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2019 ReportTable of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K(Mark One)☒☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2017 ☐☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 001-16317 CONTANGO OIL & GAS COMPANY(Exact name of registrant as specified in its charter) Delaware 95-4079863(State or other jurisdiction ofincorporation or organization) (IRS Employer Identification No.) 717 Texas Avenue, Suite 2900Houston, Texas 77002(Address of principal executive offices) (713) 236-7400(Registrant’s telephone number, including area code)Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of exchange on which registeredCommon Stock, Par Value $0.04 per share NYSE American Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes ☒ No ☐ Indicate by check mark whether 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 that theregistrant was required to submit and post such files). Yes ☒ No ☐ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to thebest of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form10-K. ☒ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or anemerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule12b-2 of the Exchange Act.Large accelerated filer ☐Accelerated filer ☒Non-accelerated filer ☐Smaller reporting company ☐ (Do not check if smaller reporting company)Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any newor revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ At June 30, 2017, the aggregate market value of the registrant’s common stock held by non-affiliates (based upon the closing sale price of shares of suchcommon stock as reported on the NYSE American, was $129.5 million. As of March 5, 2018, there were 25,479,438 shares of the registrant’s common stockoutstanding. Documents Incorporated by Reference Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since the registrant will file with the Securities and Exchange Commission, notlater than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information required by Items 10, 11, 12, 13 and 14of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form 10-K. Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2017 TABLE OF CONTENTS Page PART I Item 1. Business1 Overview1 Our Strategy2 Properties3 Onshore Investments6 Title to Properties6 Marketing and Pricing6 Competition8 Governmental Regulations and Industry Matters8 Risk and Insurance Program16 Employees17 Corporate Offices17 Code of Ethics17 Available Information17 Seasonal Nature of Business18Item 1A.Risk Factors18Item 1B. Unresolved Staff Comments38Item 2. Properties38 Development, Exploration and Acquisition Expenditures38 Drilling Activity39 Exploration and Development Acreage39 Production, Price and Cost History40 Productive Wells40 Natural Gas and Oil Reserves40 PV-1042 Proved Developed Reserves43 Proved Undeveloped Reserves43 Significant Properties44Item 3. Legal Proceedings45Item 4. Mine Safety Disclosures46 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities47 General47 Amended & Restated 2009 Incentive Compensation Plan48 2005 Stock Incentive Plan49 Share Repurchase Program50 Stock Performance Graph51Item 6. Selected Financial Data52Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations53 Overview53 Results of Operations55 Capital Resources and Liquidity60 Contractual Obligations63 Application of Critical Accounting Policies and Management’s Estimates63 Recent Accounting Pronouncements65 Off Balance Sheet Arrangements66Item 7A. Quantitative and Qualitative Disclosure about Market Risk67Item 8. Financial Statements and Supplementary Data68Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure68 Item 9A. Controls and Procedures68Item 9B. Other Information71 PART III Item 10. Directors, Executive Officers and Corporate Governance71Item 11. Executive Compensation71Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters71Item 13. Certain Relationships and Related Transactions, and Director Independence71Item 14. Principal Accountant Fees and Services71 PART IV Item 15. Exhibits and Financial Statement Schedules75 ii Table of ContentsCAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTSCertain statements contained in this report may contain “forward-looking statements” within the meaning of Section27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words andphrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressionsidentify forward-looking statements and express our expectations about future events. Although we believe the expectationsreflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-lookingstatements are made subject to certain risks and uncertainties that could cause actual results to differ materially from thosestated. Risks and uncertainties that could cause or contribute to such differences include, without limitation, those discussedin the section entitled “Risk Factors” included in this report and those factors summarized below:·our ability to successfully develop our undeveloped acreage in the Southern Delaware Basin, integrate theoperations relating thereto with our existing operations and realize the benefits associated therewith;·our financial position;·our business strategy, including outsourcing;·meeting our forecasts and budgets;·expectations regarding natural gas and oil markets in the United States;·volatility in natural gas, natural gas liquids and oil prices;·operational constraints, start-up delays and production shut-ins at both operated and non-operated productionplatforms, pipelines and natural gas processing facilities;·the risks associated with acting as operator of deep high pressure and high temperature wells, including wellblowouts and explosions;·the risks associated with exploration, including cost overruns and the drilling of non-economic wells or dryholes, especially in prospects in which we have made a large capital commitment relative to the size of ourcapitalization structure;·the timing and successful drilling and completion of natural gas and oil wells;·our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund ouroperations, satisfy our obligations, and fund our drilling program;·the cost and availability of rigs and other materials, services, and operating equipment;·timely and full receipt of sale proceeds from the sale of our production;·the ability to find, acquire, market, develop and produce new natural gas and oil properties;·interest rate volatility;·uncertainties in the estimation of proved reserves and in the projection of future rates of production and timingof development expenditures;·the need to take impairments on our properties due to lower commodity prices;·the ability to post additional collateral for current bonds or comply with new supplemental bondingrequirements imposed by the Bureau of Ocean Energy Management;·operating hazards attendant to the natural gas and oil business including weather, environmental risks,accidental spills, blowouts and pipeline ruptures, and other risks;iv Table of Contents·downhole drilling and completion risks that are generally not recoverable from third parties or insurance;·potential mechanical failure or under-performance of significant wells, production facilities, processing plantsor pipeline mishaps;·actions or inactions of third-party operators of our properties;·actions or inactions of third-party operators of pipelines or processing facilities;·the ability to retain key members of senior management and key technical employees and to find and retainskilled personnel;·strength and financial resources of competitors;·federal and state legislative and regulatory developments and approvals (including additional taxes andchanges in environmental regulations);·worldwide economic conditions;·the ability to construct and operate infrastructure, including pipeline and production facilities;·the continued compliance by us with various pipeline and gas processing plant specifications for the gas andcondensate produced by us;·operating costs, production rates and ultimate reserve recoveries of our natural gas and oil discoveries;·expanded rigorous monitoring and testing requirements; and·ability to obtain adequate insurance coverage on commercially reasonable terms.Any of these factors and other factors contained in this report could cause our actual results to differ materially fromthe results implied by these or any other forward-looking statements made by us or on our behalf. Although we believe ourestimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertaintiesthat are beyond our control. Our assumptions about future events may prove to be inaccurate. We caution you that theforward-looking statements contained in this report are not guarantees of future performance, and we cannot assure you thatthose statements will be realized or the forward-looking events and circumstances will occur. All forward-looking statementsspeak only as of the date of this report.Reserve engineering is a process of estimating underground accumulations of oil, natural gas and natural gas liquidsthat cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, theinterpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling,testing and production activities may justify revisions of estimates that were made previously. If significant, such revisionswould change the schedule of any further production and development drilling. Accordingly, reserve estimates may differsignificantly from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered.All forward-looking statements, expressed or implied, in this report are expressly qualified in their entirety by thiscautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oralforward-looking statements that we or any person acting on our behalf may issue.We do not intend to publicly update or revise any forward-looking statements as a result of new information, futureevents or otherwise, except as required by law. These cautionary statements qualify all forward-looking statementsattributable to us or persons acting on our behalf.All references in this Form 10-K to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & GasCompany and wholly-owned subsidiaries. Unless otherwise noted, all information in this Form 10-K relating to natural gasand oil reserves and the estimated future net cash flows attributable to those reserves is based on estimates prepared byindependent engineers, and is net to our interest. v Table of ContentsPART I Item 1. BusinessOverviewWe are a Houston, Texas based independent oil and natural gas company. Our business is to maximize productionand cash flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties inTexas and Wyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oiland natural gas properties in onshore West Texas, the Texas Gulf Coast and the Rocky Mountain regions of the UnitedStates.The following table lists our primary producing areas as of December 31, 2017:Location Formation Gulf of Mexico Offshore Louisiana - water depths less than 300 feet Madison and Grimes counties, Texas Woodbine (Upper Lewisville) Pecos County, Texas Southern Delaware Basin (Wolfcamp) Other Texas Gulf Coast Conventional and smaller unconventional formations Zavala and Dimmit counties, Texas Buda / Austin Chalk Weston County, Wyoming Muddy Sandstone Sublette County, Wyoming Jonah Field (1)Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production from this investment is not included in our reportedproduction results or in our reported reserves for any periods reported herein.Since October 2013, upon the merger with Crimson Exploration Inc. (“Crimson”) (the “Merger”), and prior to thedecline in crude oil and natural gas prices in 2015, we focused our drilling efforts on liquids-rich horizontal resource plays.Beginning in the second half of 2015, we reduced our drilling program in response to the challenging commodity priceenvironment, and instead focused on: (i) the preservation of our strong and flexible financial position, including limiting ouroverall capital expenditure budget; (ii) the identification of opportunities for cost and production efficiencies in all areas ofour operations; and (iii) the maintenance of core leases and the continued identification of new resource potentialopportunities. As a result, until the latter half of 2016, our only drilling activity was in Weston County, Wyoming, where wecompleted our third well targeting the Muddy Sandstone formation. During the third quarter of 2016, we acquired a 12,100gross acre position (5,000 net) in the Southern Delaware Basin in Pecos County, Texas (the “Acquisition”), and as ofDecember 31, 2017, had increased our acreage in the Southern Delaware Basin to 16,500 gross acres (6,800 net). Since theAcquisition, we have begun production from seven wells in the Southern Delaware Basin and are waiting on completion ofan eighth well. We currently expect that the Southern Delaware Basin position will continue to be the primary focus of ourdrilling program for 2018. In addition to our above producing properties, we also have (i) operated producing properties in the HaynesvilleShale, Mid Bossier Shale and the James Lime formations in East Texas and (ii) operated conventional producing propertiesin the south and southeast areas of Texas. In December 2016, we sold our operated producing properties in the DenverJulesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado. During the quarter ended September 30, 2016, in conjunction with the Acquisition, we completed an underwrittenpublic offering of 5,360,000 shares of our common stock for net proceeds of approximately $50.5 million, which were usedto fund the initial purchase of this acreage and provide funding for the costs associated with drilling our initial wells in theSouthern Delaware Basin.Our production for the year ended December 31, 2017 was approximately 20.1 Bcfe (or 55.1 Mmcfe/d), was 68%from our offshore properties and was 69% natural gas. Our production for the three months ended December 31, 2017 wasapproximately 4.8 Bcfe (or 51.8 Mmcfe/d), was 66% from our offshore properties and was 68% natural gas. As of December31, 2017, our proved reserves were approximately 65% proved developed, were 40% offshore, were 48% natural gas and were98% attributed to wells and properties operated by us.1 (1) Table of ContentsAs of December 31, 2017, our proved reserves, as estimated by Netherland, Sewell & Associates, Inc. (“NSAI”) andWilliam M. Cobb and Associates (“Cobb”), our independent petroleum engineering firms, in accordance with reservereporting guidelines required by the Securities and Exchange Commission (“SEC”), were approximately 189.3 Bcfe,consisting of 91.7 Bcf of natural gas, 10.6 MMBbl of crude oil and condensate and 5.6 MMBbl of natural gas liquids(“NGLs”), with a present value, discounted at a 10% rate (PV‑10), of $257.3 million, and a Standardized Measure ofDiscounted Future Net Cash Flows (“Standardized Measure”) of $255.9 million. PV-10 as of December 31, 2017 was basedon adjusted prices of $2.92 per MMbtu of natural gas, $47.41 per barrel of oil, and $18.59 per barrel of NGLs. PV-10 is not anaccounting principle generally accepted in the United States of America (“GAAP”) and is therefore classified as a non-GAAPfinancial measure. A reconciliation of our Standardized Measure to PV‑10 is provided under “Item 2. Properties ‑ PV-10”.The following summary table sets forth certain information with respect to our proved reserves as of December 31,2017 (excluding reserves attributable to our investment in Exaro), as estimated by NSAI and Cobb, and our net average dailyproduction for the year ended December 31, 2017: Estimated Proved % Crude Oil / Natural % Natural Gas % Proved Average Daily Region Reserves (Bcfe) Condensate % Gas Liquids Developed Production (Mmcfe/d) Offshore GOM 75.4 3% 82% 15% 100% 37.7 Southeast Texas 30.9 41% 37% 22% 63% 8.0 South Texas 25.7 46% 40% 14% 64% 5.6 West Texas 55.5 64% 15% 21% 19% 2.6 Other 1.8 65% 32% 3% 100% 1.2 Total 189.3 55.1 (1)Includes East Texas, Mississippi, Louisiana and Wyoming.The following summary table sets forth certain information with respect to the proved reserves attributable to ourinvestment in Exaro, as of December 31, 2017, as estimated by W.D. Von Gonten and Associates (“Von Gonten”), and our netshare of Exaro’s average daily production for the year ended December 31, 2017: Estimated Proved % Crude Oil / % Natural % Natural Gas % Proved Average Daily Region Reserves (Bcfe) Condensate Gas Liquids Developed Production (Mmcfe/d) Investment in Exaro 30.7 6% 94% —% 99% 26.4 Our StrategyOur long-term business strategy is:• Enhancing our portfolio by dedicating the majority of our drilling capital to our oil and liquids-richopportunities. A key element of our long term strategy is to continue to develop the oil and natural gas liquids resourcepotential that we believe exists in numerous formations within our various oil/liquids weighted resource plays, and wherepossible, to expand our presence in those plays. Due to the current superior economics of oil production, as compared tonatural gas, we expect to focus on oil and liquids-weighted opportunities as we strive to transition from a heavily weightednatural gas production profile to a more balanced reserve and production profile between oil/liquids and natural gas. For theforeseeable future, we will focus our drilling capital on the Southern Delaware Basin position, as we believe it providesexcellent returns in the current oil price environment. We believe we possess the flexibility to focus on the development ofour Southern Delaware Basin potential without jeopardizing our acreage position in other areas, as the vast majority of ouracreage in those other areas is held by production or has longer term lease terms. • Pursuing accretive, opportunistic acquisitions that meet our strategic and financial objectives. We intend toevaluate opportunistic acquisitions of crude oil and natural gas properties, both undeveloped and developed, in areas wherewe currently have a presence and/or specific operating expertise, and to pursue undeveloped acreage positions, at reasonablecost, in new areas that we believe to be complementary to our existing plays and feel have significant exploration,exploitation or operational upside. We believe that the ongoing low commodity price environment might provide growthopportunities for us through potential corporate combinations.• Selectively exploiting, in a higher commodity price environment, our existing onshore producing conventionalnatural gas property portfolio to generate additional cash flows. We believe our multi-year drilling inventory of2 (1) Table of Contentsexploitation opportunities on our existing onshore conventional natural gas oriented producing properties provides us with asolid, dependable platform for future reserve and production growth. We will continuously monitor the commodity priceenvironment and technical advancements, and if warranted, make adjustments to our investment strategy.We currently expect to focus our 2018 capital program on our Southern Delaware Basin acreage, which is expectedto continue to generate positive returns on our drilling investment in the current price environment. Assuming results are asexpected, and market conditions remain favorable, we will proceed to drill throughout the year. Until a sustainedimprovement in commodity prices occurs, we do not currently expect to devote meaningful capital to our other areas, butwill devote capital to those areas to fulfill leasehold commitments, preserve core acreage and, where determined appropriateto do so, expand our presence in those existing areas. We will continue to make balance sheet strength a priority in 2018 bylimiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales.We will continue to evaluate new organic opportunities for growth and will continue to evaluate pursuing stressed ordistressed acquisition opportunities that may arise in this low price environment. We retain the flexibility to be moreaggressive in our drilling plans should planned results exceed expectations, should commodity prices continue to improve,and/or we continue to show progress in reducing our drilling and completion costs, thereby making an expansion of ourdrilling program an appropriate business decision. Our 2018 capital expenditure budget is initially expected to include thefollowing:·Pecos County, Texas – We forecast capital expenditures of approximately $52 million for drilling in this area.·Other – We forecast capital expenditures of approximately $2 million for unproved leasehold acquisition costs.PropertiesOffshore Gulf of MexicoAs of December 31, 2017, our offshore assets consisted of six federal and five state of Louisiana company-operatedwells in the shallow waters of the GOM. These 11 wells are located in two fields. The following summary table sets forthcertain information with respect to our offshore reserves as of December 31, 2017 and average daily offshore production forthe year ended December 31, 2017: Average Daily Estimated Proved % Crude Oil / % Natural % NaturalGas % Proved Production Field Reserves (Bcfe) Condensate Gas Liquids Developed (Mmcfe/d) Dutch and Mary Rose 72.0 3% 81% 16% 100% 33.7 Vermilion 170 3.4 4% 84% 12% 100% 3.8 South Timbalier 17 — —% —% —% —% 0.2 Total 75.4 37.7 Dutch and Mary Rose FieldWe operate five wells located in federal waters at Eugene Island 10 (“Dutch”), and five wells located in adjacentLouisiana state waters (“Mary Rose”). All Dutch and Mary Rose wells flow to a Company-owned and operated productionplatform at Eugene Island 11. While we do not own the lease for the Eugene Island 11 block, this does not impact our abilityto operate our facilities located on that block. Operators in the GOM may place platforms and facilities on any locationwithout having to own the lease, provided that permission and proper permits from the Bureau of Safety and EnvironmentalEnforcement (“BSEE”) have been obtained. We have obtained such permission and permits. We installed our facilities atEugene Island 11 because that was the optimal gathering location in proximity to our wells and marketing pipelines.From our production platform we are able to access two separate gas markets thereby minimizing downtime risk andproviding the ability to select the best sales price for our natural gas production. Oil and natural gas production can flowthrough our 20” gas pipeline to third-party owned and operated onshore processing facilities near Patterson, Louisiana.Alternatively, natural gas can flow via our 8” pipeline to a third-party owned and operated onshore processing facility atBurns Point, Louisiana. We have recently completed a 6” oil pipeline to third-party owned and operated onshore processingfacilities in St. Mary Parish, Louisiana, providing us with two separate oil markets. Production facilities include a turbinetype compressor capable of servicing all ten Dutch and Mary Rose wells at the Eugene Island 11 platform. Condensate canalso flow to onshore markets and multiple refineries. 