR plus 1.75%—2.75%, depending on the utilization of the borrowing base. At December 31, 2016, the interest rateon the credit facility was 3.27% based on 1-month LIBOR borrowings and level of utilization.Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is June 30, 2018. Interest is payable quarterlyon reference rate advances and not less than quarterly on LIBOR advances. We are permitted to terminate the credit facility and are able, from time to time, topermanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements.Each of our subsidiaries has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility aresecured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material propertyand assets. The collateral is required to include properties comprising of least 90% of the PV-10 of our proven reserves. We have also granted our lenders asecurity interest in our headquarters building and a ranch that we own in West Texas.Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are requiredto maintain a current ratio, as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio of not less than 2.50 to 1.00. We arealso required as of the last day of each quarter to maintain a total debt to EBITDAX ratio of not more than 4.00 to 1.00. The current ratio is defined as the ratioof consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing basewhich is undrawn but excludes any cash deposited with a counter-party to a hedging arrangement and any assets representing a valuation account arisingfrom the application of ASC 815, Derivatives and Hedging, and ASC 410-20 Asset Retirement Obligations, and current liabilities exclude the current portionof long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratiois defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date. For the purposesof this calculation, EBITDAX is defined as the sum of consolidated net income plus interest expense, oil and gas exploration expenses, income, franchise ormargin taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718, ASC815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts plus expenses incurred inconnection with the negotiation, execution, delivery and performance of the Credit Facility plus expenses incurred in connection with any acquisitionpermitted under the Credit Facility plus expenses incurred in connection with any offering of senior unsecured notes, subordinated debt or equity plus up to$1.0 million of extraordinary expenses in any 12-month period plus extraordinary losses minus all non-cash items of income which were included indetermining consolidated net income, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includestotal interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio oftotal debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date. For the purposes of this calculation, total debt is theoutstanding principal amount of debt, excluding debt associated with the office building and obligations with respect to surety bonds and derivativecontracts.At December 31, 2016 we were in compliance with all of our debt covenants. As of December 31, 2016, the interest coverage ratio was 10.49 to 1.00,the total debt to EBITDAX ratio was 2.32 to 1.00, and our current ratio was 1.64 to 1.00.The credit facility contains a number of other covenants that, among other things, restrict our ability to: •incur or guarantee additional indebtedness;•transfer or sell assets;•create liens on assets;•engage in transactions with affiliates other than on an “arm’s length” basis;•make any change in the principal nature of our business; and•permit a change of control.The credit facility also contains certain additional covenants including:F-78Table of Contents•100% of the net proceeds from any terminations of derivative contracts must be used to repay amounts outstanding under the credit facility; and•If the sum of our cash on hand plus liquid investments exceeds $10.0 million, then the amount in excess of $10.0 million must be used to payamounts outstanding under the credit facility.The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross defaultand cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. As of December 31, 2016 we were in compliance withall of these conditions. Rig Loan Agreement On September 19, 2011, Raven Drilling entered into a rig loan agreement, secured by our Oilwell 2000 HP diesel electric drilling rig (the“Collateral”). The original principal amount of the note was $7.0 million and bears interest at 4.26%. The note is payable in monthly interest and principalpayments in the amount of $179,695. As of December 31, 2015 and 2016, $2.6 million and $0.5 million, respectively, were outstanding under the rig loanagreement. This loan was paid in full in March 2017.Real Estate Lien Note We have a real estate lien note secured by a first lien deed of trust on the property and improvements which serves as our corporate headquarters. Thenote bears interest for five years at a fixed rate of 4.25% and is payable in monthly installments of $34,354. Beginning August 20, 2018, the interest rate willadjust to the current bank prime rate plus 1.00% with a maximum rate of 7.25%. The maturity date of the note is July 20, 2023. As of December 31, 2015 and2016, $4.1 million and $3.9 million, respectively, were outstanding on the note.4. Property and EquipmentThe major components of property and equipment, at cost, are as follows: EstimatedUseful Life December 31, 2015 2016 Years (In thousands)Oil and gas properties — $787,683 $794,634Equipment and other 3-39 18,866 15,227Drilling rig 15 22,578 23,342 829,127 833,203Accumulated depreciation, depletion, amortization and impairment (604,289) (696,892)Net Property and Equipment $224,838 $136,3115. Stock-Based Compensation and Option PlansThe Company’s Amended and Restated 2005 Employee Long-Term Equity Incentive Plan reserves 10.6 million shares of Abraxas common stock,subject to adjustment following certain events. Awards may be in options or shares of restricted stock. Options have a term not to exceed 10 years. Optionsissued under this plan vest according to a vesting schedule as determined by the compensation committee of the Company’s board of directors. Vesting mayoccur upon (1) the attainment of one or more performance goals or targets established by the committee, (2) the optionee’s continued employment or servicefor a specified period of time, (3) the occurrence of any event or the satisfaction of any other condition specified by the committee, or (4) a combination ofany of the foregoing.Stock Options The Company utilizes a standard option pricing model (Black-Scholes) to measure the fair value of stock options granted to employees anddirectors. The fair value for these options was estimated at the date of grant using the following weighted average assumptions for 2014, 2015 and 2016:F-79Table of Contents 2014 2015 2016Weighted average value per option granted during the period $2.44 $2.37 $0.68Assumptions: Forfeiture rate (1) 4.2% 4.5% 4.2%Expected dividend yield (2) —% —% —%Volatility (3) 80.7% 81.1% 71.1%Risk free interest rate (4) 2.05% 1.92% 1.72%Expected life (years) (5) 6.6 7.0 7.0Fair value of options granted (in thousands) $2,666 $3,792 $2,307______________________(1) The estimated future forfeiture rate is based on the Company’s historical forfeiture rate.(2) The dividend yield is based on the fact the Company does not pay any dividends.(3) The volatility is based on the historical volatility of our stock for a period approximating the expected life.(4)The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted.(5)The expected life was derived based on a weighting between (a) the Company’s historical exercise and forfeiture activity and (b) the average midpointbetween vesting and the contractual term.The Company grants options to its officers, directors, and other employees under various stock option and incentive plans.The following table is a summary of the Company’s stock option activity for the three years ended December 31: Options(000s) Weighted averageexercise price Weighted average remaining life Intrinsicvalueper shareOptions outstanding December 31, 2013 5,400 $2.77 Granted 1,091 3.38 Exercised (410) 2.71 Forfeited/Expired (196) 3.08 Options outstanding December 31, 2014 5,885 $2.88 Granted 1,601 3.22 Exercised (164) 1.03 Forfeited/Expired (514) 4.36 Options outstanding December 31, 2015 6,808 $2.89 Granted 2,265 1.02 Exercised (83) 1.40 Forfeited/Expired (836) 2.84 Options outstanding December 31, 2016 8,154 $2.39 6.39 1.70Exercisable at end of year 4,808 4.90 1.93Other information pertaining to the Company’s stock option activity for the three years ended December 31: 2014 2015 2016Weighted average grant date fair value of stock options granted (per share) $2.44 $2.37 $0.68Total fair value of options vested (000’s) $1,718 $2,035 $2,776Total intrinsic value of options exercised (000’s) $932 $124 $39F-80Table of ContentsAs of December 31, 2016, the total compensation cost related to non-vested awards not yet recognized was approximately $2.9 million, which willbe recognized in 2017 through 2020. For the years ended December 31, 2014, 2015 and 2016, we recognized $1.8 million, $2.4 million and $2.0 million,respectively, in stock-based compensation expense relating to options. The following table represents the range of stock option prices and the weighted average remaining life of outstanding options as of December 31,2016: Options outstanding Exercisable Numberoutstanding Weightedaverageremaininglife Weightedaverageexerciseprice Numberexercisable Weightedaverageremaininglife Weightedaverageexerciseprice0.97 - 1.99 3,462,042 6.7 $1.23 1,595,042 3.8 $1.522.00 - 2.99 1,240,350 5.2 $2.35 1,102,063 5.0 $2.353.00 - 3.99 2,765,633 7.0 $3.29 1,438,408 6.3 $3.414.00 - 4.99 585,750 3.6 $4.56 574,750 3.6 $4.565.00 - 5.99 99,000 7.4 $5.39 97,500 7.4 $5.386.00 - 6.28 1,000 7.5 $6.28 500 7.5 $6.28 8,153,775 4,808,263 Restricted Stock AwardsRestricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminatesemployment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date.Compensation expense is recorded over the applicable restricted stock vesting periods. As of December 31, 2016, the total compensation cost related to non-vested awards not yet recognized was approximately $1.9 million, which will be recognized in 2017 through 2020. For the years ended December 31, 2014,2015 and 2016, we recognized $0.9 million, $1.5 million and $1.2 million, respectively, in stock-based compensation expense related to restricted stockawards.The following table is a summary of the Company’s restricted stock activity for the three years ended December 31, 2016: NumberofShares Weightedaveragegrant datefair valueUnvested December 31, 2013 355,240 $3.24Granted 1,582,000 3.49Vested/Released (121,622) 3.64Forfeited (39,528) 3.44Unvested December 31, 2014 1,776,090 $3.43Granted — —Vested/Released (127,729) 3.38Forfeited (5,077) 2.56Unvested December 31, 2015 1,643,284 $3.44Granted — —Vested/Released (52,017) 2.40Forfeited (98,802) 3.63Unvested December 31, 2016 1,492,465 $3.47 Director Stock Awards The 2005 Directors Plan (as amended and restated) reserves 1.9 million shares of Abraxas common stock, subject to adjustment following certainevents. The 2005 Directors Plan provides that each year, at the first regular meeting of the board of directors immediately following Abraxas’ annualstockholder’s meeting, each non-employee director shall be granted or issued awards of 25,000 shares of Abraxas common stock, for participation in boardand committee meetings during the previous calendar year. The maximum annual award for any one person is 100,000 shares of Abraxas common stock oroptions for common stock. IfF-81Table of Contentsoptions, as opposed to shares, are awarded, the exercise price shall be no less than 100% of the fair market value on the date of the award while the optionterms and vesting schedules are at the discretion of the committee. In 2014 and 2015 directors were paid a retainer fee of $40,000. Beginning in 2016, theretainer fee was reduced by 20% and paid one half in cash and one half in Abraxas common stock. The retainer fee for 2016 was $32,000. At December 31, 2016, the Company had approximately 9.0 million shares reserved for future issuance for conversion of its stock options, andincentive plans for the Company’s directors, employees and consultants.6. Income TaxesDeferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reportingpurposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax liabilities and assets are as follows: Years Ended December 31, 2014 2015 2016 (In thousands)Deferred tax liabilities: Hedge contracts $8,114 $9,578 $—Assets held for sale — — 3,390Other 4,458 4,042 4,431Total deferred tax liabilities 12,572 13,620 7,821Deferred tax assets: U.S. full cost pool 3,352 35,689 48,436Capital loss carryforward 12,325 7,767 7,361Depletion carryforward 4,936 5,558 5,216U.S. net operating loss carryforward 50,941 67,531 80,670Alternative minimum tax credit 1,104 757 757Hedge contracts — — 3,135Total deferred tax assets 72,658 117,302 145,575Valuation allowance for deferred tax assets (60,086) (103,682) (137,754)Net deferred tax assets 12,572 13,620 7,821Net deferred tax $— $— $—Significant components of the provision (benefit) for income taxes are as follows: Years ended December 31, 2014 2015 2016 (In thousands)Current: Federal $(276) $(242) $—State (11) (37) — $(287) $(279) $—Deferred: Federal $— $— $— $— $— $—At December 31, 2016, the Company had, subject to the limitation discussed below, $230.5 million of net operating loss carryforwards for U.S. taxpurposes. The U.S. federal loss carryforward will expire in varying amounts from 2022 through 2036, if not utilized. The use of our net operating loss carryforwards will be limited if there is an "ownership change" in our common stock, generally a cumulativeownership change exceeding 50% during a three year period, as determined under Section 382 of the Internal Revenue Code. As of December 31, 2016, wehave not had an ownership change as defined by Section 382. In additionF-82Table of Contentsto any Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards. Therefore, the Company has established avaluation allowance of $60.1 million at December 31, 2014, $103.7 million at December 31, 2015 and $137.8 million at December 31, 2016.The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is: Years ended December 31, 2014 2015 2016 (In thousands)Tax (expense) benefit at U.S. statutory rates (35%) $(22,044) $44,586 $33,732(Increase) decrease in deferred tax asset valuation allowance 15,480 (43,596) (34,072)Alternative minimum tax — 568 —Rate differential for non US income (39) — —State income taxes — — —Accrual of prior year federal taxes (2009 and 2013) 287 37 —Permanent differences (950) (1,371) (1,133)Return to provision estimate revision 4,562 — 1,473Tax benefit related to the sale of Canadian subsidiary 3,501 — —Increase in asset for partnership distribution — — —Other (510) 55 — $287 $279 $—During 2016, the Company increased deferred tax assets by $28.3 million primarily related to increases in the full cost pool assets and net operatingloss carryforward. The deferred tax assets were fully offset by a valuation allowance which was reduced at the same time. As of December 31, 2016, 2015 and 2014, the Company did not have any accrued interest or penalties related to uncertain tax positions. The taxyears 2012 through 2016 remain open to examination by the tax jurisdictions to which the Company is subject. 