3 Table of ContentsVermilion 170 FieldWe own and operate one well located in federal waters with a dedicated production facility at Vermilion 170.Production from this platform, which includes compression equipment, flows via the Sea Robin Pipeline to a third-partyowned and operated onshore processing plant.Other OffshoreOur Ship Shoal 263 field, located in federal waters, and South Timbalier 17 field, located in Louisiana state waters,were historically included in “Other Offshore”. During 2017, the Ship Shoal field was permanently plugged and abandoned,and the production facilities were removed and sold. In late 2017, the South Timbalier well was permanently plugged andabandoned, and the production facilities were removed.Onshore PropertiesSouthern Delaware Basin Since the closing of the Acquisition in late July 2016, we and our partner have increased our leasehold footprint toapproximately 6,800 acres, net to Contango. As of December 31, 2017, we currently estimate that we have proven reserves of55.5 Bcfe and close to 400 gross drilling locations, initially targeting the Wolfcamp A, Wolfcamp B and Second Bone Springformations. Substantially all of the locations can accommodate 10,000 foot laterals. As previously disclosed, during 2017 webrought our first four Southern Delaware Basin wells on production (two in the Upper Wolfcamp A, one in the MiddleWolfcamp A, and one in the Lower Wolfcamp A), with an average maximum 30 day initial production rate (“IP”) of 968Boed (72% oil). In mid-December 2017, we brought our fifth horizontal well on production, the Crusader #1H, targeting the LowerWolfcamp A. This well was drilled to a total measured depth (“TMD”) of 20,275 feet, including a 10,184 foot lateral, and wascompleted with 50 stages of fracture stimulation, reaching a 30-day average IP of 389 Boed (67% oil). Our sixth well, theRagin Bull #3H, targeting the Lower Wolfcamp A, was spud in November 2017. This well was drilled to a TMD of 20,570feet, including a 10,325 foot lateral, and was completed with 50 stages of fracture stimulation. Production began in January2018, and the well reached a 30-day average IP of 716 Boed (67% oil). Our seventh well, the River Rattler #1H, our first Wolfcamp B test, was spud in December 2017. This well wasdrilled to a TMD of 20,710 feet, including a 10,275 foot lateral, and was completed with 50 stages of fracture stimulation.Production is expected to begin in mid-March 2018. We continue to identify cost efficiencies in our drilling efforts, asevidenced by the fact that the Ragin Bull #3H and River Rattler #1H have been our most efficient wells to date, taking only27 days from spud to TMD. Our eighth well, the Ragin Bull #2H, our second Wolfcamp B test, was spud in January 2018. This well was drilledto a TMD of 20,624 feet, including a 10,344 foot lateral, and is currently waiting on completion with 50 stages of fracturestimulation. There have been multiple Wolfcamp B wells adjacent to our leasehold that have been put on productionrecently by our offset operators, thereby derisking the Wolfcamp B in the area and providing encouragement for thedevelopment of that formation on our acreage.Southeast Texas (Woodbine)As of December 31, 2017, our Southeast Texas region included approximately 29,300 gross (17,100 net) acres,proven reserves of 30.9 Bcfe, and 81 gross (45 net) producing wells. No drilling capital was allocated to this area in 2016 or2017 due to the low commodity price environment. For 2018, our current budget does not anticipate further drilling in thisarea, but should we experience sustained improvement in commodity prices, we could increase our activity. We currentlyhave approximately 12,100 net acres in Madison and Grimes counties, with a multi-year inventory of potential drillinglocations encompassing the Woodbine, Eagle Ford Shale and/or Georgetown/Buda formations.South Texas (Buda/Eagle Ford)As of December 31, 2017, our South Texas region included approximately 89,600 gross (40,800 net) acres, provenreserves of 25.7 Bcfe, and 217 gross (96.5 net) producing wells. We believe approximately 16,700 gross (7,800 net) acres tobe prospective for the Buda and Eagle Ford Shale plays. No drilling activity has been conducted in4 Table of Contentsthis area since 2014 due to the reduction in our capital expenditure programs in response to the commodity priceenvironment. We do not anticipate devoting any drilling capital to this area in 2018.Our estimated net proven Buda/Eagle Ford reserves in this area were 12.2 Bcfe, comprised of 94% liquids, with 41gross (17.6 net) producing wells, as of December 31, 2017.South Texas (Elm Hill Project) As of December 31, 2017, we held approximately 4,900 gross acres (2,700 net) in Fayette, Gonzales, Caldwell andBastrop counties, Texas. There was no drilling activity in 2016 or 2017, and we recognized an impairment expense of $6.8million for the year ended December 31, 2016. The Company and its partner have no plans to further test this area.The remaining 68,000 gross (30,300 net) acres in our South Texas region are located in our conventional fields thatproduce primarily from the Wilcox, Frio, and Vicksburg sands. Our estimated net proved conventional reserves in this regionwere 12.1 Bcfe, comprised of 71% gas, with 176 gross (78.9 net) producing wells, as of December 31, 2017.Weston County, Wyoming (N. Cheyenne Project)In 2015, we began drilling the first of three successful wells in this area targeting the Muddy Sandstone formation.Based on current results, a sustained improvement in oil prices will be needed to justify allocation of drilling capital to thisarea compared to our Southern Delaware Basin position. As a result of drilling these wells, we have satisfied the right to earn35,000 net acres (approximately 4% of which is held by production).Natrona County, Wyoming (FRAMS Project)We spud our first well targeting the Mowry Shale in 2015, which proved to be unsuccessful. As a result, werecognized $6.7 million in exploration expenses for the cost of drilling the well for the year ended December 31, 2016 and$2.9 million in impairment expense in 2016 related to our unproved acreage in Natrona County, Wyoming. No drillingactivity was conducted in this area in 2017.Other (East Texas)As of December 31, 2017, our East Texas region included approximately 6,000 gross (3,600 net) acres primarily inSan Augustine County, with proven reserves of 0.5 Bcfe comprised of 90% gas, and 10 gross (5.1 net) producing wells. Webelieve that the further exploitation of our acreage in the Haynesville, Mid-Bossier and James Lime formations may providelong-term natural gas reserve and production growth potential in the future. There has been renewed interest in this area byoffset operators as they experiment with new frac techniques and refracing of previously drilled wells. We will continue tomonitor that activity and results; however, we do not anticipate devoting any capital to this area during 2018. As ofDecember 31, 2017, substantially all of our acreage in our East Texas region was held by production.Other (Colorado)On December 30, 2016, we completed the sale of all of our Colorado assets to an independent oil and gas companyfor an aggregate purchase price of $5.0 million, subject to normal post-closing adjustments. The properties sold consisted ofapproximately 16,000 gross (11,200 net) acres and associated producing vertical wells primarily in Adams and Weldcounties. At the time of sale, the sold properties had proved reserves of 4.2 Bcfe and during 2016 average net dailyproduction was 0.4 Mmcfe/d.OtherAs of December 31, 2017, we held approximately 8,300 gross (6,000 net) mostly undeveloped acres in Louisiana,Mississippi, and North Texas.Impairment of Long-Lived AssetsWe recognized approximately $1.8 million in non-cash impairment charges in 2017. Under US GAAP, animpairment charge is required when the unamortized capital cost of any individual property within the Company’s5 Table of Contentsproved property base exceeds the risked estimated future net cash flows from the proved, probable and possible reserves forthat property. Included in the impairment charge for the year is approximately $0.3 million related to proved propertyimpairment for our Tuscaloosa Marine Shale (“TMS”) properties, a shale play in central Louisiana and Mississippi, due torevised estimated reserves. The 2017 impairment charges also consist of $1.5 million related to the partial impairment of twounused offshore platforms in onshore storage. If oil and/or natural gas prices decline from prices at December 31, 2017, we may be required to record additionalnon-cash impairment in the future, thereby impacting our financial results for that period.Onshore InvestmentsJonah Field – Sublette County, WyomingOur wholly-owned subsidiary, Contaro Company (“Contaro”), owns a 37% ownership interest in Exaro. As ofDecember 31, 2017, we had invested approximately $46.9 million in Exaro, with no anticipation of making any additionalequity contributions, as our commitment to invest in Exaro expired on March 31, 2017. We account for Contaro’s ownershipin Exaro using the equity method of accounting, and therefore, do not include its share of individual operating results,reserves or production in those reported for our consolidated results.As of December 31, 2017, Exaro had 645 wells on production over its 5,760 gross acres (1,040 net acres), with aworking interest between 2.4% and 32.5%. These wells were producing at a rate of approximately 26 Mmcfe/d, net to Exaro.The operator of these interests has applied for multiple drilling permits for horizontal wells that will be located on parts ofour acreage. Exaro’s working interest in the drilling spacing units for the applied for horizontal wells ranges from 1% to 6%.As of December 31, 2017, the operator has been approved to drill two horizontal wells, in which Exaro has a net workinginterest of 2.4%. For the year ended December 31, 2017, the Company recognized a net investment gain of approximately$2.7 million, net of no tax expense, as a result of its investment in Exaro. As of December 31, 2017, reserves attributable toour investment in Exaro were 30.7 Bcfe. See Note 10 to our Financial Statements - “Investment in Exaro Energy III LLC” foradditional details related to this investment.Title to PropertiesFrom time to time, we are involved in legal proceedings relating to claims associated with ownership interests in ourproperties. We believe we have satisfactory title to all of our producing properties in accordance with standards generallyaccepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operatingagreements, and liens for current taxes and other burdens, which we believe do not materially interfere with the use of oraffect the value of such properties. As is customary in the industry in the case of undeveloped properties, little investigationof record title is made at the time of acquisition (other than a preliminary review of local records). Detailed investigations,including a title opinion rendered by a licensed independent third party attorney, are typically made before commencementof drilling operations.We have granted mortgage liens on substantially all of our natural gas and crude oil properties to secure our seniorsecured revolving credit facility. These mortgages and the related credit agreement contain substantial restrictions andoperating covenants that are customarily found in credit agreements of this type. See Note 12 to our Financial Statements ‑“Long-Term Debt” for further information.Marketing and PricingWe derive our revenue principally from the sale of natural gas and oil. As a result, our revenues are determined, to alarge degree, by prevailing natural gas and oil prices. We sell a portion of our natural gas production to purchasers pursuantto sales agreements which contain a primary term of up to three years and crude oil and condensate production to purchasersunder sales agreements with primary terms of up to one year. The sales prices for natural gas are tied to industry standardpublished index prices, subject to negotiated price adjustments, while the sale prices for crude oil are tied to industrystandard posted prices subject to negotiated price adjustments.We typically utilize commodity price hedge instruments to minimize exposure to declining prices on our crude oil,natural gas and natural gas liquids production, by using a series of swaps and/or costless collars. Unrealized gains or lossesassociated with hedges vary period to period, and will be a function of hedges in place, the strike prices of those hedges andthe forward curve pricing for the commodities being hedged. 6 Table of ContentsAs of December 31, 2017, we had the following derivative contracts in place with members of our bank group: Commodity Period Derivative Volume/Month Price/UnitNatural Gas Jan 2018 - July 2018 Swap 370,000 MMBtus $3.07 Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $3.07 Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $3.07 Oil Jan 2018 - June 2018 Swap 20,000 Bbls $56.40 Oil July 2018 - Oct 2018 Collar 20,000 Bbls $52.00 - 56.85 Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $52.00 - 56.85 Oil Jan 2018 - Dec 2018 Collar 2,000 Bbls $52.00 - 58.76 Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $50.00 - 58.00 In January 2018, we entered into the following additional derivative contracts with members of our bank group: Commodity Period Derivative Volume/Month Price/UnitOil Jan 2018 - July 2018 Collar 6,000 Bbls $58.00 - 68.00 Oil Nov 2018 - Dec 2018 Collar 5,000 Bbls $58.00 - 68.00 Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $52.00 - 59.45 (1)Based on Henry Hub NYMEX natural gas prices.(2)Based on Argus Louisiana Light Sweet crude oil prices.(3)Based on West Texas Intermediate crude oil prices.Decreases in commodity prices would adversely affect our revenues, profits and the value of our proved reserves.Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause thesefluctuations are:·The domestic and foreign supply of natural gas and oil.·Overall economic conditions.·The level of consumer product demand.·Adverse weather conditions and natural disasters.·The price and availability of competitive fuels such as heating oil and coal.·Political conditions in the Middle East and other natural gas and oil producing regions.·The level of LNG imports/exports.·Domestic and foreign governmental regulations.·Special taxes on production.·The loss of tax credits and deductions.7 (1)(1)(1)(2)(2)(2)(3)(2)(2)(2)(3) Table of ContentsHistorically, we have been dependent upon a few purchasers for a significant portion of our revenue. The largestpurchaser of our production for the year ended December 31, 2017, calculated on an equivalent basis, was ConocoPhillipsCompany (51.2%). This concentration may increase our overall exposure to credit risk, and our purchasers will likely besimilarly affected by changes in economic and industry conditions. Our financial condition and results of operations couldbe materially adversely affected if one or more of our significant purchasers fails to pay us or ceases to acquire our productionon terms that are favorable to us. However, we believe our current purchasers could be replaced by other purchasers undercontracts with similar terms and conditions.CompetitionThe oil and gas industry is highly competitive, and we compete with numerous other companies. Our competitors inthe exploration, development, acquisition and production business include major integrated oil and gas companies as well asnumerous independent companies, including many that have significantly greater financial resources.The primary areas in which we encounter substantial competition are in locating and acquiring desirable leaseholdacreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties andobtaining purchasers and transporters for the natural gas and crude oil we produce. There is also competition betweenproducers of natural gas and crude oil and other industries producing alternative energy and fuel. Furthermore, competitiveconditions may be substantially affected by various forms of energy legislation and/or regulation considered from time totime by federal, state and local governments; however, it is not possible to predict the nature of any such legislation orregulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however,substantially increase the costs of exploring for, developing or producing natural gas and crude oil and may prevent or delaythe commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.Governmental Regulations and Industry Matters Industry RegulationsThe availability of a ready market for crude oil, natural gas and natural gas liquids production depends uponnumerous factors beyond our control. These factors include regulation of crude oil, natural gas and natural gas liquidsproduction, federal, state and local regulations governing environmental quality and pollution control, state limits onallowable rates of production by well or proration unit, the amount of crude oil, natural gas and natural gas liquids availablefor sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing ofcompetitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas orlack of an available natural gas pipeline in the area in which the well is located. State and federal regulations generally areintended to prevent waste of crude oil, natural gas and natural gas liquids, protect rights to produce crude oil, natural gas andnatural gas liquids between owners in a common reservoir, control the amount of crude oil, natural gas and natural gasliquids produced by assigning allowable rates of production, and protect the environment. Pipelines are subject to thejurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects ofwhich cannot be predicted.The following discussion summarizes the regulation of the U.S. oil and gas industry. Such statutes, rules, regulationsand government orders may be changed or reinterpreted from time to time in response to economic or political conditions,and there can be no assurance that such changes or reinterpretations will not materially adversely affect our results ofoperations and financial condition. The following discussion is not intended to constitute a complete discussion of thevarious statutes, rules, regulations and governmental orders to which our operations may be subject.Regulation of Crude Oil, Natural Gas and Natural Gas Liquids Exploration and ProductionOur operations are subject to various types of regulation at the federal, state and local levels. Such regulationincludes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells andregulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties uponwhich wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations.Our operations are also subject to various conservation laws and regulations. These include the regulation of the size ofdrilling and spacing units or proration units and the density of wells that may be drilled in and the unitization or pooling ofcrude oil and natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitateexploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In8 Table of Contentsareas where pooling is voluntary, it may be more difficult to form units, and therefore more difficult to develop a project, ifthe operator owns less than 100% of the leasehold. In addition, state conservation laws, which establish maximum rates ofproduction from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certainrequirements regarding the ratability of production. The effect of these regulations may limit the amount of crude oil, naturalgas and natural gas liquids we can produce from our wells and may limit the number of wells or the locations at which we candrill. The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects ourprofitability. Inasmuch as such laws and regulations are frequently expanded, amended and interpreted, we are unable topredict the future cost or impact of complying with such regulations.Regulation of Sales and Transportation of Natural GasFederal legislation and regulatory controls have historically affected the price of natural gas produced by us, and themanner in which such production is transported and marketed. Under the Natural Gas Act of 1938 (the “NGA”), the FederalEnergy Regulatory Commission (the “FERC”) regulates the interstate transportation and the sale in interstate commerce forresale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulatednatural gas prices for all “first sales” of natural gas, including all sales by us of our own production. As a result, all of ourdomestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may bein effect. However, the Decontrol Act did not affect the FERC’s jurisdiction over natural gas transportation.Section 1(b) of the NGA exempts gas gathering facilities from the FERC's jurisdiction. We believe that the gasgathering facilities we own meet the traditional tests the FERC has used to establish a pipeline system's status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities.Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is thesubject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subjectto change based on future determinations by the FERC and the courts. While we own some gas gathering facilities, we alsodepend on gathering facilities owned and operated by third parties to gather production from our properties, and therefore,we are affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or stateregulation affect the rates charged for gathering services, we also may be affected by these changes. Accordingly, we do notanticipate that we would be affected any differently than similarly situated gas producers.Under the provisions of the Energy Policy Act of 2005 (the “2005 Act”), the NGA has been amended to prohibitmarket manipulation by any person, including marketers, in connection with the purchase or sale of natural gas, and theFERC has issued regulations to implement this prohibition. The Commodity Futures Trading Commission (the “CFTC”) alsoholds authority to monitor certain segments of the physical and futures energy commodities market including oil and naturalgas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedgingactivities that we undertake, we are thus required to observe anti-market manipulation laws and related regulations enforcedby FERC and/or the CFTC. FERC holds substantial enforcement authority, including the ability to potentially assessmaximum civil penalties of approximately $1.24 million per day per violation, subject to annual adjustment for inflation.CFTC also holds substantial enforcement authority, including the ability to potentially assess maximum civil penalties of upto approximately $1.12 million per day per violation or triple the monetary gain.Under the 2005 Act, the FERC has also established regulations that are intended to increase natural gas pricingtransparency through, among other things, new reporting requirements and expanded dissemination of information about theavailability and prices of gas sold. For example, on December 26, 2007, FERC issued a final rule on the annual natural gastransaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requiresbuyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, tosubmit on May 1 of each year an annual report to FERC describing their aggregate volumes of natural gas purchased or soldat wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formationof price indices. Order No. 704 also requires market participants to indicate whether they report prices to any indexpublishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. It is theresponsibility of the reporting entity to determine which individual transactions should be reported based on the guidance ofOrder No. 704 as clarified in orders on clarification and rehearing. In addition, to the extent that we enter into transportationcontracts with interstate pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use ofsuch interstate capacity. Any failure on our part to comply with the FERC’s regulations could result in the imposition of civiland criminal penalties.9 Table of ContentsOur natural gas sales are affected by intrastate and interstate gas transportation regulation. Following theCongressional passage of the Natural Gas Policy Act of 1978 (the “NGPA”), the FERC adopted a series of regulatory changesthat have significantly altered the transportation and marketing of natural gas. Beginning with the adoption of OrderNo. 436, issued in October 1985, the FERC has implemented a series of major restructuring orders that have requiredinterstate pipelines, among other things, to perform “open access” transportation of gas for others, “unbundle” their sales andtransportation functions, and allow shippers to release their unneeded capacity temporarily and permanently to othershippers. As a result of these changes, sellers and buyers of gas have gained direct access to the particular interstate pipelineservices they need and are better able to conduct business with a larger number of counterparties. We believe these changesgenerally have improved our access to markets while, at the same time, substantially increasing competition in the naturalgas marketplace. It remains to be seen, however, what effect the FERC’s other activities will have on access to markets, thefostering of competition and the cost of doing business. We cannot predict what new or different regulations the FERC andother regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. We do not believethat we will be affected by any such new or different regulations materially differently than any other seller of natural gaswith which we compete.In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the morerecent trend has been in favor of deregulation, or “lighter handed” regulation, and the promotion of competition in the gasindustry. There regularly are other legislative proposals pending in the federal and state legislatures that, if enacted, wouldsignificantly affect the natural gas industry. At the present time, it is impossible to predict what proposals, if any, mightactually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Wedo not believe that we will be affected by any such new legislative proposals materially differently than any other seller ofnatural gas with which we compete.Oil Price Controls and Transportation RatesSales prices of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices.Our sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (the“FTC”) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantialenforcement authority under these regulations, including the ability to potentially assess maximum civil penalties ofapproximately $1.18 million per day per violation, subject to annual adjustment for inflation. Our sales of thesecommodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.The price we receive from the sale of these products may be affected by the cost of transporting the products tomarket. Much of the transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERCimplemented regulations generally grandfathering all previously approved interstate transportation rates and establishing anindexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certainconditions and limitations. The FERC’s regulation of crude oil and natural gas liquids transportation rates may tend toincrease the cost of transporting crude oil and natural gas liquids by interstate pipelines, although the annual adjustmentsmay result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annualchange in the applicable index and the actual cost changes experienced in the oil pipeline industry. We are not able at thistime to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crudeoil production from our crude oil producing operations.There regularly are other legislative proposals pending in the federal and state legislatures that, if enacted, wouldsignificantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, mightactually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Wedo not believe that we will be affected by any such new legislative proposals materially differently than any other seller ofpetroleum with which we compete.Environmental and Occupational Health and Safety MattersOur crude oil and natural gas exploration, development and production operations are subject to stringent federal,regional, state and local laws and regulations governing occupational health and safety aspects of our operations, thedischarge of materials into the environment, or otherwise relating to environmental protection. Numerous governmentalauthorities, including the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the powerto enforce compliance with these laws and regulations and the permits issued under them, which may cause us to incursignificant capital expenditures or costly actions to achieve and maintain compliance. Failure to comply with these laws andregulations may result in the assessment of sanctions, including administrative,10 Table of Contentscivil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the occurrence ofdelays or restrictions in permitting or performance of projects and the issuance of orders