7. Commitments and ContingenciesOperating LeasesThe Company leases office space in Dickinson, North Dakota, Lusk, Wyoming and Denver, Colorado. During 2014, 2015 and 2016, rent expenseincurred for the Dickinson, North Dakota office was $26,265, $27,165, and $27,840, respectively. The lease expires on October 31, 2018. Rent expenseincurred for the Lusk, Wyoming office for 2014, 2015 and 2016 was $9,000 for each year. The lease expires on December 31, 2018. Rent expense for theDenver Colorado office for 2014, 2015 and 2016 was $14,554, $15,601 and $15,766, respectively. The lease expires on December 31, 2017.Litigation and ContingenciesFrom time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. AtDecember 31, 2016, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverseeffect on the Company.8. Earnings per ShareThe following table sets forth the computation of basic and diluted earnings per share: Years ended December 31: 2014 2015 2016 (In thousands, except per share data)Numerator: Net income (loss) from continuing operations $61,951 $(127,090) $(96,378)Net income (loss) from discontinued operations 1,318 (20) — $63,269 $(127,110) $(96,378)Denominator: Denominator for basic earnings per share – weighted-average common shares outstanding 98,835 104,605 122,132Effect of dilutive securities:Stock options and restricted shares 2,633 — —Denominator for diluted earnings per share – adjusted weighted-average shares and assumedexercise of options and restricted shares 101,468 104,605 122,132 Net income (loss) per common share - basic Continuing operations $0.63 $(1.21) $(0.79)Discontinued operations 0.01 — — $0.64 $(1.21) $(0.79) Net income (loss) per common share - diluted Continuing operations $0.61 $(1.21) $(0.79)Discontinued operations 0.01 — — $0.62 $(1.21) $(0.79) Basic earnings per share, excluding any dilutive effects of stock options and unvested restricted stock, is computed by dividing net income (loss)available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted income (loss) per share iscomputed similar to basic; however diluted income (loss) per share reflects the assumed conversion of all potentially dilutive securities. For the year endedDecember 31, 2015 and 2016, 624 and 1,635, respectively, of potential shares relating to stock options and unvested restricted shares were excluded from thecalculation of diluted income (loss) per share since their inclusion would have been anti-dilutive due to the loss incurred in the period. None of the dilutiveshares were excluded for the year ended December 31, 2014.9. Quarterly Results of Operations (Unaudited)F-83Table of Contents Selected results of operations for each of the fiscal quarters during the years ended December 31, 2015 and 2016 are as follows: 1stQuarter 2ndQuarter 3rdQuarter 4thQuarter (In thousands, except per share data)Year Ended December 31, 2015 Net revenue $18,661 $18,944 $16,077 $13,348Operating loss $(4,535) $(1,531) $(63,438) $(72,301)Net loss $(718) $(6,601) $(52,372) $(67,419) Net loss per common share – basic $(0.01) $(0.06) $(0.50) $(0.64)Net loss per common share – diluted $(0.01) $(0.06) $(0.50) $(0.64) Year Ended December 31, 2016 Net revenue $9,564 $11,008 $13,976 $22,007Operating (loss) income $(40,143) $(31,898) $(4,952) $3,606Net loss $(40,880) $(46,937) $(3,260) $(5,301) Net loss per common share – basic $(0.39) $(0.40) $(0.02) $(0.04)Net loss per common share – diluted $(0.39) $(0.40) $(0.02) $(0.04)10. Benefit PlansThe Company has a defined contribution plan (401(k) plan) covering all eligible employees. In 2014, 2015 and 2016, in accordance with the safeharbor provisions of the plan, the Company contributed $313,899, $347,632 and $256,309, respectively, to the plan. The Company adopted the safe harborprovisions for its 401(k) plan which requires us to contribute a fixed match to each participating employee’s contribution to the plan. The fixed match is setat the rate of dollar for dollar on the first 1% of eligible pay contributed, then 50 cents on the dollar for each additional percentage point of eligible paycontributed, up to 5%. Each employee’s eligible pay with respect to calculating the fixed match is limited by IRS regulations. In addition, the Board ofDirectors, at its sole discretion, may authorize the Company to make additional contributions to each participating employee’s plan. The employeecontribution limit for 2014 was $17,500 for employees under the age of 50 and $23,000 for employees 50 years of age or older. The 2015 and 2016 employeecontribution limit was $18,000 for employees under the age of 50 and $24,000 for employees 50 years of age or older.11. Hedging Program and DerivativesThe derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in ouroperations. Our derivative contracts do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of thederivative contracts are recognized in earnings during the current period. There are no netting agreements relating to these derivative contracts and there isno policy to offset.The following table sets forth the summary position of our derivative contracts as of December 31, 2016: Oil - WTIContract Periods Daily Volume (Bbl) Swap Price (perBbl)Fixed Swaps 2017 2,401 $54.532018 1,796 $47.482019 1,200 $54.54 Basis Swap F-84Table of Contents2017 500 $0.65 Collar contracts: Gas Contract Periods Daily Volume(Mcf) Floor (LongPut) Ceiling(Short Call) 2017 5,000 $3.00 $3.90 The following table illustrates the impact of derivative contracts on the Company’s balance sheet:Fair Value of Derivative Instruments as of December 31, 2015 Asset Derivatives Liability DerivativesDerivatives not designated as hedginginstruments Balance Sheet Location Fair Value Balance Sheet Location Fair ValueCommodity price derivatives Derivatives – current $18,902 Derivatives – current $—Commodity price derivatives Derivatives – long-term 8,463 Derivatives – long-term — $27,365 $—Fair Value of Derivative Instruments as of December 31, 2016 Asset Derivatives Liability DerivativesDerivatives not designated as hedginginstruments Balance Sheet Location Fair Value Balance Sheet Location Fair ValueCommodity price derivatives Derivatives – current $54 Derivatives – current $2,382Commodity price derivatives Derivatives – long-term — Derivatives – long-term 6,630 $54 $9,012 Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying Consolidated Statements ofOperations.12. Financial InstrumentsThere is a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilitiesmeasured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels aredefined as follows:•Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.•Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that areobservable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.•Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair valuemeasurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment andconsiders factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivativecontract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value ofthe derivative instrument. The following tables sets forth information about the Company’s assets and liabilities measured at fair value on a recurring basis asof December 31, 2015 and 2016, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (inthousands):F-85Table of Contents Quoted Prices in ActiveMarkets forIdenticalAssets(Level 1) SignificantOtherObservableInputs (Level 2) SignificantUnobservableInputs (Level 3) Balance as ofDecember 31,2015Assets: NYMEX Fixed Price Derivative contracts $— $21,731 $— $21,731NYMEX Collars — — 5,634 5,634Total Assets $— $21,731 $5,634 $27,365Liabilities: NYMEX Fixed Price Derivative contracts $— $— $— $—Total Liabilities $— $— $— $— Quoted Prices in ActiveMarkets forIdenticalAssets(Level 1) SignificantOtherObservableInputs (Level 2) SignificantUnobservableInputs (Level 3) Balance as ofDecember 31,2016Assets: NYMEX Fixed Price Derivative contracts $— $35 $— $35NYMEX Collars — — 19 19Total Assets $— $35 $19 $54Liabilities: NYMEX Fixed Price Derivative contracts $— $8,759 $— $8,759NYMEX Collars/basis differential swaps $— $— $253 $253Total Liabilities $— $8,759 $253 $9,012The Company’s derivative contracts at December 31, 2016 consist of NYMEX-based fixed price commodity swaps, basis swaps and NYMEX collars.The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity andare commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivativecontracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivativecontract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are activelyquoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In order to verify the third party valuation,we enter the various inputs into a model and compare our results to the third party for reasonableness. The fair value of the collar instruments and the basisswaps are based on inputs that are not as observable as the fixed price swaps. In addition to the actively quoted market price, variables such as time value,volatility and other unobservable inputs are used. Accordingly, these instruments have been classified as Level 3.Additional information for the Company's recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the yearended December 31, 2016. (In thousands)Unobservable inputs at December 31, 2015 $5,634Changes in market value (2,385)Settlements during the period (3,483)Unobservable inputs at December 31, 2016 $(234)Nonrecurring Fair Value MeasurementsF-86Table of ContentsThe Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis. As itrelates to the Company, ASC 820-10 applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measuredat fair value and the initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As thereis no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of thebeginning and ending balances of the Company’s asset retirement obligation is presented in Note 1.Other Financial Instruments The carrying amounts of our cash, cash equivalents, restricted cash, accounts receivable, accounts payable, and accrued liabilities approximate fairvalue because of the short-term maturities and/or liquid nature of these assets and liabilities. The carrying value of our debt approximates fair value as theinterest rates are market rates and this debt is considered Level 2.13. Discontinued OperationsOn October 31, 2014, the Company closed on the sale of its Canadian subsidiary, Canadian Abraxas Petroleum, ULC ("Canadian Abraxas"). The salewas based on management's decision to discontinue Canadian operations due to continuing losses.In 2014, the Company recognized a gain on the sale of $1.9 million which is included in the accompanying Consolidated Statements of Operationsas a component of net (loss) income from discontinued operations, net of tax.Canadian Abraxas revenue, reported in discontinued operations for the ten months ended October 31, 2014 was $2.0 million. Canadian Abraxas netloss, reported in discontinued operations for the ten months ended October 31, 2014 was $0.6 million. 14. Subsequent EventIn January 2017, the Company closed on the sale of non-core oil and gas properties in Wyoming. Net proceeds of $10.6 million, $1.1 million ofwhich was received in 2016, were used to reduce amounts outstanding under the Company's credit facility. These assets are presented as "Assets held for sale"in the consolidated balance sheet as of December 31, 2016 at the lower of its carrying amount or estimated fair value less costs to sell.In January 2017, the Company completed the sale of 28.8 million shares of common stock. Net proceeds of approximately $65.3 million were used toreduce amounts outstanding under the Company's credit facility.In March 2017, the Company repaid the Rig Loan in full.15. Supplemental Oil and Gas Disclosures (Unaudited)Information in the following tables is inclusive of Canadian operations through October 2014, which are presented in the basic financialstatements as discontinued operations.The accompanying table presents information concerning the Company’s oil and gas producing activities inclusive of discontinued operations“Disclosures about Oil and Gas Producing Activities.” Capitalized costs relating to oil and gas producing activities are as follows: Years Ended December 31 2015 2016 (In thousands)Proved oil and gas properties $787,683 $794,634Unproved properties — —Total 787,683 794,634Accumulated depreciation, depletion, amortization and impairment (590,432) (680,861)Net capitalized costs $197,251 $113,773F-87Table of ContentsCost incurred in oil and gas property acquisition and development activities are as follows: Years Ended December 31 2014 2015 2016 (In thousands)Development costs $189,322 $68,631 $18,262Exploration costs — — 12,529Property acquisition costs — — —Unproved — — — $189,322 $68,631 $30,791The results of operations for oil and gas producing activities, inclusive of discontinued operations, for the three years ended December 31, 2014, 2015 and2016 are as follows: Years Ended December 31, 2014 2015 2016 (In thousands)Revenues $133,701 $67,002 $56,493 Production costs (37,337) (29,753) (23,659) Depreciation, depletion, and amortization (42,945) (38,040) (22,803) Proved property impairment — (128,573) (67,626) Results of operations from oil and gas producing activities (excluding corporateoverhead and interest costs) $53,419 $(129,364) $(57,595) Depletion rate per barrel of oil equivalent $20.39 $17.44 $10.08 Estimated Quantities of Proved Oil and Gas ReservesThe following table presents the Company’s estimate of its net proved oil and gas reserves as of December 31, 2014, 2015, and 2016. Reserveestimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, theestimates are expected to change as future information becomes available. The estimates have been predominately prepared by independent petroleumreserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonablecertainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reservesare those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are locatedin the continental United States.Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be preparedunder existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, theunweighted average prior 12-month-first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cashflows for the periods presented.The following is a summary of the changes to the Company’s proved reserves that occurred during 2016:Revisions to prior estimates:An increase of 5,005 MBoe of reserves was attributed to the Company’s Bakken and Three Forks proved undeveloped locations in McKenzieCounty, ND, due to continuing improvement in its producing well production results. Well results improved as a result of the application of optimizedcompletion methods. Similarly, reserves for the Company’s Bakken and Three Forks producing wells increased by 1,360 MBoe of net producing reserves dueto improved performance. On the other hand, projections for the Hedgehog State 16-2H producing well and its two related proved undeveloped locations inthe Porcupine Field, CampbellF-88Table of ContentsCounty, WY, decreased by 670 MBoe of net reserves due to the under-performance of the Hedgehog State 16-2H. There was also a reduction in this categoryof 2,271 MBoe attributable to shortened economic life calculations at the lower commodity pricing.Extensions, discoveries and other additions:The Company added the Caprito 99 302H as a new Wolfcamp producing well in Ward County, TX, accounting for 449 MBoe of net producingreserves. It also added five new proved undeveloped Wolfcamp locations offsetting this new producer accounting for 805 MBoe of net undeveloped reserves.The Company also developed a new Austin Chalk