enjoining some or all of ouroperations in affected areas. Public interest in the protection of the environment has increased dramatically in recent years.The trend in environmental legislation and regulations in recent years has been to place more restrictions and limitations onactivities that may affect the environment, which is expected to result in increased costs of doing business and consequentlyaffect profitability.The Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), alsoknown as the “Superfund Law”, and similar state laws, impose strict joint and several liability, without regard to fault or thelegality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributedto the release of a “hazardous substance” into the environment. These potentially responsible persons include the current orpast owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for thedisposal of the hazardous substances released at the site. Persons who are or were responsible for releases of hazardoussubstances under CERCLA may be subject to liability for the costs of cleaning up the hazardous substances that have beenreleased into the environment, for damages to natural resources and for the costs of certain health studies, and it is notuncommon for neighboring landowners and other third parties to file claims for personal injury and property damageallegedly caused by the hazardous substances released into the environment. We generate materials in the course of ouroperations that may be regulated as hazardous substances.We also generate wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (the“RCRA”), and comparable state statutes. The RCRA imposes strict requirements on the generation, storage, treatment,transportation and disposal of nonhazardous and hazardous wastes, and the EPA and analogous state agencies stringentlyenforce the approved methods of management and disposal of these wastes. While the RCRA currently exempts certaindrilling fluids, produced waters, and other wastes associated with exploration, development and production of crude oil andnatural gas from regulation as hazardous wastes, allowing us to manage these wastes under RCRA’s less stringent non-hazardous waste requirements, we can provide no assurance that this exemption will be preserved in the future. For example,following in response to the filing of a lawsuit by several non-governmental environmental groups against the EPA for theagency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmentalgroups entered into an agreement that was finalized in a consent decree issued by the U.S. District Court for the District ofColumbia in December 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemakingfor revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision ofthe regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decreerequires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Any removalof this exclusion could increase the amount of waste we are required to manage and dispose of as hazardous waste rather thannon-hazardous waste, and could cause us to incur increased operating costs, which could have a significant impact on us aswell as the natural gas and oil industry in general.The Clean Air Act, as amended (the “CAA”), and comparable state laws restrict the emission of air pollutants frommany sources and also impose various monitoring and reporting requirements. These laws and regulations may require us toobtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantlyincrease air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment ortechnologies to control emissions. Obtaining permits has the potential to delay the development of crude oil and natural gasprojects. Over the next several years, we may be required to incur certain capital expenditures for air pollution controlequipment or other air emissions-related issues.Based on findings made by the EPA that emissions of carbon dioxide, methane and other greenhouse gases(“GHGs”) present an endangerment to public health and the environment, the EPA adopted regulations under existingprovisions of the CAA that, among other things, impose permit reviews and restrict emissions of GHGs from certain largestationary sources. These EPA regulations could adversely affect our operations and restrict or delay our ability to obtain airpermits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHGemissions from specified sources in the United States on an annual basis, including certain onshore and offshore productionfacilities, which include the majority of our operations. We are monitoring and reporting on GHG emissions from certain ofour operations.While Congress has, from time to time considered legislation to reduce emissions of GHGs, there has not beensignificant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In theabsence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at11 Table of Contentstracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHGemissions to acquire and surrender emission allowances in return for emitting those GHGs. Moreover, in December 2015, theUnited States joined other countries of the United Nations in preparing an agreement requiring member countries to reviewand establish goals for limiting GHG emissions. This “Paris Agreement” was signed by the United States in April 2016 andentered into force in November 2016; however, this agreement does not create any binding obligations for nations to limittheir GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions. However, in August 2017,the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the ParisAgreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016,which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or theterms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at thistime.Although it is not possible at this time to predict how legislation or new regulations that may be adopted to addressGHG emissions would impact our business, any such future international, federal or state laws or regulations that imposereporting obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operationscould require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.The Federal Water Pollution Control Act, as amended (the “Clean Water Act”) and analogous state laws imposerestrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. Anysuch discharge of pollutants into regulated waters is prohibited except in accordance with the terms of an issued permit. Spillprevention, control and countermeasure plan requirements under federal law require appropriate containment berms andsimilar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill,rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage undergeneral permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits thedischarge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and stateregulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits orother requirements of the Clean Water Act and analogous state laws and regulations.Our oil and natural gas exploration and production operations generate produced water, drilling muds and otherwaste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurfaceformations. The disposal of oil and natural gas wastes into underground injection wells are subject to the Safe DrinkingWater Act, as amended (the “SDWA”), and analogous state laws. The Underground Injection Well Program under the SDWArequires that we obtain permits from the EPA or analogous state agencies for our disposal wells, establishes minimumstandards for injection well operations, restricts the types and quantities that may be injected, and prohibits the migration offluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions ofthe injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuanceof fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, andimposition of liability by third parties for alternative water supplies, property damages and personal injuries. Furthermore, inresponse to a growing concern that the injection of produced water and other fluids into belowground disposal wells triggersseismic activity in certain areas, some states, including Texas, where we operate, have imposed, and other states areconsidering imposing, additional requirements in the permitting or operation of produced water injection wells. In Texas, theTexas Railroad Commission (“TRC”) has adopted a final rule governing the permitting or re-permitting of disposal wells thatrequires, among other things, the submission of information on seismic events occurring within a specified radius of thedisposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. Ifthe permittee or an applicant of a disposal well fails to demonstrate that the injected fluids are confined to the disposal zoneor if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then theTRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Increasedregulation and attention given to induced seismicity could lead to greater opposition, including litigation, to oil and naturalgas activities utilizing injection wells for produced water disposal. These existing and any new seismic requirementsapplicable to disposal wells that impose more stringent permitting or operational requirements could result in added costs tocomply or, perhaps, may require alternative methods of disposing of produced water and other fluids, which could delayproduction schedules and also result in increased costs.The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on“responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters.The OPA applies to vessels, onshore facilities and offshore facilities, including exploration and production12 Table of Contentsfacilities that may affect waters of the United States. Under OPA, responsible parties including owners and operators ofonshore facilities and lessees and permittees of offshore leases may be held strictly liable for oil cleanup costs and naturalresource damages as well as a variety of public and private damages that may result from oil spills. While liability limitsapply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence orwillful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist tothe liability imposed by the OPA. In addition, in January 2018, the federal Bureau of Ocean Energy Management (“BOEM”)has raised OPA’s damages liability cap to $137.7 million. OPA requires owners and operators of offshore oil productionfacilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding toan oil spill, and to prepare and submit for approval oil spill response plans. These oil spill response plans must detail theaction to be taken in the event of a spill; identify contracted spill response equipment, materials, and trained personnel; andidentify the time necessary to deploy these resources in the event of a spill. In addition, OPA currently requires a minimumfinancial responsibility demonstration of between $35 million and $150 million for companies operating on the federalOuter Continental Shelf (“OCS”) waters, including the Gulf of Mexico. We are currently required to demonstrate, on anannual basis, that we have ready access to $35 million that can be used to respond to an oil spill from our facilities on theOCS. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject toadditional state and local clean-up requirements or incur liability under state and local laws.Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/orcrude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand orother proppant and chemical additives under pressure into targeted subsurface formations to stimulate production. Weroutinely use hydraulic fracturing techniques in many of our completion programs. Hydraulic fracturing typically isregulated by state oil and natural gas commissions, or other similar state agencies, but several federal agencies have alsoasserted regulatory authority over, or conducted investigations that focus upon, certain aspects of the process, including asuite of proposed rulemakings and final rules issued by the EPA and the federal Bureau of Land Management (the “BLM”),which legal requirements, to the extent finalized and implemented by the agencies, may impose more stringent requirementsrelating to the composition of fracturing fluids, emissions and discharges from hydraulic fracturing, chemical disclosures, andperformances of fracturing activities on federal and Indian lands. Also, in December 2016, the EPA released its final report onthe potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associatedwith hydraulic fracturing may impact drinking water under certain circumstances.Congress has from time to time considered, but not enacted, legislation to provide for federal regulation of hydraulicfracturing and to require disclosure of the chemicals used in the hydraulic fracturing process while, at the state level, severalstates, including Texas and Wyoming, where we operate, have adopted, and other states are considering adopting legalrequirements that could impose more stringent permitting, public disclosure, or well construction requirements on hydraulicfracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach takenby the State of New York. Local government may also seek to adopt ordinances within their jurisdictions regulating the time,place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringentfederal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, wecould incur potentially significant added costs to comply with such requirements, experience delays or curtailment in thepursuit of exploration, development, or production activities, and perhaps even be precluded from drilling or completingwells.Oil and natural gas exploration, development and production activities on federal lands, including Indian lands andlands administered by the BLM, are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requiresfederal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact theenvironment. 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 detailedEnvironmental Impact Statement that may be made available for public review and comment. Governmental permits orauthorizations that are subject to the requirements of NEPA are required for exploration and development projects on federaland Indian lands. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects.Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.Environmental laws such as the Endangered Species Act, as amended (“ESA”), may impact exploration,development and production activities on public or private lands. The ESA provides broad protection for species of fish,wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered13 Table of Contentsspecies. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our facilities may belocated in areas that are designated as habitat for endangered or threatened species. If endangered species are located in areasof the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations,such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of one or moresettlements entered into by the U.S. Fish and Wildlife Service (the “FWS”), the agency is required to make a determination onlisting of numerous species as endangered or threatened under the ESA by specified timelines. The designation of previouslyunprotected species as threatened or endangered in areas where underlying property operations are conducted could cause usto incur increased costs arising from species protection measures, time delays or limitations on our drilling programactivities, which costs delays or limitation could have an adverse impact on our ability to develop and produce reserves.We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, and comparablestate statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational Safety andHealth Administration hazard communication standard, the EPA community right-to-know regulations under Title III of thefederal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintainedconcerning hazardous materials used or produced in our operations and that this information be provided to employees, stateand local government authorities and citizens.In recent years, the BOEM and the BSEE, each agencies of the U.S. Department of the Interior, have imposed morestringent permitting procedures and regulatory safety and performance requirements for wells in federal waters. In addition,states may adopt and implement similar or more stringent legal requirements applicable to exploration and productionactivities in state waters. Compliance with these more stringent regulatory restrictions, together with any uncertainties orinconsistencies in current decisions and rulings by governmental agencies, delays in the processing and approval of drillingpermits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatoryinitiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoingdevelopment efforts. In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in thefuture that could result in additional costs, delays, restrictions or obligations with respect to oil and natural gas explorationand production operations conducted offshore. Any new rules, regulations or legal initiatives could delay or disrupt ouroperations, increase the risk of expired leases due to the time required to develop new technology, result in increasedsupplemental bonding requirements and limit activities in certain areas, or cause us to incur penalties, fines, or shut-inproduction at one or more of our facilities. If the BOEM determines that increased financial assurance is required inconnection with our offshore facilities but we are unable to provide the necessary supplemental bonds or other forms offinancial assurance, the BOEM could impose monetary penalties or require our operations on federal leases to be suspendedor cancelled. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissionsrequirements relating to offshore oil and natural gas activity on the OCS. Additionally, the BOEM issued a Notice to Lesseesand Operators (the “NTL #2016-N01”) that became effective in September 2016 and bolsters supplemental bondingprocedures for the decommissioning of offshore wells, platforms, pipelines and other facilities. Also, if material spillincidents were to occur, the United States could elect to again issue directives to temporarily cease drilling activities and, inany event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil andnatural gas exploration and development, any of which developments could have a material adverse effect on our business.Any one or more of the offshore-related matters described above could have a material adverse effect on our business,financial condition and results of operations.These regulatory actions, or any new rules, regulations or legal initiatives could delay or disrupt our operations,increase the risk of expired leases due to the time required to develop new technology, result in increased supplementalbonding and costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one ormore of our facilities or result in the suspension or cancellation of leases. Moreover, under existing BOEM rules relating toassignment of offshore leases and other legal interests on the OCS, assignors of such interest may be held jointly andseverally liable for decommissioning of OCS facilities existing at the time the assignment was approved by the BOEM, in theevent that the assignee is unable or unwilling to conduct required decommissioning. In the event that we, in the role ofassignor, receive orders from the BOEM to decommission OCS facilities that one of our assignees of offshore facilities isunwilling or unable to perform, we could incur costs to perform those decommissioning obligations, which costs could bematerial. If the BOEM determines that increased financial assurance is required in connection with our or any previouslyassigned offshore facilities but we are unable to provide the necessary supplemental bonds or other forms of financialassurance, the BOEM could impose monetary penalties or require our operations on federal leases to be suspended orcancelled.14 Table of ContentsDuring 2017, however, with the issuance of Order 3350 in May 2017 by U.S. Department of the Interior SecretaryRyan Zinke that directed the BOEM and the BSEE to reconsider a number of regulatory initiatives governing oil and naturalgas exploration, development and production activities on the OCS (“Order 3350”), the BSEE and the BOEM have beendirected to reconsider a number of regulatory initiatives governing offshore oil and gas safety and performance-relatedactivities, including, for example, NTL #2016-N01 and the rules relating to blow-out preventers and well control, andprovide recommendations on whether such regulatory initiatives should continue to be implemented. Moreover, Order 3350directed the BOEM to immediately cease all activities to promulgate the April 2016 proposed rule relating to offshore airquality control. One consequence of this review is that on December 29, 2017, the BSEE published proposed revisions to itsregulations regarding offshore drilling safety equipment, which proposal includes the removal of the requirement for offshoreoperators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g.,subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extremeconditions. The December 2017 proposed rule has not been finalized, and there remains substantial uncertainty as to thescope and extent of any revisions to existing oil and gas safety and performance-related regulations and other regulatoryinitiatives that ultimately will be adopted by the BSEE and the BOEM pursuant to those agencies’ review process.See “Item 1A. Risk Factors” for further discussion on hydraulic fracturing; ozone standards; climate change,including methane or other greenhouse gas emissions; releases of regulated substances; and other aspects of compliance withlegal or financial assurance requirements or relating to environmental protection, including with respect to offshore leases.Other Laws and RegulationsVarious laws and regulations often require permits for drilling wells and also cover spacing of wells, the preventionof waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. Theeffect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which theCompany has production, could be to limit the number of wells that could be drilled on the Company’s properties and tolimit the allowable production from the successful wells completed on the Company’s properties, thereby limiting theCompany’s revenues.Whereas the BLM administers oil and natural gas leases held by the Company on federal onshore lands, the BOEMadministers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the OCS. TheOffice of Natural Resources Revenue (the “ONRR”) collects a royalty interest in these federal leases on behalf of the federalgovernment. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time theONRR changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affectthe actual royalty obligation that the Company is required to pay. However, the Company believes that the regulationsgenerally do not impact the Company to any greater extent than other similarly situated producers.To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells, decommissionor remove platforms and pipelines, and clear the seafloor of obstructions at the end of production (collectively,“decommissioning obligations”), the BOEM generally requires that lessees post supplemental bonds or other acceptablefinancial assurances that such obligations will be met. Historically, our financial assurance costs to satisfy decommissioningobligations have not had a material adverse effect on our results of operations; however, the BOEM continues to considerimposing more stringent financial assurance requirements on offshore operators on the OCS. For example, the BOEM issuedNTL #2016-N01 that went into effect in September 2016 and augments requirements for the posting of additional financialassurance by offshore lessees, among others, to assure that sufficient funds are available to satisfy decommissioningobligations on the OCS. If the BOEM determines under this new NTL that a company does not satisfy the minimumrequirements to qualify for providing self-insurance to meet its decommissioning and other obligations, that company will berequired to post additional financial security as assurance. While we do not meet the requirements for self-insurance, weestimated the impact of the requirement to provide additional security under NTL #2016-N01 for our operations in the Gulfof Mexico and do not believe that the revised policy will have a material impact on our operations in the Gulf of Mexico.During 2017, however, with the issuance of Order 3350, the BSEE and the BOEM have been directed to reconsider anumber of regulatory initiatives governing offshore oil and gas safety and performance-related activities, including, forexample, NTL #2016-N01. Consequently, during 2017, the BOEM extended the start date for implementing NTL #2016-N01indefinitely beyond June 30, 2017. This extension currently remains in effect; however,15 Table of Contentsthe BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is asubstantial risk of nonperformance of the interest holder’s decommissioning sole liabilities. Following completion of itsreview, the BOEM may elect to retain NTL #2016-N01 in its current form or may make revisions thereto and, thus, until thereview is completed and the BOEM determines what additional financial assurance may be required by us, we cannot provideassurance that such financial assurance coverage can be obtained. Moreover, the BOEM could in the future make otherdemands for additional financial assurances covering our obligations under sole liability properties and/or non-sole liabilityproperties. In the event that we are unable to obtain the additional required bonds or assurances as requested, the BOEM mayrequire certain of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties.Risk and Insurance Program In accordance with industry practice, we maintain insurance against many, but not all, potential perils confrontingour operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile,our insurance program is structured to provide us financial protection from significant losses resulting from damages to, orthe loss of, physical assets or loss of human life, and liability claims of third parties, including such occurrences as wellblowouts and weather events that result in oil spills and damage to our wells and/or platforms. Our goal is to balance the costof insurance with our assessment of the potential risk of an adverse event. We maintain insurance at levels that we believe areappropriate and consistent with industry practice, and we regularly review our risks of loss and the cost and availability ofinsurance and revise our insurance program accordingly.We continuously monitor regulatory changes and regulatory responses and their impact on the insurance market andour overall risk profile, and adjust our risk and insurance program to provide protection at a level that we can affordconsidering the cost of insurance, against the potential and magnitude of disruption to our operations and cash flows.Changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico could lead to tighterunderwriting standards, limitations on scope and amount of coverage, and higher premiums, including possible increases inliability caps for claims of damages from oil spills.Health, Safety and Environmental ProgramOur Health, Safety and Environmental (“HS&E”) Program is supervised by an operating committee of seniormanagement to ensure compliance with all state and federal regulations. In support of the operating committee, we havecontracted with J. Connor Consulting (“JCC”) to coordinate the regulatory process relative to our offshore assets. JCC is aregulatory consulting firm specializing in the offshore Gulf of Mexico. They provide preparation of incident response plans,safety and environmental services and facilitation of comprehensive oil spill response training and drills on behalf of oil andgas companies and pipeline operators.Additionally, in support of our Gulf of Mexico operations, we have established a Regional Oil Spill Response Planwhich has been approved by the BSEE. Our response team is trained annually and is tested through in-house spill drills. Wehave also contracted with O’Brien’s Response Management (“O’Brien’s”), who maintains an incident command center on 24hour alert in Houston, TX. In the event of an oil spill, the Company’s response program is initiated by notifying O’Brien’s ofany reportable incident. While the Company response team is mobilized to focus on source control and containment of thespill, O’Brien’s coordinates communications with state and federal agencies and provides subject matter expertise in supportof the response team.We also have contracted with Clean Gulf Associates (“CGA”) to assist with equipment and personnel needs in theevent of a spill. CGA specializes in onsite control and cleanup and is on 24-hour alert with equipment currently stored ateight bases along the gulf coast, from South Texas to East Louisiana. The CGA equipment stockpile is available to servemember oil spill response needs and includes open seas skimmers, shoreline protection boom, communications equipment,dispersants with application systems, wildlife rehabilitation and a forward command center. CGA has retainers with aerialdispersant and mechanical recovery equipment contractors for spill response.In addition to our membership in CGA, the Company has contracted with Wild Well Control for source control atthe wellhead, if required. Wild Well Control is one of the world’s leading providers of firefighting and well control services.We also have a full time health, safety and environmental professional who supports our operations and oversees theimplementation of our onshore HS&E policies.16 Table of ContentsSafety and Environmental Management SystemWe have developed and implemented a Safety and Environmental Management System (“SEMS”) to address oil andgas operations in the OCS, as required by the BSEE. Our SEMS identifies and mitigates safety and environmental hazardsand the impacts of these hazards on design, construction, start-up, operation, inspection, and maintenance of all new andexisting facilities. The Company has established goals, performance measures, training and accountability for SEMSimplementation. We also provide the necessary resources to maintain an effective SEMS, and we review the adequacy andeffectiveness of the SEMS program annually. Company facilities are designed, constructed, maintained, monitored, andoperated in a manner compatible with industry codes, consensus standards, and all applicable governmental regulations. Wehave contracted with Island Technologies Inc. to coordinate our SEMS program and to track compliance for productionoperations.The BSEE enforces the SEMS requirements through regular audits. Failure of an audit may result in an Incident ofNon-Compliance and could ultimately require a shut-in our Gulf of Mexico operations if not resolved within the requiredtime.EmployeesOn December 31, 2017, we had 63 full time employees, of which 20 were field personnel. We have been able toattract and retain a talented team of industry professionals that have been successful in achieving significant growth andsuccess in the past. As such, we are well-positioned to adequately manage and develop our existing assets and also toincrease our proved reserves and production through exploitation of our existing asset base, as well as the continuingidentification, acquisition, and development of new growth opportunities. None of our employees are covered by collectivebargaining agreements. We believe our relationship with our employees is good.In addition to our employees, we use the services of independent consultants and contractors to perform variousprofessional services. As a working interest owner, we rely on certain outside operators to drill, produce and market ournatural gas and oil where we are a non-operator. In prospects where we are the operator, we rely on drilling contractors to drilland sometimes rely on independent contractors to produce and market our natural gas and oil. In addition, we frequentlyutilize the services of independent contractors to perform field and on-site drilling and production operation services andindependent third party engineering firms to evaluate our reserves.Corporate OfficesOur corporate offices are located at 717 Texas Avenue in downtown Houston, Texas, under a lease that expiresMarch 31, 2019. Rent, including parking, related to this office space for the year ended December 31, 2017 wasapproximately $2.2 million. As of January 2017, a portion of our space in the building is being subleased through the leaseexpiration date for $0.5 million annually.Code of EthicsIn January 2014, our board of directors adopted our current Code of Business Conduct and Ethics ("Code ofConduct") which applies to all directors, officers and employees of the Company. Our Code of Conduct is available on theCompany's website at www.contango.com. Any shareholder who so requests may obtain a copy of the Code of Conduct bysubmitting a request to the Company's corporate secretary at the address on the cover of this Form 10-K. Changes in andwaivers to the Code of Conduct for the Company's directors, chief executive officer and certain senior financial officers willbe posted on the Company's website within five business days and maintained for at least 12 months. Information on ourwebsite or any other website is not incorporated by reference into, and does not constitute a part of, this Report on Form 10-K.Available InformationYou may read and copy all or any portion of this report on Form 10-K, our quarterly reports on Form 10-Q andcurrent reports on Form 8-K, as well as any amendments and exhibits to those reports, without charge at the office of theSecurities and Exchange Commission (the “SEC”) in Public Reference Room, 100 F Street NE, Washington, DC, 20549.Information regarding the operation of the public reference rooms may be obtained by calling the SEC at 1-800-SEC-0330.In addition, filings made with the SEC electronically are publicly available through the SEC's website at http://www.sec.gov,and we make these documents available free of charge at our website at http://www.contango.com17 Table of Contentsas soon as reasonably practicable after they are filed or furnished with the SEC. This report on Form 10-K, including allexhibits and amendments, has been filed electronically with the SEC.Seasonal Nature of BusinessThe demand for oil and natural gas fluctuates depending on the time of year. Seasonal anomalies such as mildwinters or cooler summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies,and industrial end users utilize oil and natural gas storage facilities and purchase some of their anticipated winterrequirements during the summer, which can also lessen seasonal demand. Item 1A. Risk Factors In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider thefollowing factors when evaluating the Company. An investment in the Company is subject to risks inherent in our business.The trading price of the shares of the Company is affected by the performance of our business relative to, among otherthings, competition, market conditions and general economic and industry conditions. The value of an investment in theCompany may decrease, resulting in a loss.RISK FACTORS RELATING TO OUR BUSINESSWe have no ability to control the market price for natural gas and oil. Natural gas and oil prices fluctuate widely, and acontinued substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitabilityand growth and could have a material adverse effect on the business, the results of operations and financial condition ofthe Company.Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Natural gasand crude oil prices remained relatively low through 2017. While natural gas prices have remained consistent with 2017levels, crude oil prices increased slightly during the final months of 2017 and throughout early 2018. The markets for thesecommodities are volatile and prices received affect the amount of future cash flow available for capital expenditures andrepayment of indebtedness and our ability to raise additional capital. Lower prices also affect the amount of natural gas andoil that we can economically produce. Factors that can cause price fluctuations include:·Overall economic conditions, domestic and global.·The domestic and foreign supply of natural gas and oil.·The level of consumer product demand.·Adverse weather conditions and natural disasters.·The price and availability of competitive fuels such as LNG, heating oil and coal.·Political conditions in the Middle East and other natural gas and oil producing regions.·The ability of the members of the Organization of Petroleum Exporting Countries and other oil exportingnations to agree to and maintain oil price and production controls.·The level of LNG imports and any LNG exports.·The level of natural gas exports.·Domestic and foreign governmental regulations.·Special taxes on production.·Access to pipelines and gas processing plants.·The loss of tax credits and deductions.18 Table of ContentsA substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access tocapital and the quantities of natural gas and oil that may be economically produced by us. The Company may utilizefinancial derivative contracts, such as swaps, costless collars and puts on commodity prices, to reduce exposure to potentialdeclines in commodity prices, however, these derivative contracts may not be sufficient to mitigate the effect of lowercommodity prices.Part of our strategy involves drilling in new or emerging plays; therefore, our drilling results in these areas are notcertain.The results of our drilling in new or emerging plays are more uncertain than drilling results in areas that are moredeveloped and with longer production history. Since new or emerging plays and new formations have limited productionhistory, we are less able to use past drilling results in those areas to help predict our future drilling results. The ultimatesuccess of these drilling and completion strategies and techniques in these formations will be better evaluated over time asmore wells are drilled and production profiles are better established. Accordingly, our drilling results are subject to greaterrisks in these areas and could be unsuccessful. We may be unable to execute our expected drilling program in these areasbecause of disappointing drilling results, capital constraints, lease expirations, access to adequate gathering systems orpipeline take-away capacity, availability of drilling rigs and other services or otherwise, and/or crude oil, natural gas andnatural gas liquids price declines. To the extent we are unable to execute our expected drilling program in these areas, ourreturn on investment may not be as attractive as we anticipate and our common stock price may decrease. We could incurmaterial write-downs of unevaluated properties, and the value of our undeveloped acreage could decline in the future if ourdrilling results are unsuccessful.Initial production rates in shale plays tend to decline steeply in the first twelve months of production and arenot necessarily indicative of sustained production rates.Our future cash flows are subject to a number of variables, including the level of production from existingwells. Initial production rates in shale plays tend to decline steeply in the first twelve months of production and are notnecessarily indicative of sustained production rates. As a result, we generally must locate and develop or acquire new crudeoil or natural gas reserves to offset declines in these initial production rates. If we are unable to do so, these declines in initialproduction rates may result in a decrease in our overall production and revenue over time.Our development and exploration operations require substantial capital, and we may be unable to obtain neededcapital or financing on satisfactory terms, which could lead to a loss of undeveloped acreage and/or a decline in ourcrude oil, natural gas and natural gas liquids reserves.The oil and gas industry is capital intensive. We make and expect to continue to make substantial capitalexpenditures in our business and operations for the exploration, development, production and acquisition of crude oil,natural gas and natural gas liquids reserves. We intend to finance our future capital expenditures primarily with cash flowfrom operations, borrowings under our senior secured revolving credit agreement and/or proceeds from non-core asset sales.Our cash flow from operations and access to capital is subject to a number of variables, including:·Our proved reserves.·The level of crude oil, natural gas and natural gas liquids we are able to produce from existing wells.·The prices at which crude oil, natural gas and natural gas liquids are sold.·Our ability to acquire, locate and produce new reserves.If our revenues decrease as a result of lower crude oil, natural gas and natural gas liquids prices, operatingdifficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustainour operations at current levels, to further develop and exploit our current properties, or to conduct exploratory activity. Inorder to fund our capital expenditures, we may need to seek additional financing. Our credit agreements contain covenantsrestricting our ability to incur additional indebtedness without the consent of the lenders. Our lenders may withhold thisconsent in their sole discretion. In addition, if our borrowing base redetermination results in a lower borrowing base underour senior secured revolving credit agreement, we may be unable to obtain financing otherwise currently available under oursenior secured revolving credit agreement. As part of the regular redetermination schedule, the borrowing base on ourrevolving credit agreement was redetermined at $115 million effective November 9, 2017 and19 Table of Contentsthrough May 01, 2018. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results ofOperations - Capital Resources and Liquidity.”In addition, our ability to comply with the financial and other restrictive covenants in our indebtedness is uncertainand will be affected by our future performance and events or circumstances beyond our control. For example, at December 31,2017, we were not in compliance with the Current Ratio covenant under our credit agreement, although we obtained a waiver for such non-compliance. Any future failure to comply with these covenants could result in an event of default undersuch indebtedness and the potential foreclosure on the collateral securing such debt, and could cause a cross-default underany of our other outstanding indebtedness. Furthermore, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. In particular,the cost of raising money in the debt and equity capital markets has increased substantially while the availability of fundsfrom those markets generally has diminished significantly. Also, as a result of concerns about the stability of financialmarkets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit marketsgenerally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lendingstandards, refused to refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in somecases ceased, to provide funding to borrowers. The failure to obtain additional financing could result in a curtailment of ouroperations relating to exploration and development of our prospects, which in turn could lead to a possible loss of propertiesand a decline in our crude oil, natural gas and natural gas liquids reserves.We rely on third-party contract operators to drill, complete and manage some of our wells, production platforms,pipelines and processing facilities and, as a result, we have limited control over the daily operations of such equipmentand facilities.We depend upon the services of third-party operators to operate drilling rigs, completion operations, offshoreproduction platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our naturalgas, condensate and oil. We have limited influence over the conduct of operations by third-party operators. As a result, wehave little control over how frequently and how long our operations are down or our production is shut-in when problems,weather and other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, theoperator of a project in which we participate may have an adverse effect on our results of operations and financial condition.Failure of our working interest partners to fund their share of development costs could result in the delay or cancellationof future projects, which could have a materially adverse effect on our financial condition and results of operations.Natural gas and crude oil prices remained relatively low through most of 2017, and while natural gas prices haveremained consistent with 2017 levels, crude oil prices increased slightly during the final months of 2017 and throughoutearly 2018. An extended or more severe downturn could have material adverse effects on the liquidity of our working interestpartners. Our working interest partners must be able to fund their share of investment costs through cash flow fromoperations, external credit facilities, or other sources. If our partners are not able to fund their share of costs, it could result inthe delay or cancellation of future projects, resulting in a reduction of our reserves and production, which could have amaterially adverse effect on our financial condition and results of operations.We are exposed to the credit risks of our customers and derivative counterparties, and any material nonpayment ornonperformance by our customers or derivative counterparties could have a materially adverse effect on our financialcondition and results of operations.We are subject to risks of loss resulting from nonpayment or nonperformance by our customers, which risks mayincrease during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject totheir own operating and regulatory risks, which increases the risk that they may default on their obligations to us. To theextent one or more of our significant customers is in financial distress or commences bankruptcy proceedings, contracts withthese customers may be subject to renegotiation or rejection under applicable provisions of the United States BankruptcyCode. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligationunder the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk managementpolicies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or ourderivative counterparties could have a materially adverse effect on our financial condition and results of operations.20 Table of ContentsRepeated offshore production shut-ins can possibly damage our well bores.Our offshore well bores are required to be shut-in from time to time due to a variety of issues, including acombination of weather, mechanical problems, sand production, bottom sediment, water and paraffin associated with ourcondensate production, as well as downstream third-party facility and pipeline shut-ins. In addition, shut-ins are necessaryfrom time to time to upgrade and improve the production handling capacity at related downstream platform, gas processingand pipeline infrastructure. In addition to negatively impacting our near term revenues and cash flow, repeated productionshut-ins may damage our well bores if repeated excessively or not executed properly. The loss of a well bore due to damagecould require us to drill additional wells.Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect ourproduction and cash flows.Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail toreplace reserves, our level of production and cash flows will be adversely impacted. Production from natural gas and oilproperties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total provedreserves will decline as reserves are produced unless we conduct other successful exploration and development activities oracquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing.Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Ourability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would beimpaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our futureproduction and revenues will be adversely affected.Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in thesereserve estimates or underlying assumptions could materially affect the quantities of our reserves.There are numerous uncertainties in estimating crude oil and natural gas reserves and their value, including manyfactors that are beyond our control. It requires interpretations of available technical data and various assumptions, includingassumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions couldmaterially affect the estimated quantities of reserves shown in this report.In order to prepare these estimates, our independent third-party petroleum engineers must project production ratesand timing of development expenditures as well as analyze available geological, geophysical, production and engineeringdata, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating tomatters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability offunds.Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expensesand quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variancecould materially affect the estimated quantities and pre-tax net present value of reserves shown in a reserve report. Inaddition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration anddevelopment, prevailing natural gas and oil prices and other factors, many of which are beyond our control and may prove tobe incorrect over time. As a result, our estimates may require substantial upward or downward revisions if subsequent drilling,testing and production reveal different results. Furthermore, some of the producing wells included in our reserve report haveproduced for a relatively short period of time. Accordingly, some of our reserve estimates are not based on a multi-yearproduction decline curve and are calculated using a reservoir simulation model together with volumetric analysis. Anydownward adjustment could indicate lower future production and thus adversely affect our financial condition, futureprospects and market value.Approximately 35% of our total estimated proved reserves at December 31, 2017 were proved undeveloped reserves.The development of our estimated proved undeveloped reserves may take longer and may require higher levels ofcapital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not beultimately developed or produced.Recovery of proved undeveloped reserves requires significant capital expenditures and successful drillingoperations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures arerequired to develop such reserves. Although cost and reserve estimates attributable to our crude oil, natural gas and naturalgas liquids reserves have been prepared in accordance with industry standards, we cannot be sure that the21 Table of Contentsestimated costs are accurate, that development will occur as scheduled or that the results of such development will be asestimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases incommodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenuesestimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development ofreserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.The present value of future net cash flows from our proved reserves will not necessarily be the same as the currentmarket value of our estimated crude oil, natural gas and natural gas liquids reserves.You should not assume that the present value of future net revenues from our proved reserves referred to in thisreport is the current market value of our estimated crude oil, natural gas and natural gas liquids reserves. In accordance withthe requirements of the SEC, the estimated discounted future net cash flows from our proved reserves are based on prices andcosts on the date of the estimate, held flat for the life of the properties. Actual future prices and costs may differ materiallyfrom those used in the present value estimate. The present value of future net revenues from our proved reserves as ofDecember 31, 2017 was based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for theperiod January through December 2017. For our condensate and natural gas liquids, the average West Texas Intermediate(Cushing) posted price was $51.34 per barrel for offshore and onshore Southern Delaware Basin volumes, as prepared byCobb, and the average West Texas Intermediate (Plains) posted price was $47.79 per barrel for all other onshore volumes, asprepared by NSAI. For our natural gas, the average Henry Hub spot price was $2.98 per MMBtu for all offshore and onshorevolumes, as prepared by both Cobb and NSAI. Assuming strip pricing as of March 1, 2018 through 2022 and keeping pricingflat thereafter, instead of 2017 SEC pricing, while leaving all other parameters unchanged, the Company’s proved reserveswould have been 188.6 Bcfe and the PV-10 value of proved reserves would have been $258.3 million. Any adjustments tothe estimates of proved reserves or decreases in the price of crude oil or natural gas may decrease the value of our commonstock. A reconciliation of our Standardized Measure to PV‑10 is provided under "Item 2. Properties – PV-10".Actual future net cash flows will also be affected by increases or decreases in consumption by oil and gas purchasersand changes in governmental regulations or taxation. The timing of both the production and the incurrence of expenses inconnection with the development and production of oil and gas properties affects the timing of actual future net cash flowsfrom proved reserves. The effective interest rate at various times and the risks associated with our business or the oil and gasindustry in general will affect the accuracy of the 10% discount factor.Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of crude oil,natural gas and natural gas liquids. In addition, the use of such technology requires greater predrilling expenditures,which could adversely affect the results of our drilling operations.Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtainedthrough geophysical and geological analyses, production data and engineering studies, the results of which are uncertain.For example, we have over 4,000 square miles of 3D data in the South Texas and Gulf Coast regions. However, even whenused and properly interpreted, 3D seismic data and visualization techniques only assist geoscientists and geologists inidentifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know if hydrocarbons arepresent or producible economically. Other geologists and petroleum professionals, when studying the same seismic data, mayhave significantly different interpretations than our professionals.In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures thantraditional drilling strategies, and we could incur losses due to such expenditures. As a result, our drilling activities may notbe geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in aparticular area may not improve.Drilling for and producing crude oil, natural gas and natural gas liquids are high risk activities with many uncertaintiesthat could adversely affect our business, financial condition or results of operations.Our drilling and operating activities are subject to many risks, including the risk that we will not discovercommercially productive reservoirs. Drilling for crude oil, natural gas and natural gas liquids can be unprofitable, not onlyfrom dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drillingand producing operations may be curtailed, delayed or canceled as a result of other factors, including:·unusual or unexpected geological formations and miscalculations;22 Table of Contents·pressures;·fires;·explosions and blowouts;·pipe or cement failures;·environmental hazards, such as natural gas leaks, oil and produced water spills, pipeline and tank ruptures,encountering naturally occurring radioactive materials, and unauthorized discharges of toxic gases, brine, wellstimulation and completion fluids, or other pollutants into the surface and subsurface environment;·loss of drilling fluid circulation;·title problems;·facility or equipment malfunctions;·unexpected operational events;·shortages of skilled personnel;·shortages or delivery delays of equipment and services or of water used in hydraulic fracturing activities;·compliance with environmental and other regulatory requirements;·stockholder activism and activities by non-governmental organizations to limit certain sources of funding forthe energy sector or restrict the exploration, development and production of oil and natural gas so as tominimize emissions of GHGs;·natural disasters; and·adverse weather conditions.Any of these risks can cause substantial losses, including personal injury or loss of life; severe damage to ordestruction of property, natural resources and equipment, pollution, environmental contamination, clean-up responsibilities,loss of wells, repairs to resume operations; and regulatory fines or penalties.Insurance against all operational risks is not available to us. Additionally, we may elect not to obtain insurance if webelieve that the cost of available insurance is excessive relative to the perceived risks presented. We carry limitedenvironmental insurance, thus, losses could occur for uninsurable or uninsured risks or in amounts in excess of existinginsurance coverage. The occurrence of an event that is not covered in full or in part by insurance could have a materialadverse impact on our business activities, financial condition and results of operations.The potential lack of availability of, or cost of, drilling rigs, equipment, supplies, personnel and crude oil field servicescould adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.When the prices of crude oil, natural gas and natural gas liquids increase, or the demand for equipment and servicesis greater than the supply in certain areas, such as the Southern Delaware Basin, we typically encounter an increase in the costof securing drilling rigs, equipment and supplies. In addition, larger producers may be more likely to secure access to suchequipment by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only athigher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reservescould increase significantly, which would adversely affect our results of operations and financial condition.23 Table of ContentsThe natural gas and oil business involves many operating risks that can cause substantial losses and our insurancecoverage may not be sufficient to cover some liabilities or losses that we may incur.The natural gas and oil business involves a variety of operating risks, including:·Blowouts, fires and explosions.·Surface cratering.·Uncontrollable flows of underground natural gas, oil or formation water.·Natural disasters.·Pipe and cement failures.·Casing collapses.·Stuck drilling and service tools.·Reservoir compaction.·Abnormal pressure formations.·Environmental hazards such as natural gas leaks, oil and produced water spills, pipeline and tank ruptures orunauthorized discharges of brine, toxic gases, well stimulation and completion fluids, or other pollutants intothe surface and subsurface environment.·Capacity constraints, equipment malfunctions and other problems at third-party operated platforms, pipelinesand gas processing plants over which we have no control.·Repeated shut-ins of our well bores could significantly damage our well bores.·Required workovers of existing wells that may not be successful.If any of the above events occur, we could incur substantial losses as a result of:·Injury or loss of life.·Reservoir damage.·Severe damage to and destruction of property or equipment.·Pollution and other environmental and natural resources damage.·Restoration, decommissioning or clean-up responsibilities.·Regulatory investigations and penalties.·Suspension of our operations or repairs necessary to resume operations.Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizingand collisions. In addition, offshore operations, and in some instances operations along the Gulf Coast, are subject to damageor loss from hurricanes or other adverse weather conditions. For example, our total production for the year ended December31, 2017 declined by 0.4 Mmcfe/d as a result of downtime associated with the impact of Hurricane Harvey. These conditionscan cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities thatcould reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.If we were to experience any of these problems, it could affect well bores, platforms, gathering systems andprocessing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with24 Table of Contentscustomary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur foruninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintainadequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. Anevent that is not fully covered by insurance could have a material adverse effect on our financial position and results ofoperations.Our hedging activities could result in financial losses or reduce our income.To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of crudeoil, natural gas and natural gas liquids, as well as interest rates, we have, and may in the future, enter into derivativearrangements for a portion of our crude oil, natural gas and/or natural gas liquids production and our debt that could result inboth realized and unrealized hedging losses. We typically utilize financial instruments to hedge commodity price exposureto declining prices on our crude oil, natural gas and natural gas liquids production. We typically use a combination of puts,swaps and costless collars.Our production may be significantly higher or lower than we estimate at the time we enter into hedging transactionsfor such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than weintended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, wemight be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale orpurchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of thesefactors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certaincircumstances may actually increase the volatility of our cash flows.The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments toreduce the effect of commodity price, interest rate, and other risks associated with our business.The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) enacted in 2010, establishedfederal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in thatmarket. The Dodd-Frank Act requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgaterules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remainto be finalized or implemented and it is not possible at this time to predict when this will be accomplished.In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in themajor energy markets and for swaps that are their economic equivalents. The initial position-limits rule was vacated by theU.S. District Court for the District of Columbia in September 2012. In November 2013, the CFTC proposed new rules thatwould place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physicalcommodities, subject to exceptions for certain bona fide hedging transactions, but the rule was not adopted. In December2016, the CFTC proposed a new version of the rule, with respect to which the comment period has closed but a final rule hasnot been issued. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at thistime. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and theassociated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. In addition the CFTC and certainbanking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps.Although we currently qualify for the end-user exception to the mandatory clearing, trade-execution and marginrequirements for swaps entered to hedge our commercial risks, the application of such requirements to other marketparticipants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, ifany of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity andreduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk andprotect cash flows.The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be knownuntil the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act andregulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts,reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure ourexisting derivative contracts or increase our exposure to less creditworthy counterparties. If we reduce25 Table of Contentsour use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatileand our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.Increased volatility may make us less attractive to certain types of investors.Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which somelegislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Ourrevenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodityprices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results ofoperations.If prices remain at current levels or decline further, we will likely incur further impairment of proved properties.If management’s estimates of the recoverable proved reserves on a property are revised downward or if oil and/ornatural gas prices decline further in 2018, we may be required to record further non-cash impairment write-downs in thefuture, which would result in a negative impact to our financial results. Furthermore, any sustained decline in oil and/ornatural gas prices may require us to make further impairments. We review our proved oil and gas properties for impairment ona depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit isimpaired, we compare the carrying value of the depletable unit to the undiscounted future net cash flows by applyingmanagement’s estimates of future oil and natural gas prices to the estimated future production of oil and gas reserves over theeconomic life of the property. Future net cash flows are based upon our independent reservoir engineers’ estimates of provedreserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified byeconomic conditions. For each property determined to be impaired, we recognize an impairment loss equal to the differencebetween the estimated fair value and the carrying value of the property on a depletable unit basis.Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred isrecorded in accumulated depreciation, depletion, and amortization to reduce our recorded cost basis in the asset. Each part ofthis calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimatedreserves, future cash flows and fair value.Management’s assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair valueof our properties are subject to change in the future. Any change could cause impairment expense to be recorded, impactingour net income or loss and our basis in the related asset. Any change in reserves directly impacts our estimate of future cashflows from the property, as well as the property’s fair value. Additionally, as management’s views related to future priceschange, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of theseamounts will directly impact the calculation of impairment.Production activities in the Gulf of Mexico increase our susceptibility to pollution and natural resource damage.A blowout, rupture or spill of any magnitude would present serious operational and financial challenges. All of theCompany’s operations in the Gulf of Mexico shelf are in water depths of less than 300 feet and less than 50 miles from thecoast. Such proximity to the shore-line increases the probability of a biological impact or damaging the fragile eco-system inthe event of released condensate.Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operatingcosts and reduced demand for the oil and natural gas that we produce.Climate change continues to attract considerable public, governmental and scientific attention. As a result,numerous proposals have been made and may continue to be made at the international, national, regional and state levels ofgovernment to monitor and limit emissions of GHGs. While no comprehensive climate change legislation has beenimplemented to date at the federal level, the EPA and states and groupings of states have considered or pursued cap-and-tradeprograms, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certainsources. In particular, the EPA adopted regulations under existing provisions of the CAA that, among other things, establishPrevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions fromcertain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions.Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available controltechnology” standards that typically will be established by the states. In addition, the EPA has adopted rules requiring themonitoring and annual reporting of GHG emissions from specified sources in the United States, including, among others,certain oil and natural gas production facilities, which includes certain of our operations.26 Table of ContentsFederal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gasoperations. In June 2016, the EPA published a final rule establishing New Source Performance Standards (“NSPS”) SubpartOOOOa standards that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reducethese methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previouslyissued NSPS Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control practices.However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two yearsand re-evaluate the entirety of the 2016 standards, but the EPA has not yet published a final rule and, as a result, the June2016 rule remains in effect. Future implementation of the 2016 standards is uncertain at this time. In another example, theBLM published a final rule in November 2016 that imposes requirements to reduce methane emissions from venting, flaring,and leaking on federal and Indian lands. However, in December 2017, the BLM published a final rule that temporarilysuspends or delays certain requirements contained in the November 2016 final rule until January 17, 2019. The suspension ofthe November 2016 final rule is being challenged in court. These rules, should they remain in effect, and any other newmethane emission standards imposed on the oil and gas sector could result in increased costs to our or our customers’operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adverselyaffect our business. Moreover, in December 2015, the United States joined other countries of the United Nations in preparingan agreement requiring member countries to review and establish goals for limiting GHG emissions. This “Paris Agreement”was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does notcreate any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit orreduce future emissions. However, in August 2017, the U.S. State Department informed the United Nations of the intent of theUnited States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginningwhen it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separatelynegotiated agreement are unclear at this time. Although it is not possible at this time to predict how legislation or newregulations that may be adopted to address GHG emissions would impact our business, any such future international, federalor state laws or regulations that impose reporting obligations on us with respect to, or require the elimination of GHGemissions from, our equipment or operations could require us to incur increased operating costs and could adversely affectdemand for the oil and natural gas we produce. Moreover, such new legislation or regulatory programs could also increasethe cost to the consumer, which could reduce the demand for the oil and natural gas we produce and lower the value of ourreserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources offunding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources ofcapital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it moredifficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related toclimate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peakuntil after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over thattime. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’satmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity ofstorms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect onour financial condition and results of operations. At this time, we have not developed a comprehensive plan to address thelegal, economic, social or physical impacts of climate change on our operations.Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, or the FTC,we could be subject to substantial penalties and fines.Section 1(b) of the NGA exempts natural gas gathering facilities from the FERC’s jurisdiction. We believe that thegas gathering facilities we own meet the traditional tests the FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities.Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is thesubject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subjectto change based on future determinations by the FERC and the courts. Our failure to comply with this or other laws andregulations administered by the FERC could subject us to substantial penalties, as described in Part I, Item 1: “Business—Governmental Regulations and Industry Matters.”Under the 2005 Act and implementing regulations, the FERC prohibits market manipulation in connection with thepurchase or sale of natural gas. The CFTC has similar authority under the Commodity Exchange Act and regulations27 Table of Contentsit has promulgated thereunder with respect to certain segments of the physical and futures energy commodities marketincluding oil and natural gas. The FTC also prohibits manipulative or fraudulent conduct in the wholesale petroleum marketwith respect to sales of commodities, including crude oil, condensate and natural gas liquids. These agencies havesubstantial enforcement authority, including the potential ability to impose maximum penalties for violations in excess of $1million per day for each violation. Following their adoption, the maximum penalties prescribed by these regulations havebeen subject to annual adjustment for inflation. The FERC has also imposed requirements related to reporting of natural gassales volumes that may impact the formation of prices indices. Additional rules and legislation pertaining to these and othermatters may be considered or adopted from time to time. Our failure to comply with these or other laws and regulationsadministered by these agencies could subject us to substantial penalties, as described in Part I, Item 1: “Business—Governmental Regulations and Industry Matters.”Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions onthe platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.All of our natural gas and oil is transported through gathering systems, pipelines and processing plants.Transportation capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due torepairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippersthat may have priority transportation agreements. If the gathering systems, processing plants, platforms or our transportationcapacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impairedand cash flow from the affected properties could be reduced, which could have a material adverse effect on our financialcondition and results of operations. Further, repeated shut-ins of our wells could result in damage to our well bores thatwould impair our ability to produce from these wells and could result in additional wells being required to produce ourreserves.If our access to sales markets is restricted, it could negatively impact our production, our income and ultimately ourability to retain our leases.Market conditions or the unavailability of satisfactory crude oil, natural gas and natural gas liquids transportationarrangements may hinder our access to crude oil, natural gas and natural gas liquids markets or delay our production. Theavailability of a ready market for our crude oil, natural gas and natural gas liquids production depends on a number offactors, including the demand for and supply of crude oil, natural gas and natural gas liquids and the proximity of reserves topipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability andcapacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtainsuch services on acceptable terms could materially harm our business. Our productive properties may be located in areas withlimited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compressionfacilities. Such restrictions on our ability to sell our crude oil, natural gas and natural gas liquids may have several adverseeffects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower sellingprice) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibleloss of a lease due to lack of production.We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceedwith our exploration and development of the lease site.Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur theexpense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we relyupon the judgment of consultants and others to perform the field work in examining records in the appropriate governmental,county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Priorto the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drill sitelease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to thewell and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible.However, such deficiencies may not have been cured by the operator of such wells. It does happen, from time to time, that theexamination made by title lawyers reveals that the lease or leases are invalid, having been purchased in error from a personwho is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with ourexploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time,that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.28 Table of ContentsCompetition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating historythan many of our competitors.We compete with a broad range of natural gas and oil companies in our exploration and property acquisitionactivities. We also compete for the equipment and labor required to operate and to develop these properties. Many of ourcompetitors have substantially greater financial resources than we do. These competitors may be able to pay more forexploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for andpurchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and toacquire additional properties in the future depends on our ability to evaluate and select suitable properties and toconsummate transactions in this highly competitive environment. In addition, many of our competitors have been operatingfor a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively withthese companies or in such a highly competitive environment.Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration anddevelopment may be eliminated or significantly changed as a result of future legislation. Recently enacted legislation, commonly referred to as the Tax Cuts and Jobs Act, made significant changes to U.S.tax laws. While past legislative proposals have included changes to certain key U.S. federal income tax provisions currentlyavailable to oil and gas companies, including (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, and (iii) an extension of theamortization period for certain geological and geophysical expenditures, these specific changes were not included in the TaxCuts and Jobs Act. No accurate prediction can be made as to whether any such legislative changes will be proposed orenacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be.However, the Tax Cuts and Jobs Act (i) eliminates the deduction for certain domestic production activities, (ii) imposes newlimitations on the utilization of net operating losses, and (iii) provides for more general changes to the taxation ofcorporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact thetaxation of oil and gas companies. Future changes in U.S. federal income tax laws could eliminate or postpone certain taxdeductions that currently are available with respect to oil and gas development, or increase costs, and any such changescould have an adverse effect on our business, financial condition, results of operations and cash flows.We are subject to stringent laws and regulations, including environmental requirements that can adversely affect thecost, manner or feasibility of doing business.Our oil and natural gas exploration, development and production operations are subject to stringent federal,regional, state and local laws and regulations governing the operation and maintenance of our facilities, the discharge ofmaterials into the environment and environmental protection. Failure to comply with such rules and regulations could resultin the assessment of sanctions, including administrative, civil and criminal penalties, investigatory, remedial and correctiveaction obligations, the occurrence of delays or restrictions in permitting or performance of projects and the issuance of orderslimiting or prohibiting some or all of our operations in affected areas. These laws and regulations may:·require that we obtain permits before commencing drilling or other regulated activities;·restrict the substances that can be released into the environment in connection with drilling and productionactivities;·limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas;·require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and·impose substantial penalties for pollution resulting from drilling and production operations.Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmentalnatural resource and property damages. We maintain insurance coverage for sudden and accidental environmental damages;however, it is possible that coverage might not be sufficient in a catastrophic event. Accordingly, we may be subject toliability, or we may be required to cease production from properties in the event of environmental damages. The trend inenvironmental laws and regulations is to place more stringent restrictions and29 Table of Contentslimitations on activities that may affect the environment. For example, in October 2015, the EPA issued a final rule loweringthe National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion for the 8-hour primary andsecondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect toground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” buthad not yet issued non-attainment designations for the remaining areas of the U.S. not addressed in the November 2017 finalrule. States are also expected to implement requirements as a result of this NAAQs final rule, which could result in stricterpermitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures forpollution control equipment, the costs of which could be significant. Compliance with this final rule could, among otherthings, require installation of new emission controls on some of our equipment, result in longer permitting timelines, andsignificantly increase our capital or operating expenditures. In another example, in June 2015, the EPA and the Corpspublished a final rule attempting to clarify the federal jurisdictional reach over waters of the United States includingwetlands, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federaldistrict or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed tohear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intentto issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifyingthat the contested June 2015 rule would not take effect until two years after the November 2017 proposed rule was finalizedand published in the Federal Register. Recently, on January 22, 2018, the U.S. Supreme Court issued a decision finding thatjurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remainsstayed, the previously-filed district court cases will be allowed to proceed. As a result of these recent developments, futureimplementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the CleanWater Act’s jurisdiction, drilling programs could incur increased costs and delays with respect to obtaining permits fordredge and fill activities in wetland areas. Historically, our environmental compliance costs have not had a material adverseeffect on our results of operations; however, we can provide no assurance that our future compliance with existing laws andregulations, these recently adopted rulemakings, or any new or amended legal requirements will not have a material adverseeffect on our business, financial condition and results of operations. An accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.We may incur significant environmental costs liabilities in our business as a result of our handling of petroleumhydrocarbons and wastes, because of air emissions and waste water discharges related to our operations, and due to historicalindustry operations and waste disposal practices. We currently own, operate or lease numerous properties that for many yearshave been used for the exploration and production of crude oil and natural gas. Many of these properties have been operatedby third parties whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. Forexample, an accidental release resulting from the drilling of a well, could subject us to substantial liabilities arising fromenvironmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and otherthird parties for personal injury and property and natural resource damages as well as monetary fines or penalties for relatedviolations of environmental laws or regulations. Moreover, certain environmental statutes impose strict, joint and severalliability for these costs and liabilities without regard to fault or the legality of our conduct. Under these environmental lawsand regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of orreleased by prior owners or operators) or property contamination (including groundwater contamination) or to performremedial plugging or other decommissioning activities to prevent future contamination. We may not be able to recover someor any of these costs from insurance.Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmentalreviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affectour production.Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/orcrude oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand orother proppant and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rockand stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completionprograms. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, or similar state agencies, butseveral federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process. Forexample, in February 2014, the EPA asserted regulatory authority pursuant to the SDWA Underground Injection Controlprogram over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. TheEPA also published final rules under the CAA in 2012 and in June 2016 governing performance standards, includingstandards for the capture of air emissions released during oil and natural gas30 Table of Contentshydraulic fracturing. Additionally, in June 2016, the EPA published an effluent limit guideline final rule prohibiting thedischarge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewatertreatment plants and, in May 2014, published an Advance Notice of Proposed Rulemaking regarding Toxic SubstancesControl Act reporting of the chemical substances and mixtures used in hydraulic fracturing. The BLM published a final rulein March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and AmericanIndian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lackedauthority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals for the Tenth Circuit inJuly 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss thelawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and,in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challengingthe BLM’s rescission of the 2015 rule was brought in federal court. Also, in December 2016, the EPA released its final reporton the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activitiesassociated with hydraulic fracturing may impact drinking water resources under certain circumstances, including as a resultof water withdrawals for fracturing in times or areas of low water availability or due to surface spills during the managementof fracturing fluids, chemicals or produced water. Moreover, from time to time, Congress has considered, but not enacted, legislation intended to provide for federalregulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Inaddition, certain states, including Texas and Wyoming, where we conduct operations, have adopted and other states areconsidering adopting legal requirements that could impose new or more stringent permitting, public disclosure, and wellconstruction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturingaltogether, following the approach of the State of New York in 2015. Local government also may seek to adopt ordinanceswithin their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturingactivities in particular. In the event that new or more stringent federal, state, or local legal restrictions relating to thehydraulic fracturing process are adopted in areas where we currently or in the future plan to operate, we could incurpotentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit ofexploration, development, or production activities, and perhaps even be precluded from drilling wells.We may be subject to additional supplemental bonding under the BOEM financial assurance requirements. Energy companies conducting oil and natural gas lease operations offshore on the OCS are required by the BOEM,among other obligations, to conduct decommissioning within specified times following cessation of offshore producingactivities, which decommissioning includes the plugging of wells, removal of platforms and other facilities, and the clearingof obstacles from the lease site sea floor. To cover a lease operator’s decommissioning obligations, the BOEM generallyrequires that lessees demonstrate financial strength and reliability according to regulations or otherwise post bonds or otheracceptable financial assurances that such future obligations will be satisfied. As an operator, we are required to post suretybonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities as part of our generalbonding requirements, as well as the posting of additional supplemental bonds to cover, among other things, ourdecommissioning obligations. We typically post surety bonds with the BOEM to satisfy our general and supplementalbonding requirements. The BOEM continues to consider the adoption or enforcement of more stringent financial assurance regulatoryinitiatives that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gasexploration and production operations conducted offshore on the federal OCS. In particular, the BOEM issued an updatedNTL #2016-N01 that became effective in September 2016 and bolsters the financial assurance requirements offshore lesseeson the OCS, including the Gulf of Mexico, must satisfy with respect to their decommissioning liabilities. If the BOEMdetermines under NTL #2016-N01 that a company does not satisfy the minimum requirements to qualify for providing self-insurance to meet its decommissioning and other obligations, that company will be required to post additional financialsecurity as assurance. During 2017, however, with the issuance of Order 3350, the BSEE and the BOEM have been directedto reconsider a number of regulatory initiatives governing offshore oil and gas safety and performance-related activities,including, for example, NTL #2016-N01, and provide recommendations on whether such regulatory initiatives shouldcontinue to be implemented. Consequently, during 2017, the BOEM extended the start date for implementing NTL #2016-N01 indefinitely beyond June 30, 2017. This extension currently remains in effect; however, the BOEM reserved the right tore-issue sole liability orders in the future, including in the event that it determines there is a substantial risk ofnonperformance of the interest holder’s decommissioning sole liabilities. Following completion of its review, the BOEMmay elect to retain NTL #2016-N01 in its current form or may make revisions thereto and, thus, until the review is completedand the BOEM determines what additional financial assurance31 Table of Contentsmay be required by us, we cannot provide assurance that such financial assurance coverage can be obtained. Moreover, theBOEM could in the future make other demands for additional financial assurances covering our obligations under soleliability properties and/or non-sole liability properties.If we fail to comply with the current or future orders of the BOEM to provide additional surety bonds or otherfinancial assurances, the BOEM could commence enforcement proceedings or take other remedial action, including assessingcivil penalties, ordering suspension of operations or production, or initiating procedures to cancel leases, which, if upheld,would have a material adverse effect on our business, properties, results of operations and financial condition. Moreover,under existing BOEM rules relating to assignment of offshore leases and other legal interests on the OCS, assignors of suchinterest may be held jointly and severally liable for decommissioning obligations at those OCS facilities existing at the timethe assignment was approved by the BOEM, in the event that the assignee is unable or unwilling to conduct requireddecommissioning. In the event that we, in the role of assignor, receive orders from the BOEM to decommission OCS facilitiesthat one of our assignees of offshore facilities is unwilling or unable to perform, we could incur costs to perform thosedecommissioning obligations, which costs could be material.The BSEE has implemented much more stringent controls and reporting requirements that if not followed, could resultin significant monetary penalties or a shut-in of all or a portion of our Gulf of Mexico operations.The BSEE is the federal agency responsible for overseeing the safe and environmentally responsible development ofenergy and mineral resources on the OCS. The agency is responsible for leading the most aggressive and comprehensivereforms to offshore oil and natural gas regulation and oversight in U.S. history. Their reforms have tightened requirements foreverything from well and blowout preventer design and workplace safety to corporate accountability. However, as a result ofthe issuance of Order 3350 during 2017, the BSEE is reconsidering a number of regulatory initiatives governing offshore oiland gas safety and performance-related activities. For example, on December 29, 2017, the BSEE published proposedrevisions to its regulations regarding offshore drilling safety equipment, which proposal includes the removal of therequirement for offshore operators to certify through an independent third party that their critical safety and pollutionprevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning asdesigned in the most extreme conditions. The December 2017 proposed rule has not been finalized and there remainssubstantial uncertainty as to the scope and extent of any revisions to existing oil and gas safety and performance-relatedregulations and other regulatory initiatives that ultimately will be adopted by the BSEE pursuant to the agency’s reviewprocess.Additionally, the Outer Continental Shelf Lands Act authorizes and requires the BSEE to provide for both an annualscheduled inspection and a periodic unscheduled (unannounced) inspection of all oil and natural gas operations on the OCS.In addition to examining all safety equipment designed to prevent blowouts, fires, spills, or other major accidents, theinspections focus on pollution, drilling operations, completions, workovers, production, and pipeline safety. Upon detectinga violation, the inspector issues an Incident of Noncompliance ("INC") to the operator and uses one of two main enforcementactions (warning or shut-in), depending on the severity of the violation. If the violation is not severe or threatening, awarning INC is issued. The warning INC must be corrected within a reasonable amount of time specified on the INC. Theshut-in INC may be for a single component (a portion of the facility) or the entire facility. The violation must be correctedbefore the operator is allowed to resume the activity in question.In addition to the enforcement actions specified above, the BSEE can assess civil penalties if: (i) the operator fails tocorrect the violation in the reasonable amount of time specified on the INC; or (ii) the violation resulted in a threat of seriousharm or damage to human life or the environment. In January 2018, the BSEE published a final rule that increased themaximum civil penalty rate for Outer Continental Shelf Lands Act violations to $43,576 a day for each violation. Operatorswith excessive INCs may be required to cease operations in the Gulf of Mexico.We are highly dependent on our senior management team, our exploration partners, third-party consultants andengineers, and other key personnel and any failure to retain the services of such parties could adversely affect our abilityto effectively manage our overall operations or successfully execute current or future business strategies.The successful implementation of our business strategy and handling of other issues integral to the fulfillment of ourbusiness strategy is highly dependent on our management team, as well as certain key geoscientists, geologists, engineersand other professionals engaged by us. The loss of key members of our management team or other highly qualified technicalprofessionals could adversely affect our ability to effectively manage our overall operations or successfully execute currentor future business strategies which may have a material adverse effect on our business, financial condition and operatingresults. Our ability to manage our growth, if any, will require us to continue to train,32 Table of Contentsmotivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for thesetypes of personnel is intense and we may not be successful in attracting, assimilating and retaining the personnel required togrow and operate our business profitably.Acquisition prospects are difficult to assess and may pose additional risks to our operations.We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considersfavorable. The successful acquisition of natural gas and oil properties requires an assessment of:·Recoverable reserves.·Exploration potential.·Future natural gas and oil prices.·Operating costs.·Potential environmental and other liabilities and other factors.·Permitting and other authorizations, including environmental permits and authorizations, required for ouroperations.In connection with such an assessment, we would expect to perform a review of the subject properties that webelieve to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact andtheir accuracy inherently uncertain and such an assessment may not reveal all existing or potential problems, nor will itnecessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies.Inspections may not always be performed on every platform or well, and structural and environmental problems are notnecessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to ouroperations and financial results, including:·Problems integrating the purchased operations, personnel or technologies.·Unanticipated costs.·Diversion of resources and management attention from our exploration business.·Entry into regions or markets in which we have limited or no prior experience.·Potential loss of key employees of the acquired organization.We may be unable to successfully integrate the properties and assets we acquire with our existing operations.Integration of the properties and assets we acquire may be a complex, time consuming and costly process. Failure totimely and successfully integrate these assets and properties with our operations may have a material adverse effect on ourbusiness, financial condition and result of operations. The difficulties of integrating these assets and properties presentnumerous risks, including:·Acquisitions may prove unprofitable and fail to generate anticipated cash flows.·We may need to (i) recruit additional personnel and we cannot be certain that any of our recruiting efforts willsucceed and (ii) expand corporate infrastructure to facilitate the integration of our operations with thoseassociated with the acquired properties, and failure to do so may lead to disruptions in our ongoing businessesor distract our management.·Our management’s attention may be diverted from other business concerns.We are also exposed to risks that are commonly associated with acquisitions of this type, such as unanticipatedliabilities and costs, some of which may be material. As a result, the anticipated benefits of acquiring assets and propertiesmay not be fully realized, if at all.33 Table of ContentsWhen we acquire properties, in most cases, we are not entitled to contractual indemnification for pre-closing liabilities,including environmental liabilities.We generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representationsand warranties, and in these situations we cannot assure you that we will identify all areas of existing or potential exposure.In those circumstances in which we have contractual indemnification rights for pre-closing liabilities, we cannot assure youthat the seller will be able to fulfill its contractual obligations. In addition, the competition to acquire producing crude oil,natural gas and natural gas liquids properties is intense and many of our larger competitors have financial and other resourcessubstantially greater than ours. We cannot assure you that we will be able to acquire producing crude oil, natural gas andnatural gas liquids properties that have economically recoverable reserves for acceptable prices. In connection with the Acquisition, we entered into a new area of exploration and development in which we have limitedexperience and facilities, and as a result we may experience inefficiencies, incur unanticipated or higher costs andexpenses, or may not fully realize the benefits anticipated as a result of the Acquisition. We have a limited operating history in West Texas. As a result of the Acquisition, we will need to continue tointegrate the properties and operations relating thereto with our current oil and gas operations, which may increase the risk ofinefficiencies in timing, coordination and staffing, unanticipated higher costs and expenses than we currently have projectedor drilling results below our expectations. As a result, any desired benefits of the Acquisition may not be fully realized, if atall, and our future financial performance and results of operations could be negatively impacted. Increases in interest rates could adversely impact our business, share price and our ability to issue equity or incur debtfor acquisitions, capital expenditures or other purposes. Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings couldbe higher than current levels, causing our financing costs to increase accordingly. Rising interest rates could reduce theamount of cash we generate and materially adversely affect our liquidity. Moreover, the trading price of our common stock issensitive to changes in interest rates and could be materially adversely affected by any increase in interest rates. Assuming an outstanding balance on our credit facility of $85.4 million, an increase of one percentage point in theinterest rates would have resulted in an increase in interest expense during 2017 of $0.9 million. Accordingly, our results ofoperations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates. Cybersecurity breaches and information technology failures could harm our business by increasing our costs andnegatively impacting our operations. We rely extensively on information technology systems, including Internet sites, computer software, data hostingfacilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business.Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a varietyof evolving cybersecurity risks, such as those involving unauthorized access, malicious software, data privacy breaches byemployees or others with authorized access, cyber or phishing-attacks, ransomware and other security issues. Although we have implemented information technology controls and systems that are designed to protectinformation and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminatecybersecurity threats, and the enhanced controls we have installed may be breached. If our information technology systemscease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations which mayinclude drilling, completion, production and corporate functions. A cyber attack involving our information systems andrelated infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways,including but not limited to, the following: ·Unauthorized access to seismic data, reserves information, strategic information, or other sensitive orproprietary information could have a negative impact on our ability to compete for oil and gas resources; 34 Table of Contents·Data corruption, communication interruption, or other operational disruption during drilling activities couldresult in failure to reach the intended target or a drilling incident; ·Data corruption or operational disruptions of production-related infrastructure could result in a loss ofproduction, or accidental discharge; ·A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay orhalt our major development projects; ·A cyber attack on third party gathering, pipeline, or rail transportation systems could delay or prevent us fromtransporting and marketing our production, resulting in a loss of revenues; ·A cyber attack involving commodities exchanges or financial institutions could slow or halt commoditiestrading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a lossof revenues; ·A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stockcould have a significant impact on the natural gas market, resulting in reduced demand for our production,lower natural gas prices, and reduced revenues; ·A cyber attack on a communications network or power grid could cause operational disruption resulting in lossof revenues; ·A deliberate corruption of our financial or operating data could result in events of non-compliance which couldthen lead to regulatory fines or penalties; and ·A cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s or supplier’s dataor confidential information could harm our business by damaging our reputation, subjecting us to potentialfinancial or legal liability, and requiring us to incur significant costs, including costs to repair or restore oursystems and data or to take other remedial steps. All of the above could negatively impact our operational and financial results. Additionally, certain cyber incidents,such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, we may be requiredto expend significant additional resources to continue to modify or enhance our protective measures or to investigate andremediate any information security vulnerabilities. RISK FACTORS RELATED TO AN INVESTMENT IN OUR COMMON STOCKThe price of our common stock may fluctuate significantly, and you could lose all or part of your investment.Volatility in the market price of our common stock may prevent you from being able to sell your common stock ator above the price you paid for your common stock. The market price for our common stock could fluctuate significantly forvarious reasons, including:·our operating and financial performance and prospects;·our quarterly or annual earnings or those of other companies in our industry;·conditions that impact demand for crude oil, natural gas and natural gas liquids, domestically and globally;·future announcements concerning our business;·changes in financial estimates and recommendations by securities analysts;·actions of competitors;·market and industry perception of our success, or lack thereof, in pursuing our growth strategy;·strategic actions by us or our competitors, such as acquisitions or restructurings;35 Table of Contents·changes in government and environmental regulation;·general market, economic and political conditions, domestically and globally;·changes in accounting standards, policies, guidance, interpretations or principles;·sales of common stock by us, our significant stockholders or members of our management team; and·natural disasters, terrorist attacks and acts of war.Average natural gas and crude oil prices declined dramatically beginning in early 2015 and have remainedrelatively low since then. In addition, in recent years, the stock market has experienced significant price and volumefluctuations. This decline in commodity prices and stock market volatility has had a significant impact on the market price ofsecurities issued by many companies, including companies in our industry. The changes frequently appear to occur withoutregard to the operating performance of the affected companies. Hence, the price of our common stock could fluctuate basedupon factors that have little or nothing to do with our company, and these fluctuations could materially reduce our shareprice.We have no plans to pay regular dividends on our common stock, so you may not receive funds without selling yourcommon stock.Our board of directors presently intends to retain all of our earnings for the expansion of our business; therefore, wehave no plans to pay regular dividends on our common stock. Any payment of future dividends will be at the discretion ofour board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, levelof indebtedness, statutory and contractual restrictions applying to the payment of dividends, and other considerations thatour board of directors deems relevant. Also, the provisions of our senior secured revolving credit agreement and second liencredit agreement restrict the payment of dividends. Accordingly, you may have to sell some or all of your common stock inorder to generate cash flow from your investment. We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock. Our board of directors is authorized, without further stockholder action, to issue preferred stock in one or more seriesand to designate the dividend rate, voting rights and other rights, preferences and restrictions of each such series. We areauthorized to issue up to five million shares of preferred stock. The terms of one or more classes or series of preferred stockcould adversely impact the voting power or value of our common stock. For example, we might grant holders of preferredstock the right to elect some number of our directors in all events or on the happening of specified events or the right to vetospecified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders ofpreferred stock could affect the residual value of the common stock.Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price ofshares of our common stock.Future sales or the availability for sale of substantial amounts of our common stock in the public market couldadversely affect the prevailing market price of our common stock and could impair our ability to raise capital through futuresales of equity securities.We may issue shares of our common stock or other securities from time to time as consideration for futureacquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock,or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn besubstantial. We may also grant registration rights covering those shares of our common stock or other securities inconnection with any such acquisitions and investments.As of December 31, 2017, we had 94,833 stock options outstanding to purchase shares of our common stockoutstanding, all of which were fully vested.We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances andsales of our common stock will have on the market price of our common stock. Sales of substantial amounts of our commonstock (including shares of our common stock issued in connection with an acquisition), or the perception that such salescould occur, may adversely affect prevailing market prices for our common stock.36 Table of ContentsOur organizational documents may impede or discourage a takeover, which could deprive our investors of theopportunity to receive a premium for their shares.Provisions of our certificate of incorporation and bylaws may make it more difficult for, or prevent a third partyfrom, acquiring control of us without the approval of our board of directors. These provisions:·permit us to issue, without any further vote or action by the stockholders, shares of preferred stock in one ormore series and, with respect to each such series, to fix the number of shares constituting the series and thedesignation of the series, the voting powers (if any) of the shares of the series, and the preferences and relative,participating, optional, and other special rights, if any, and any qualification, limitations or restrictions of theshares of such series;·require special meetings of the stockholders to be called by the Chairman of the board of directors, the ChiefExecutive Officer, the President, or by resolution of a majority of the board of directors;·require business at special meetings to be limited to the stated purpose or purposes of that meeting;·require that stockholder action be taken at a meeting rather than by written consent, unless approved by ourboard of directors;·require that stockholders follow certain procedures, including advance notice procedures, to bring certainmatters before an annual meeting or to nominate a director for election; and·permit directors to fill vacancies in our board of directors.We are subject to the Delaware business combination law.We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder”for a period of three years after the date of the transaction in which the person became an interested stockholder, unless thebusiness combination is approved in a prescribed manner.Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financialbenefit to the interested stockholders. Section 203 defines an “interested stockholder” as a person who, together withaffiliates and associates, owns, or, in some cases, within three years prior, did own, 15% or more of the corporation’s votingstock. Under Section 203, a business combination between us and an interested stockholder is prohibited unless:·our board of directors approved either the business combination or the transaction that resulted in thestockholders becoming an interested stockholder prior to the date the person attained the status;·upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, theinterested stockholder owned at least 85% of our voting stock outstanding at the time the transactioncommenced, excluding, for purposes of determining the number of shares outstanding, shares owned by personswho are directors and also officers and issued employee stock plans, under which employee participants do nothave the right to determine confidentially whether shares held under the plan will be tendered in a tender orexchange offer; or·the business combination is approved by our board of directors on or subsequent to the date the person becamean interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmativevote of the holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interestedstockholder.This provision has an anti-takeover effect with respect to transactions not approved in advance by our board ofdirectors, including discouraging takeover attempts that might result in a premium over the market price for the shares of ourcommon stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect notto be governed by the anti-takeover law.37 Table of ContentsOur business could be negatively affected by security threats, including cybersecurity threats and other disruptions.As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorizedaccess to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructureor third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. Thepotential for such security threats has subjected our operations to increased risks that could have a material adverse effect onour business. In particular, our implementation of various procedures and controls to monitor and mitigate security threatsand to increase security for our information facilities and infrastructure may result in increased capital and operating costs.Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches fromoccurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, criticalinfrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financialposition, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include,but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronicsecurity breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwiseprotected information, and corruption of data. These events could lead to financial losses from remedial actions, loss ofbusiness or potential liability. Item 1B. Unresolved Staff CommentsNone Item 2. PropertiesAs of December 31, 2017, we operated all of our offshore wells, with an average working interest of 54%, andoperated 48% of our onshore wells with an average working interest of 69%. As of December 31, 2017, our properties werelocated in the following regions: Offshore Gulf of Mexico, Southeast Texas, South Texas, West Texas and Other.Development, Exploration and Acquisition ExpendituresThe following table presents information regarding our net costs incurred in the purchase of proved and unprovedproperties, exploration costs incurred in the search for new reserves from unproved properties and costs incurred in thedevelopment of those properties for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Property acquisition costs: Unproved $6,540 $29,767 $11,453 Proved — — — Exploration costs 8,158 9,126 29,477 Development costs 45,016 1,890 20,120 Total costs $59,714 $40,783 $61,050 Included in unproved property acquisition costs for the year ended December 31, 2017, is $5.9 million related to ouracquisition of unproved property in the Southern Delaware Basin.Included in unproved property acquisition costs for the year ended December 31, 2016, is $27.0 million related toour acquisition of unproved property in the Southern Delaware Basin.Included in unproved property acquisition costs for the year ended December 31, 2015, is $5.0 million related toNatrona and Weston counties, Wyoming.38 Table of ContentsThe following table presents information regarding our share of the net costs incurred by Exaro in the purchase ofproved and unproved properties and in exploration and development activities for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Property acquisition costs $ — $ — $ — Exploration costs — — — Development costs 429 395 4,503 Total costs incurred $429 $395 $4,503 Drilling ActivityThe following tables show our exploratory and developmental drilling activity for the periods indicated. In thetables, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by ourworking interest in such wells. Year Ended December 31, 2017 2016 2015 Gross Net Gross Net Gross Net Exploratory Wells: Productive (onshore) 1 0.5 1 0.8 5 2.9 Productive (offshore) — — — — — — Non-productive (onshore) 1 0.4 — — 1 0.8 Non-productive (offshore) — — — — — — Total 2 0.9 1 0.8 6 3.7 Year Ended December 31, 2017 2016 2015 Gross Net Gross Net Gross Net Development Wells: Productive (onshore) 4 1.9 — — 9 5.3 Productive (offshore) — — — — — — Non-productive (onshore) — — — — — — Non-productive (offshore) — — — — — — Total 4 1.9 — — 9 5.3 Exploration and Development AcreageDeveloped acreage is acreage spaced or assigned to productive wells. Undeveloped acreage is acreage on whichwells have not been drilled or completed to a point that would form the basis to determine whether the property is capable ofproduction of commercial quantities of crude oil, natural gas and natural gas liquids. Gross acres are the total acres in whichwe own a working interest. Net acres are the sum of the fractional working interests we own in gross acres.The following table shows the approximate developed and undeveloped acreage that we have an interest in, byregion, at December 31, 2017. Developed Acreage (1) UndevelopedAcreage (1) Gross Net (2) Gross Net (2) Offshore GOM 9,618 6,828 — — Southeast Texas 22,044 13,143 7,262 3,994 South Texas 78,990 34,537 10,617 6,299 West Texas 6,139 2,883 10,316 3,929 Other 9,956 5,735 62,517 41,733 Total 126,747 63,126 90,712 55,955 (1)Excludes any interest in acreage in which we have no working interest before payout or before initial production.39 (3) Table of Contents(2)Net acres represent the number of acres attributable to our proportionate working interest in a lease (e.g., a 50% working interest in a leasecovering 320 acres is equivalent to 160 net acres).(3)Other includes acreage in Louisiana, Mississippi, Wyoming, North Texas and East Texas.Some of our offshore and onshore leases will expire over the next three years as follows, unless we establishproduction or take action to extend the terms of these leases: Year ending December 31, 2018 2019 2020 GrossAcres NetAcres GrossAcres NetAcres GrossAcres NetAcres Offshore GOM — — — — — — Southeast Texas 328 245 272 264 — — South Texas 3,618 1,809 100 50 — — West Texas 3,174 1,587 2,291 1,059 650 299 North Texas 4,195 — — — — — Wyoming 8,267 10,256 7,880 6,039 5,521 4,417 Total 19,582 13,897 10,543 7,412 6,171 4,716 Production, Price and Cost HistorySee “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”Productive WellsProductive wells are producing wells and wells capable of producing commercial quantities. Completed butmarginally producing wells are not considered here as a “productive” well. The following table sets forth the number of grossand net productive natural gas and oil wells in which we owned an interest as of December 31, 2017: Natural Gas Wells Oil Wells GrossWells (1) NetWells (2) GrossWells (1) NetWells (2) Offshore GOM 11 6.0 — — Southeast Texas 34 19.7 47 25.3 South Texas 171 74.4 46 22.1 West Texas — — 6 2.9 Other 23 4.9 12 4.7 Total 239 105.0 111 55.0 (1)A gross well is a well in which we own an interest.(2)The number of net wells is the sum of our fractional working interests owned in gross wells.Natural Gas and Oil ReservesEstimates of proved reserves and future net revenue as of December 31, 2017, 2016 and 2015 were prepared by NSAIand Cobb, our independent petroleum engineering firms in accordance with the definitions and regulations of the SEC. Thetechnical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists thatmeet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the StandardsPertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of PetroleumEngineers (“SPE”). Approximately 69% and 31% of the proved reserves estimates shown herein at December 31, 2017 havebeen independently prepared by Cobb and NSAI, respectively. Cobb prepared the proved reserves estimates as of December31, 2017, 2016 and 2015 for all of our offshore properties and our onshore Southern Delaware Basin reserves as of December31, 2017, while NSAI prepared the proved reserves estimates as of December 31, 2017, 2016 and 2015 for our remainingonshore properties. The technical individual at NSAI responsible for the preparation of our reserve estimates as of December 31, 2017,2016, and 2015 has over 15 years of experience in the estimation and evaluation of reserves; is a licensed professionalengineer in the state of Texas; and holds a Bachelor of Science Degree in Petroleum Engineering from the University ofTulsa. The technical individual at Cobb responsible for overseeing the preparation of our reserve estimates40 Table of Contentsas of December 31, 2017, 2016, and 2015 has over 40 years of experience in the estimation and evaluation of reserves; is aregistered professional engineer in the state of Texas; holds a Bachelor of Science Degree in Petroleum Engineering fromTexas A&M University; is a member of the SPE; and is a member of the Society of Petroleum Evaluation Engineers.The estimates of proved reserves and future net revenue as of December 31, 2017, 2016 and 2015 were reviewed byour corporate reservoir engineering department that is independent of the operations department. The corporate reservoirengineering department interacts with geoscience, operating, accounting and marketing departments to review the integrity,accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates. All relevantdata is compiled in a computer database application to which only authorized personnel are given access rights. Our SeniorVice President - Engineering is the person primarily responsible for overseeing the preparation of our internal reserveestimates and for reviewing any reserves estimates prepared by our independent petroleum engineering firms. Our SeniorVice President - Engineering has a Bachelor of Science degree in Petroleum Engineering from the University of Texas andover 40 years of industry experience with positions of increasing responsibility. He reports directly to our President andChief Executive Officer. Reserves are also reviewed internally with senior management and presented to our board ofdirectors in summary form on a quarterly basis.We maintain adequate and effective internal controls over the underlying data upon which reserve estimates arebased. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownershipinterests and production data. All field and reservoir technical information, which is communicated to our reservoir engineersquarterly, is confirmed when our third-party reservoir engineers hold technical meetings with geologists, operations and landpersonnel to discuss field performance and to validate future development plans. Current revenue and expense information isobtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set ofinternal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annuallyusing criteria set forth in Internal Controls - Integrated Framework issued by the Committee of Sponsoring Organizations ofthe Treadway Commission. All data such as commodity prices, lease operating expenses, production taxes, field levelcommodity price differentials, ownership percentages and well production data are updated in the reserve database by ourthird-party reservoir engineers and then analyzed by management to ensure that they have been entered accurately and thatall updates are complete. Once the reserve database has been entirely updated with current information, and all relevanttechnical support material has been assembled, our independent engineering firms prepare their independent reserveestimates and final report.41 Table of ContentsThe following table reflects our estimated proved reserves as of the dates indicated: December 31, 2017 2016 2015 Crude Oil and Condensate (MBbl) Developed 3,364 2,158 2,869 Undeveloped 7,285 1,266 1,922 Total 10,649 3,424 4,791 Natural Gas (MMcf) Developed 82,133 95,396 113,952 Undeveloped 9,586 9,657 12,176 Total 91,719 105,053 126,128 Natural Gas Liquids (MBbl) Developed 3,596 3,509 4,354 Undeveloped 2,011 850 1,040 Total 5,607 4,359 5,394 Total MMcfe Developed 123,895 129,399 157,288 Undeveloped 65,359 22,351 29,950 Total 189,254 151,750 187,238 Proved developed reserves percentage 65% 85% 84%Prices utilized in estimates : Crude oil ($/Bbl) $47.41 $38.67 $44.53 Natural gas ($/MMBtu) $2.92 $2.43 $2.63 Natural gas liquids ($/Bbl) $18.59 $13.62 $14.41 (1)Excludes reserves attributable to our 37% interest in Exaro.(2)During the year ended December 31, 2017, proved reserves increased by approximately 37.5 Bcfe primarily due to 63.1 Bcfe of newadditions and extensions related to our drilling program and a 9.9 Bcfe positive revision of reserve estimates due to higher commodityprices, partially offset by 20.1 Bcfe in 2017 production and a 12.2 Bcfe decrease due to a reduction in proved undeveloped reservesrequired by SEC guidelines for those reserves that are not likely to be drilled within a five year period after those reserves are initiallyrecorded.(3)Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month averageprice per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in thetable represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SECrules. All prices were adjusted for quality, energy content, transportation fees and regional price differentials in determining provedreserves.PV‑10PV-10 at year-end is a non-GAAP financial measure and represents the present value, discounted at 10% per year, ofestimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costsusing pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net CashFlows because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor StandardizedMeasure of Discounted Net Cash Flows represents an estimate of fair market value of our natural gas and crude oil properties.PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against pastreserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.42 (1)(1) (1)(2)(3) Table of ContentsThe following table provides a reconciliation of our Standardized Measure to PV‑10 (in thousands): December 31, 2017 2016Pre-tax net present value, discounted at 10% $257,283 $166,228Future income taxes, discounted at 10% (1,376) —Standardized measure of discounted future net cash flows $255,907 $166,228The following table reflects our estimated proved reserves by category as of December 31, 2017 (dollars inthousands): Crude Oil and Natural Gas Natural Gas % ofTotal Condensate (MBbl) (MMcf) Liquids (MBbl) Total (MMcfe) Proved PV - 10 Proved developed producing 3,157 73,694 3,066 111,037 59% $186,098 Proved developed non-producing 207 8,439 530 12,858 7% 14,625 Proved undeveloped 7,285 9,586 2,011 65,359 34% 56,560 Total 10,649 91,719 5,607 189,254 100% $257,283 Our estimated net proved reserves as of December 31, 2017 were approximately 34% crude oil and condensate, 48%natural gas and 18% natural gas liquids.Proved Developed ReservesTotal proved developed reserves declined slightly from 129.4 Bcfe at December 31, 2016 to 123.9 Bcfe at December31, 2017. This decline is primarily due to a 20.1 Bcfe decrease attributable to production during the year and a 1.7 Bcfenegative performance revision, partially offset by 10.7 Bcfe of extensions and additions related to our drilling program and a7.0 Bcfe positive revision of reserve estimates due to higher commodity prices. The following table presents the changes in our total proved developed reserves for the year ended December 31,2017: Proved Developed Reserves (Mmcfe) Proved developed reserves at December 31, 2016 129,399 Revisions of previous estimates 7,008 Extensions, discoveries and other additions 10,743 Purchase of minerals in place — Disposition of reserves in place (1,459) Production (20,123) Negative revisions related to performance (1,673) Proved developed reserves at December 31, 2017 123,895 (1)Positive revisions due to higher commodity prices. (2)Extensions, discoveries and additions are primarily related to our assets in the Southern Delaware Basin in West Texas.