producer in Atascosa County, TX, which accounted for 265 MBoe of net producing reserves. Further, theCompany added eight new proved undeveloped Bakken/Three Forks locations on non-operated units in McKenzie County, ND, accounting for 18 MBoe ofnet undeveloped reserves. These locations were added in response to operator well proposals.Sales:The Company sold all its holdings in the Portilla Field in San Patricio County, TX, and in the Brooks Draw Field in Converse County, WY, during2016. These sales accounted for 1,232 MBoe of net proved reserves.Production:The Company produced 2,262 MBoe of net reserves during 2016.The following is a summary of the changes to the Company’s proved reserves that occurred during 2015:Revisions of prior estimates:A total of 48 proved locations accounting for approximately 7.9 net MMBoe of reserves were dropped from the report in 2015 due to lack ofeconomic viability at the lower commodity pricing applied of which 42 were in the undeveloped category. Most significant of these were 38 South TexasEagle Ford locations representing approximately 7,717 MBoe of net reserves. There was also a reduction of 614 net MBoe attributable to shortenedeconomic life calculations at lower commodity pricing which were partially offset by an increase of 600 net MBoe in the Company’s Bakken/Three Forksundeveloped locations due to better-than-anticipated production. There were also reduction in this category of 1.8 MMBoe of net reserves attributable toshortened economic life calculations at the lower commodity pricing and 1.6 MMBoe of net reserves attributable to lower than anticipated productionperformance in various wells.Extensions, discoveries and other additions:The Company added 28 new proved undeveloped Bakken locations during 2015 on the Company’s prospect acreage in McKenzie County, NorthDakota, accounting for approximately 6.5 MMBoe of net reserves, 20 of which accounting for 4.9 net MMBoe, were for the Three Forks (2nd Bench) whichwere proved by local development activity in that reservoir during the year. There were also 8 other cases in the Bakken/Three Forks, accounting for 1.6 netMMBoe, which were added because the Company gained operational control of the Yellowstone Unit resulting in the Company developing the properties inaccordance with its normal well spacing pattern.The Company also gained proved undeveloped reserves of approximately 1.3 net MMBOE, due to the change in classification of 21 probable andpossible undeveloped Bakken cases into the proved category. This change was warranted by local well development in the specific local areas during 2015.The Company also added 6 new Montoya proved undeveloped locations on the Company’s prospect acreage in Ward County, Texas, accounting for6.5 MMBOE of net reserves. These locations were added based on the performance of existing Montoya producers on the subject acreage.Sales:During 2015, the Company sold properties accounting for 43 net MBoe of reserves.F-89Table of ContentsProduction:During 2015, the Company produced 2,181 of net MBoe of reserves Oil NGL Gas OilEquivalents (MBbl) (MBbl) (MMcf) (MBoe) Proved developed and undeveloped reserves: (in thousands) Balance at December 31, 2013 20,915 2,038 48,109 30,970 Revisions of previous estimates 2,697 1,021 7,383 4,950 Extensions and discoveries 7,780 868 6,893 9,797 Sales of minerals in place (608) (12) (3,614) (1,223) Production (1,394) (207) (2,918) (2,088) Balance at December 31, 2014 29,390 3,708 55,853 42,406 Revisions of previous estimates (9,485) (505) (8,002) (11,324) Extensions and discoveries 5,679 3,591 30,372 14,332 Sales of minerals in place (13) — (181) (43) Production (1,440) (238) (3,015) (2,181) Balance at December 31, 2015 24,131 6,556 75,027 43,190 Revisions of previous estimates 1,379 2,300 (1,537) 3,424 Extensions and discoveries 1,183 157 1,179 1,537 Sales of minerals in place (1,112) (6) (680) (1,232) Production (1,372) (363) (3,160) (2,262) Balance at December 31, 2016 24,209 8,644 70,829 44,657 Total Oil NGL Gas OilEquivalents (MBbl) (MBbl) (MMcf) (MBoe) (In thousands)Proved Developed Reserves: December 31, 2014 10,162 2,006 34,677 17,948 December 31, 2015 10,022 1,956 31,298 17,194 December 31, 2016 7,818 2,568 27,792 15,018 Proved Undeveloped Reserves: December 31, 2014 19,228 1,702 21,176 24,459 December 31, 2015 14,109 4,599 43,729 25,996 December 31, 2016 16,391 6,076 43,037 29,639 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The Company’s proved oil and gas reserves have been estimated by the Company with the assistance of an independent petroleum engineering firm(DeGolyer & MacNaughton) as of December 31, 2014, 2015 and 2016.The following information has been prepared in accordance with SEC rules and accounting standards based on the 12-month first-day-of-the-monthunweighted average prices in accordance with provisions of the FASB’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas(Topic 932).” Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cashinflows. Future net cash flows have not beenF-90Table of Contentsadjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes were computed by applying the statutory tax rate to theexcess of pre-tax cash inflows over the tax basis and net operating losses associated with the properties. Since prices used in the calculation are averageprices for 2016, the standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year. The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications,independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Informationpromulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists,and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. All reports by DeGolyer andMacNaughton were developed utilizing studies performed by DeGolyer and MacNaughton and assisted by the Engineering and Operations departments ofAbraxas. Reserves are estimated by independent petroleum engineers. The report of DeGolyer and MacNaughton dated February 13, 2017, which containsfurther discussions of the reserve estimates and evaluations prepared by DeGolyer and MacNaughton as well as the qualifications of DeGolyer andMacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report. Estimates of proved reserves at December 31, 2014, 2015 and 2016 were based on studies performed by our independent petroleum engineers assistedby the Engineering and Operations departments of Abraxas. The Engineering department is directly responsible for Abraxas’ reserve evaluation process. TheVice President of Engineering is the manager of this department and is the primary technical person responsible for this process. The Vice President ofEngineering holds a Bachelor of Science degree in Petroleum Engineering and has 38 years of experience in reserve evaluations. The Vice President ofEngineering is a Registered Professional Engineer in the State of Texas. The operations department of Abraxas assisted in the process.The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted to represent thefair market value of the Company’s proved oil and gas reserves. An estimate of fair market value would also take into account, among other factors, therecovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value ofmoney and the risks inherent in reserve estimates.Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table belowsets forth the Standardized Measure of our proved oil and gas reserves for the three years ended December 31, 2014, 2015 and 2016: Years Ended December 31, 2014 2015 2016 (In thousands) Future cash inflows $2,988,464 $1,241,334 $999,716 Future production costs (921,977) (438,784) (357,917) Future development costs (557,782) (338,316) (267,836) Future income tax expense (373,095) — — Future net cash flows 1,135,610 464,234 373,963 Discount (623,053) (266,983) (213,363) Standardized Measure of discounted future net cash relating to provedreserves $512,557 $197,251 $160,600 F-91Table of ContentsChanges in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas ReservesThe following is an analysis of the changes in the Standardized Measure: Year Ended December 31, 2014 2015 2016 (In thousands)Standardized Measure, beginning of year $340,985 $512,557 $197,251Sales and transfers of oil and gas produced, net of production costs (96,364) (37,249) (32,834)Net change in prices and development and production costs from prior year 150,504 (488,160) (58,425)Extensions, discoveries, and improved recovery, less related costs 147,275 63,341 5,531Sales of minerals in place (15,042) (197) (4,433)Revisions of previous quantity estimates 74,390 (49,602) 12,317Change in timing and other (82,653) 20,419 21,468Change in future income tax expense (40,636) 124,886 —Accretion of discount 34,098 51,256 19,725Standardized Measure, end of year $512,557 $197,251 $160,600The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates: Year Ended December 31, 2014 2015 2016Oil (per Bbl) (1) $95.28 $50.12 $42.74Gas (per MMbtu) (2) $4.35 $2.63 $2.50Oil (per Bbl) (3) $87.11 $41.25 $35.54Gas (per MMBtu) (4) $5.15 $2.36 $1.41NGL’s (per Bbl) (5) $37.92 $10.52 $5.17_____________________(1)The quoted oil price for the year ended December 31 of each year, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-monthWest Texas Intermediate spot price for each month of 2014, 2015 and 2016.(2)The quoted gas price for the year ended December 31, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month Henry Hubspot price for each month of 2014, 2015 and 2016.(3)The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.(4)The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied.(5)The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.F-92Table of ContentsExhibit Index23.1Consent of BDO USA, LLP. (Filed herewith).23.2Consent of DeGolyer & MacNaughton. (Filed herewith).31.1Certification – Chief Executive Officer. (Filed herewith).31.2Certification – Chief Financial Officer. (Filed herewith).32.1Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(Filed herewith).32.2Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(Filed herewith).99.1Report of DeGolyer and MacNaughton with respect to oil and reserves of Abraxas Petroleum. (Filed herewith).SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signedon its behalf by the undersigned, thereunto duly authorized. ABRAXAS PETROLEUM CORPORATIONBy:/s/Robert L.G. Watson By:/s/Geoffrey R. KingBy:/s/ G. William Krog, Jr. President and Principal Executive Officer Vice President and Chief FinancialOfficer Principal Financial Officer Principal Accounting OfficerDATED: March 16, 2017F-93Table of ContentsPursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of theRegistrant and in the capacities and on the date indicated.Signature Name and Title Date/s/ Robert L.G. WatsonRobert L.G. Watson Chairman of the Board, President (Principal ExecutiveOfficer) and Director March 16, 2017/s/ Geoffrey R. KingGeoffrey R. King Vice President, CFO (Principal Financial Officer) March 16, 2017/s/ G. William Krog, Jr.G. William Krog, Jr. Chief Accounting Officer (Principal Accounting Officer) March 16, 2017/s/ Harold D. CarterHarold D. Carter Director March 16, 2017/s/ Ralph F. CoxRalph F. Cox Director March 16, 2017/s/ W. Dean KarrashW. Dean Karrash Director March 16, 2017/s/ Jerry J. LangdonJerry J. Langdon Director March 16, 2017/s/ Dennis E. LogueDennis E. Logue Director March 16, 2017/s/ Brian L. MeltonBrian L. Melton Director March 16, 2017/s/ Paul A. Powell, Jr.Paul A. Powell, Jr. Director March 16, 2017/s/ Edward P. RussellEdward P. Russell Director March 16, 201794Exhibit 23.1Consent of Independent Registered Public Accounting FirmAbraxas Petroleum CorporationSan Antonio, TexasWe hereby consent to the incorporation by reference in the Registration Statements on Form S3 (No. 333-212342), Form S-4 (No. 333-212-340) and Form S-8(Nos. 333-17375, 333-17377, 033-81416, 333-55691, 333-74614, 333-74592, 333-135032, 333-153635, 333-162358, 333-168022, 333-188117, 333-204744 and 333-212341) of Abraxas Petroleum Corporation of our reports dated March 16, 2017, relating to the consolidated financial statements, and theeffectiveness of Abraxas Petroleum Corporation’s internal control over financial reporting, which appear in this Form 10-K./s/ BDO USA, LLPSan Antonio, TexasMarch 16, 2017R-221 (4/11)Exhibit 23.2DEGOLYER AND MACNAUGHTON5001 SPRING VALLEY ROADSUITE 800 EASTDALLAS, TEXAS 75244March 16, 2017Abraxas Petroleum Corporation18803 Meisner DriveSan Antonio, Texas 78258Ladies and Gentlemen:We consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton, and to theinclusion of information taken from our “Report as of December 31, 2016 on Reserves and Revenue of Certain Properties owned byAbraxas Petroleum Corporation,” “Report as of December 31, 2015 on Reserves and Revenue of Certain Properties owned by AbraxasPetroleum Corporation,” and “Appraisal Report as of December 31, 2014 on Certain Properties owned by Abraxas PetroleumCorporation” (our Reports) under the sections “Item 1. Business - General,” “Item 2. Properties - Reserves Information,” and “Notes toConsolidated Financial Statements - 15. Supplemental Oil and Gas Disclosures (Unaudited)” in the Abraxas Petroleum CorporationAnnual Report on Form 10-K for the year ended December 31, 2016. We also consent to the inclusion of our third‑party letter reportdated February 13, 2017, in the Annual Report on Form 10‑K of Abraxas Petroleum Corporation as Exhibit 99.1. We further consent tothe incorporation by reference in the Registration Statements on Form S-3 (No. 333‑212342), Form S-4 (No. 333‑212340) and Form S-8 (Nos. 333-17375, 333‑17377, 033-81416, 333-55691, 333‑74592, 333-74614, 333-135032, 333-153635, 333-162358, 333-168022,333‑188117, 333-204744, and 333-212341) of information from our Reports.Very truly yours,/s/DeGolyer and MacNaughtonDeGOLYER and MacNAUGHTONTexas Registered Engineering Firm F-716Exhibit 31.1CERTIFICATIONSI, Robert L. G. Watson, certify that: 1.I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.2.Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to makethe statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport.3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;(c)evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscalquarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting.Date: March 16, 2017/s/ Robert L.G. WatsonRobert L.G. WatsonChairman of the Board, President andPrincipal Executive OfficerExhibit 31.2CERTIFICATIONSI, Geoffrey R. King, certify that: 1.I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation.2.Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to makethe statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport.3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;(c)evaluated the effectiveness of the registrant’s disclosure controls and procedures, and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscalquarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting.Date: March 16, 2017/s/ Geoffrey R. KingGeoffrey R. KingVice President andPrincipal Financial OfficerExhibit 32.1CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report of Abraxas Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2016 as filed withthe Securities and Exchange Commission on the date hereof (the “Report”), I, Robert L.G. Watson, Chairman of the Board, President and Chief ExecutiveOfficer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company./s/ Robert L.G. WatsonRobert L.G. WatsonChairman of the Board, President and Chief Executive OfficerMarch 16, 2017This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by theSarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of §18 of the Securities Exchange Act of 1934, as amended.A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished tothe Securities and Exchange Commission or its staff upon request.Exhibit 32.2CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report of Abraxas Petroleum Corporation (the “Company”) on Form 10-K for the year ended December 31, 2016 as filed withthe Securities and Exchange Commission on the date hereof (the “Report”), I, Geoffrey R. King, Vice President and Chief Financial Officer of the Company,certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company./s/Geoffrey R. KingGeoffrey R. KingVice President and Chief Financial OfficerMarch 16, 2017This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by theSarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of §18 of the Securities Exchange Act of 1934, as amended.A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished tothe Securities and Exchange Commission or its staff upon request.DeGolyer and MacNaughton5001 Spring Valley RoadSuite 800 EastDallas, Texas 75244Exhibit 99.1February 13, 2017Abraxas Petroleum Corporation18803 Meisner DriveSan Antonio, Texas 78258Ladies and Gentlemen:Pursuant to your request, we have prepared estimates of the extent and value of the net proved oil, condensate, natural gasliquids (NGL), and gas reserves, as of December 31, 2016, of certain selected properties in which Abraxas Petroleum Corporation(Abraxas) has represented that it owns an interest. This evaluation was completed on February 13, 2017. Abraxas has represented thatthese properties account for 98 percent on a net equivalent barrel basis of Abraxas’ net proved reserves as of December 31, 2016. Theproperties evaluated are located in Montana, North Dakota, South Dakota, Texas, and Wyoming. The net proved reserves estimatesprepared by us have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of theSecurities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified inItem 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Abraxas.Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum tobe produced from these properties after December 31, 2016. Net reserves are defined as that portion of the gross reserves attributable tothe interests owned by Abraxas after deducting all interests owned by others.Estimates of oil, condensate, NGL, and gas reserves and future net revenue should be regarded only as estimates that maychange as further production history and additional informationDeGolyer and MacNaughton5001 Spring Valley RoadSuite 800 EastDallas, Texas 75244become available. Not only are such reserves and revenue estimates based on that information which is currently available, but suchestimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.3DeGolyer and MacNaughtonData used in this evaluation were obtained from reviews with Abraxas personnel, from Abraxas files, from records on file withthe appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independentverification, upon such information furnished by Abraxas with respect to property interests, production from such properties, currentcosts of operation and development, current prices for production, agreements relating to current and future operations and sale ofproduction, and various other information and data that were accepted as represented. A field examination of the properties was notconsidered necessary for the purposes of this report.Methodology and ProceduresEstimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles andtechniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of theSociety of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information(Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered byexperience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.Based on the current stage of field development, production performance, the development plans provided by Abraxas, and theanalyses of areas offsetting existing wells with test or production data, reserves were classified as proved.An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in theestimation of reserves. All of the undeveloped reserves were estimated by analogy to similar wells or offset wells.For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or otherdiagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships.In the analyses of production‑decline curves, reserves were estimated only to the limits of economic production.Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be deliveredinto a gas pipeline for sale after field separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60degrees Fahrenheit and at the pressure base of the state in which the interest is located. Gas quantities included herein are expressed4DeGolyer and MacNaughtonin thousands of cubic feet (Mcf). Oil and condensate reserves estimated herein are those to be recovered by conventional leaseseparation. NGL reserves are those attributed to the leasehold interests according to processing agreements. Oil, condensate, and NGLreserves included herein are expressed in barrels (bbl) representing 42 United States gallons per barrel. For reporting purposes, oil andcondensate reserves have been estimated separately and are presented herein as a summed quantity.Definition of ReservesPetroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report.Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–Xof the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic andoperating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment.In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existingeconomic and operating conditions using prices and costs consistent with the effective date of this report, including consideration ofchanges in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. Thepetroleum reserves are classified as follows:Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscienceand 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 thetime 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 hydrocarbonsmust have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.(i) The area of the reservoir considered as proved includes:(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoirthat can, with reasonable certainty, be judged to be continuous with it and to contain economically5DeGolyer and MacNaughtonproducible oil or gas on the basis of available geoscience and engineering data.(ii) 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 establishesa lower contact with reasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potentialexists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir onlyif geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonablecertainty.(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but notlimited to, fluid injection) are included in the proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir asa whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliabletechnology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmental entities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to bedetermined. The price shall be the average price during the 12‑month period prior to the ending date of the period coveredby the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month withinsuch period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to berecovered:6DeGolyer and MacNaughton(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment isrelatively 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 extractionis by means not involving a well.Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to berecovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required forrecompletion.(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonablycertain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty ofeconomic producibility at greater distances.(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adoptedindicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an applicationof fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effectiveby actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or byother evidence using reliable technology establishing reasonable certainty.The development status shown herein represents the status applicable on December 31, 2016. In the preparation of this report,data available from wells drilled on the evaluated properties through December 31, 2016, were used in estimating gross ultimaterecovery. When applicable, gross production estimated through December 31, 2016, was deducted from gross ultimate recovery toarrive at the estimates of gross reserves. In some fields this required that the production rates be7DeGolyer and MacNaughtonestimated for up to 3 months, since production data from certain properties were available only through September 2016.Primary Economic AssumptionsValues of proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth.Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated netreserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, capital costs,and abandonment costs from the future gross revenue. Operating expenses include field operating costs, compression charges, and anallocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in thepreparation of these estimates. Present worth of future net revenue is calculated by discounting the future net revenue at the arbitraryrate of 10 percent per year compounded annually over the expected period of realization. Present worth should not be construed as fairmarket value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.Revenue values in this report were estimated using the initial prices and expenses provided by Abraxas. Future prices wereestimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The assumptions used forestimating future prices and expenses are as follows:Oil, Condensate, and NGL PricesAbraxas has represented that the oil, condensate, and NGL prices were based on West Texas Intermediate pricing,calculated as the unweighted arithmetic average of the first‑day-of-the-month price for each month within the 12‑monthperiod prior to the end of the reporting period, unless prices are defined by contractual arrangements. Abraxas supplieddifferentials to the reference price of $42.74 per barrel and the prices were held constant thereafter. The volume-weightedaverage prices over the lives of the properties were $35.51 per barrel of oil and condensate and $5.03 per barrel of NGL.Gas Prices8DeGolyer and MacNaughtonAbraxas has represented that the gas prices were based on a Henry Hub price, calculated as the unweighted arithmeticaverage of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reportingperiod, unless prices are defined my contractual arrangements. The gas prices were calculated for each property usingdifferentials furnished by Abraxas to the reference price of $2.50 per million British thermal units ($/MMBtu) and heldconstant thereafter. British thermal unit factors provided by Abraxas were used to convert prices from $/MMBtu to dollarsper thousand cubic feet. The volume-weighted average price over the lives of the properties was $1.394 per thousand cubicfeet of gas.Production and Ad Valorem TaxesProduction taxes were calculated using the tax rates for the state in which the reserves are located. Ad valorem taxes werecalculated using rates provided by Abraxas based on historical payments.Operating Expenses, Capital Costs, and Abandonment CostsOperating expenses and capital and abandonment costs, based on information provided by Abraxas, were used in estimatingfuture costs required to operate the properties. In certain cases, future costs, either higher or lower than existing costs, mayhave been used because of anticipated changes in operating conditions. These costs were not escalated for inflation.Our estimates of Abraxas’ net proved reserves attributable to the reviewed properties were based on the definitions of reservesof the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands ofbarrels of oil equivalent (Mboe):9DeGolyer and MacNaughton Estimated byDeGolyer and MacNaughtonNet Proved Reservesas of December 31, 2016Oil andCondensate(Mbbl) NGL(Mbbl) SalesGas(MMcf) OilEquivalent(Mboe) Proved Developed Producing 6,730 2,332 22,847 12,870Developed Non-Producing 585 61 2,560 1,073Undeveloped 16,390 6,076 43,037 29,639 Total Proved 23,705 8,469 68,444 43,582Note: Gas is converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.The estimated future revenue and costs attributable to the production and sale of Abraxas’ net proved reserves of the propertiesevaluated, as of December 31, 2016, are summarized in thousands of dollars (M$) as follows: Proved DevelopedProducing DevelopedNon-Producing Undeveloped TotalProved Future Gross Revenue, M$ 277,195 26,412 670,922 974,529Production and Ad Valorem Taxes, M$ 27,669 2,553 68,396 98,618Operating Expenses, M$ 99,074 7,716 131,636 238,426Capital Costs, M$ 22 4,944 258,062 263,028Abandonment Costs, M$ 1,239 218 1,361 2,818Future Net Revenue, M$ 149,191 10,981 211,467 371,639Present Worth at 10 Percent, M$ 99,657 5,708 53,612 158,977 Note: Future income taxes have not been taken into account in the preparation of these estimates. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’sability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of theDecember 31, 2016, estimated oil, condensate, NGL, and gas reserves.In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, andpresent worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in thisreport has been prepared in accordance10DeGolyer and MacNaughtonwith Paragraphs 932‑235-50-4, 932-235-50-6, 932-235-50-7, 932‑235‑50‑9, 932-235-50-30, and 932‑235-50-31(a), (b), and (e) of theAccounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation andDisclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided,however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worthvalues set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginningof the year.To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature,we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewithor sufficient therefor.11DeGolyer and MacNaughtonDeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleumconsulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stockownership, in Abraxas. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the requestof Abraxas. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary andappropriate to prepare this report.Submitted,/s/ DeGolyer and MacNaughtonDeGOLYER and MacNAUGHTON Texas Registered Engineering FirmF-716[SEAL]/s/ Dennis W. Thompson, P.E.Dennis W. Thompson, P.E.Senior Vice PresidentDeGolyer and MacNaughtonDeGolyer and MacNaughtonCERTIFICATE of QUALIFICATIONI, Dennis W. Thompson, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East,Dallas, Texas, 75244 U.S.A., hereby certify:1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed toAbraxas dated February 13, 2017, and that I, as Senior Vice President, was responsible for the preparation of this letter report.2.That I attended Eastern New Mexico University, and that I graduated with a Bachelor of Science degree in Geology in 1973;that I attended the University of Texas, and that I earned a Master of Science degree in Petroleum Engineering in 1975; that I ama Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that Ihave in excess of 37 years of experience in oil and gas reservoir studies and reserves evaluations.[SEAL]/s/ Dennis W. Thompson, P.E.Dennis W. Thompson, P.E.Senior Vice PresidentDeGolyer and MacNaughton

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