(3)Related to the sale of our assets in the North Bob West area and our operated assets in the Escobas area, both located in Southeast Texas.Proved Undeveloped ReservesTotal proved undeveloped reserves (“PUDs”) increased from 22.4 Bcfe at December 31, 2016 to 65.4 Bcfe atDecember 31, 2017. As noted in the table below, this increase was primarily attributable to extensions and additionsprimarily related to the successful development of assets in West Texas, partially offset by the PUDs removed due to theSEC’s five year rule.Future drilling plans and timelines are re-evaluated at the end of each calendar year based on updated reservereports, current drilling cost estimates and product price forecast. Our development plan prioritizes reserves based on thecapital requirements and net present value of potential wells. Generally, our plan is to convert PUDs to developed reserves inan order that is based on their economic importance and impact on production and cash flow, but other factors may beconsidered such as technical merit, product type, location and available working interest partners. The43 (1)(2)(3) Table of ContentsPUD conversion rate in 2017 and 2016 was 0% and 0%, respectively, of the total net present value of the Company’s totalPUDs at the beginning of the applicable year.The Company annually reviews any PUDs to ensure their development within five years from the date of originallyadding the reserves. The Company’s financial resources are expected to be sufficient to drill all of the remaining 65.4 Bcfe ofproved undeveloped reserves within the five year period. Development costs relating to the 65.4 Bcfe at December 31, 2017are projected to be approximately $124.6 million over the next five years.The following table presents the changes in our total proved undeveloped reserves for the year ended December 31,2017: Proved Undeveloped Reserves (Mmcfe) Proved undeveloped reserves at December 31, 2016 22,351 Revisions of previous estimates 2,889 Extensions, discoveries and other additions 52,333 Purchase of minerals in place — Expired undeveloped reserves (12,214) Disposition of reserves in place — Conversion to proved developed — Proved undeveloped reserves at December 31, 2017 65,359 (1)Positive revisions due to higher commodity prices. (2)Extensions, discoveries and additions are primarily related to our assets in the Southern Delaware Basin in West Texas.Significant PropertiesSummary proved reserve information for our properties as of December 31, 2017, by region, is provided below(excluding reserves attributable to our investment in Exaro) (dollars in thousands): Proved Reserves Natural Gas Liquids Regions Crude Oil (MBbl) Natural Gas (MMcf) (MBbl) Total (Mmcfe) PV - 10 Offshore GOM 432 61,430 1,889 75,359 $124,316 Southeast Texas 2,092 11,448 1,146 30,874 37,005 South Texas 1,984 10,196 598 25,687 37,060 West Texas 5,944 8,064 1,965 55,516 55,879 Other 197 581 9 1,818 3,023 Total 10,649 91,719 5,607 189,254 $257,283 (1)Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month averageprice per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). Prices for natural gas liquids in thetable represent average prices for natural gas liquids used in the proved reserve estimates, calculated in accordance with applicable SECrules. All prices, using SEC rules, are adjusted for quality, energy content, transportation fees and regional price differentials in determiningproved reserves.While we are reasonably certain of recovering our calculated reserves, the process of estimating natural gas and oilreserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses,capital expenditures, taxes and availability of funds. Our third party engineers must project production rates, estimate timingand amount of development expenditures, analyze available geological, geophysical, production and engineering data, andthe extent, quality and reliability of all of this data may vary. Actual future production, natural gas and oil prices, revenues,taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likelywill vary from estimates. Any significant variance could materially affect the estimated quantities and net present value ofreserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration anddevelopment, prevailing natural gas and oil prices and other factors, many of which are beyond our control.44 (1) (2)(1) Table of ContentsReserves Attributable to our Investment in ExaroEstimates of proved reserves and future net revenue as of December 31, 2017 and 2016 associated with ourinvestment in Exaro, which we account for using the equity method, were prepared by Von Gonten in accordance with thedefinitions and regulations of the SEC. The technical persons responsible for preparing the reserve estimates are independentpetroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity andconfidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Informationpromulgated by the SPE.Reserves as of December 31, 2017 and 2016 were reviewed by our corporate reservoir engineering department asdescribed above. The technical individual at Von Gonten responsible for overseeing the preparation of our reserve estimatesas of December 31, 2017 and December 31, 2016 has over 17 years of practical experience in the estimation and evaluationof reserves; is a registered professional engineer in the state of Texas; holds a Bachelor of Science Degree in PetroleumEngineering from Texas A&M University; and is a member in good standing of the SPE.The following table reflects the estimated proved reserves attributable to our Investment in Exaro: December 31, 2017 December 31, 2016 December 31, 2015 Crude Oil (MBbl) Developed 325 360 442 Undeveloped 4 — — Total 329 360 442 Natural Gas (MMcf) Developed 28,443 30,441 36,074 Undeveloped 303 — — Total 28,746 30,441 36,074 Total MMcfe Developed 30,390 32,600 38,724 Undeveloped 329 — — Total 30,719 32,600 38,724 Proved developed reserves percentage 99% 100% 100%Standardized measure $24,366 $19,778 $31,298 Prices utilized in estimates Crude oil ($/Bbl) $48.91 $39.60 $44.28 Natural gas ($/MMBtu) $3.02 $2.44 $2.71 (1)The Company's share of the standardized measure of discounted future net cash flows attributable to our investment in Exaro does notinclude the effect of income taxes because Exaro is treated a partnership for tax purposes. Exaro allocates any income or expense for taxpurposes to its partners.(2)Under SEC rules, prices used in determining our proved reserves are based upon an unweighted 12-month first day of the month averageprice per MMBtu (Henry Hub spot) of natural gas and per barrel of oil (West Texas Intermediate posted). All prices are adjusted for quality,energy content, transportation fees and regional price differentials in determining proved reserves.(3)During the year ended December 31, 2017, the decrease in Exaro’s proved reserves attributable to our Investment in Exaro wasapproximately 1.9 Bcfe.Prior Year ReservesOur estimated net proved natural gas, oil and natural gas liquids reserves as of December 31, 2016, 2015 and 2014are disclosed in “Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Disclosures(Unaudited)”. Reserves as of December 31, 2016, 2015 and 2014 were based on reserve reports generated by NSAI and Cobb,while the reserves associated with our 37% investment in Exaro were prepared by Von Gonten. Item 3. Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties,operations or business or arising from disputes with vendors in the normal course of business, including the material mattersdiscussed below.45 (3)(1)(2) Table of ContentsIn July 2010, several parties associated with a limited partnership, formed to invest in oil and gas properties, andthat was dissolved in 1995, filed suit against a subsidiary of the Company and several co-defendants in the district court forMadison County in Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in MadisonCounty, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution,which were distributed to the partners in connection with such dissolution. A predecessor of the subsidiary of the Companyinvolved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partnerof the aforementioned partnership in 2000. The case went to trial in December 2017. As the Court did not allow virtually allof the plaintiff’s claims, a nominal settlement agreement was executed to settle all claims.In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers werenamed in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interestin two wells that has not been recognized by the Company or by predecessor operators to which the Company had grantedindemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorlydocumented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favorof the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decisionto the applicable state Court of Appeals. In the fourth quarter of 2017 the Court of Appeals issued its opinion and affirmedthe trial court’s summary decision. The Company continues to vigorously defend this lawsuit and has filed a motion forrehearing with the Court of Appeals, and if denied, will petition the Texas Supreme Court. In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for HarrisCounty in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operatedby the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred tothe district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claimingownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it ownsan additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (thisclaimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has maderoyalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to thegrantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiffpreviously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additionalhydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiaryand the successors to the grantors under the aforementioned deeds. The plaintiff appealed the trial court’s decision to theapplicable state Court of Appeals. On December 14, 2017, the Court of Appeals affirmed the judgement in the Company’sfavor. The plaintiff has filed a motion for rehearing. The Company continues to vigorously defend this lawsuit and believesthat it has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to theplaintiff could be partially offset by recoupment rights the Company may have against other working interest and/or royaltyinterest owners in the unit.While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing toestimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of theliability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on itsconsolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. TheCompany maintains various insurance policies that may provide coverage when certain types of legal proceedings aredetermined adversely. Item 4. Mine Safety DisclosuresNot applicable.46 Table of Contents PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.Our common stock is listed on the NYSE American under the symbol “MCF”. The table below shows the high andlow sales prices per share of our common stock for the periods indicated. High Low Year Ended December 31, 2017 Quarter Ended March 31, 2017 $10.15 $5.62 Quarter Ended June 30, 2017 $8.19 $5.83 Quarter Ended September 30, 2017 $6.89 $3.97 Quarter Ended December 31, 2017 $5.43 $2.22 Year Ended December 31, 2016 Quarter Ended March 31, 2016 $12.84 $3.68 Quarter Ended June 30, 2016 $14.14 $10.52 Quarter Ended September 30, 2016 $12.85 $8.25 Quarter Ended December 31, 2016 $11.98 $7.43 From the period from January 1, 2018 to March 5, 2018, our common stock traded at prices between $2.80 and$5.97 per share. During the quarter ended September 30, 2016, we completed an underwritten public offering of 5,360,000shares for net proceeds of approximately $50.5 million.GeneralThe following descriptions are summaries of material terms of our common stock, preferred stock, certificate ofincorporation and bylaws. This summary is qualified by reference to our certificate of incorporation, bylaws and thedesignations of our preferred stock, which are filed as exhibits to this report on Form 10-K, and by the provisions ofapplicable law.Common StockWe are authorized to issue up to 50 million shares of common stock. As of March 5, 2018, there were approximately30.9 million shares of common stock issued and 25.5 million shares of common stock outstanding held by approximately228 registered shareholders.Holders of common stock are entitled to one vote for each share held of record on each matter submitted to a vote ofstockholders and, in the event of liquidation, to share ratably in the distribution of assets remaining after payment ofliabilities (including preferential distribution and dividend rights of holders of preferred stock). Holders of common stockhave no cumulative rights. The holders of a plurality of the outstanding shares of the common stock have the ability to electall of the directors.Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock areentitled to such dividends as may be declared by the board of directors out of funds legally available. Therefore, any decisionto pay future dividends on our common stock will be at the discretion of our board of directors and will depend upon ourfinancial condition, results of operations, capital requirements and other factors our board of directors may deem relevant. Wedo not anticipate paying any cash dividends on our common stock in the foreseeable future, as we currently intend to retainall future earnings to fund the development and growth of our business. Our credit facility with Royal Bank of Canada andother lenders currently restricts our ability to pay cash dividends on our common stock, and we may also enter into creditagreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash dividends on ourcommon stock.Preferred StockOur board of directors is authorized, without further stockholder action, to issue preferred stock in one or more seriesand to designate the dividend rate, voting rights and other rights, preferences and restrictions of each such series. We areauthorized to issue up to five million shares of preferred stock. No preferred stock was outstanding at December 31, 2017.47 Table of ContentsShare-Based CompensationThe following table sets forth information about our equity compensation plans at December 31, 2017: Number of securities to be issued upon Weighted-average Number of securities remaining exercise of outstanding exercise price of available for future issuance Plan Category options outstanding options under equity compensation plans Amended and Restated 2009Incentive Compensation Plan -approved by security holders — $ — 2,002,492*2005 Stock Incentive Plan ("CrimsonPlan") 94,833 $57.69 — * Excludes 382,744 Performance Stock Units granted in 2016 and 2017.Amended and Restated 2009 Incentive Compensation Plan On September 15, 2009, the Company’s board of directors (the “Board”) adopted the Contango Oil & Gas CompanyEquity Compensation Plan (the “Original 2009 Plan”), which was approved by shareholders on November 19, 2009. On April10, 2014, the Board amended and restated the Original 2009 Plan through the adoption of the Contango Oil & Gas CompanyAmended and Restated 2009 Incentive Compensation Plan (the “2009 Plan”), which was approved by shareholders on May20, 2014. The 2009 Plan provides for both cash awards and equity awards (such as restricted stock, performance stock unitsand options) to officers, directors, employees and consultants of the Company. Awards made under the 2009 Plan are subjectto such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.Stock options issued under the 2009 Plan must have an exercise price equal to or greater than the market price of theCompany’s common stock on the date of grant. The Company may grant officers and employees both incentive stockoptions intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that arenot qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can onlybe stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. Thevesting schedule for all equity awards varies from immediately to over a four-year period.Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009Plan for the benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan(“LTIP”). The specific performance metrics and targeted performance goals under the CIBP are approved annually, inadvance, by the Compensation Committee and/or the Board. Upon achieving the performance levels established each year,bonus awards under the CIBP will be calculated as a percentage of base salary of each employee for the plan year. The CIBPawards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed bythe Company at the time that awards are disbursed to be eligible. Prior to the 2017 performance year, the LTIP metrics andperformance measures were also determined, in advance, by the Board, with ultimate grants for a performance yeardetermined at the end of the performance year based on performance compared to the previously established goals. Theultimate LTIP awards for each year were also distributed during the first quarter of the following year with a three yearvesting period. Beginning with the 2017 performance year, the Company discontinued the practice of awarding LTIP grantson a look-back basis based on performance compared to operational goals, and implemented the policy of determining anappropriate number of performance stock units (“PSUs”) to be granted to all employees at the beginning of the year, with aspecified number of those granted shares vesting ratably, typically over a three period. The other portion of those grants willvest at the end of a three year performance period, with the ultimate number of shares to be issued based on the Company’sstock performance vs. that of the Company’s peer group during that three year period. The CIBP awards will be paid in cash while the LTIP awards will consist of restricted common stock, PSUs and/orstock options that vest over three or four years. The number of shares of restricted common stock, the PSUs and the number ofshares underlying the stock options granted will be determined based upon the fair market value of the common stock on thedate of the grant.48 Table of ContentsRestricted Stock AwardsDuring the year ended December 31, 2017, the Company granted 457,701 restricted stock awards under the 2009Plan to officers, employees and directors of the Company, while 137,021 restricted shares issued under the 2009 Plan wereforfeited by former employees and are available to be reissued. During the year ended December 31, 2016, 580,141 restrictedstock awards were granted under the 2009 Plan to officers, employees and directors of the Company, while 17,864 restrictedshares were forfeited by former employees and are available to be reissued. During the year ended December 31, 2015,270,091 restricted stock awards were granted under the 2009 Plan to officers, employees and directors of the Companypursuant to the LTIP, while 12,534 restricted shares were forfeited by former employees and are available to be reissued. As ofDecember 31, 2017, there were 731,073 shares of unvested restricted stock outstanding.Performance Stock UnitsDuring the year ended December 31, 2017, the Company granted 30,000 PSUs to a new employee, at a weightedaverage fair value of $8.32 per unit and 160,908 PSUs to executive officers, as part of their overall compensation package, ata value of $13.91 per unit. All prices were determined using the Monte Carlo simulation model. Also during the year, 99,363PSUs were forfeited by former employees.During the year ended December 31, 2016, the Company issued 285,800 PSUs to all employees as part of its LTIP,at a fair value of $16.32 per unit, as determined using the Monte Carlo simulation method. Additionally, the Company issued6,699 PSUs to new employees, at a fair value of $13.06 per unit, also determined using the Monte Carlo simulation method.Former employees forfeited 1,300 PSUs during the year ended December 31, 2016. PSUs represent a contractual right toreceive shares of the Company's common stock. The settlement of PSUs may range from 0% to 300% of the targeted numberof PSUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to apeer group index. The PSUs vest and settlement is determined after a three year period.Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determinedusing the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomesgiven a variety of inputs. As the Compensation Committee intends to settle the PSUs with shares of the Company's commonstock after three years, the PSU awards are accounted for as equity awards and the fair value is calculated on the grant date.The simulation model calculates the payout percentage based on the stock price performance over the performance period.The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair valueexpense is amortized over the life of the PSU award.2005 Stock Incentive Plan The 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. The planexpired on February 25, 2015 and therefore no additional shares are available for grant.During the year ended December 31, 2017, 5,197 restricted stock awards previously issued under the 2005 Plan wereforfeited by former employees, while 17,072 stock options previously issued were forfeited. During the year ended December31, 2016, 1,226 restricted stock awards issued under the 2005 Plan were forfeited by former employees, while 4,556 stockoptions previously issued were forfeited. During the year ended December 31, 2015, the Company granted 7,030 restrictedstock awards under the 2005 Plan to a new employee, while 189 restricted stock awards were forfeited by former employees.Additionally, during the year ended December 31, 2015, 13,473 stock options previously issued were forfeited. As ofDecember 31, 2017, there were no shares of restricted stock outstanding and 94,833 stock options vested and exercisableunder the 2005 Plan. The exercise price for such options ranges from $28.96 to $60.33 per share, with an average remainingcontractual life of three years. 49 Table of ContentsShare Repurchase ProgramIn September 2011, the Company’s board of directors approved a $50 million share repurchase program. All sharesare to be purchased in the open market from time to time by the Company or through privately negotiated transactions. Thepurchases are subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of thepurchases upon the market. No shares were purchased for the years ended December 31, 2017, 2016 and 2015. As ofDecember 31, 2017, the Company has $31.8 million available under its share repurchase program.In addition, the Company repurchased the following shares, outside of the repurchase program, from employees forthe payment of withholding taxes due on vesting shares of restricted stock previously issued under our stock-basedcompensation plans: Total Number of Shares Approximate Dollar Value Total Number of Shares Average Price Paid Purchased as Part of of Shares that may yetPeriod Purchased Per Share Publicly Announced Program be Purchased Under ProgramFebruary 2017 174 $8.08 n/a n/aMarch 2017 11,693 $6.18 n/a n/aApril 2017 10,998 $7.88 n/a n/aJune 2017 116 $6.65 n/a n/aOctober 2017 22,421 $4.11 n/a n/aNovember 2017 276 $3.09 n/a n/aDecember 2017 2,690 $2.96 n/a n/a50 Table of ContentsStock Performance GraphThe following graph compares the yearly percentage change from December 31, 2012 until December 31, 2017 inthe cumulative total stockholder return on our common stock to the cumulative total return on the S&P Smallcap 600 Indexand a peer group of independent oil & gas exploration companies selected by us. As of December 31, 2016, the companies in our selected peer group included Carrizo Oil & Gas, Matador Resources,Bill Barrett, Denbury Resources, SRC Energy, Abraxas Petroleum, Sanchez Energy, EP Energy, Halcon Resources, W&TOffshore and Approach Energy (collectively, the “2016 Peer Group”). For the year ended December 31, 2017, we elected touse the same PSU peer group used under the Company’s LTIP to determine the number of shares of common stock to beissued to employees at the end of the three year performance period. That peer group consisted of: Abraxas Petroleum Corp,Approach Resources Inc, Bill Barrett Corp, Callon Petroleum Co, Carrizo Oil & Gas Inc, Denbury Resources Inc, EnergenCorp, EP Energy Corp, Extraction Oil & Gas Inc, Halcon Resources Corp, Laredo Petroleum Inc, Matador Resources Co,Murphy Oil Corp, Oasis Petroleum Inc, QEP Resources Inc, Sanchez Energy Corp, SM Energy Co, SRC Energy Inc, W&TOffshore Inc, Whiting Petroleum Corp and WPX Energy Inc, (collectively, the “2017 Peer Group”).Our common stock began trading on the NYSE American (previously NYSE MKT) on January 19, 2001 and beforethat had traded on the Nasdaq over-the-counter Bulletin Board. The graph assumes that a $100 investment was made in ourcommon stock and each index on December 31, 2012, adjusted for stock splits and dividends. The stock performance for ourcommon stock is not necessarily indicative of future performance. 12/31/2012 12/31/2013 12/31/2014 12/31/2015 12/31/2016 12/31/2017 Contango Oil & Gas Company 100.00 111.57 69.03 15.13 22.05 11.12 S&P Smallcap 600 100.00 141.31 149.45 146.50 185.40 209.94 2016 Peer Group 100.00 112.08 68.87 33.47 46.28 36.35 2017 Peer Group 100.00 129.55 80.05 40.40 62.52 48.93 51 Table of ContentsItem 6. Selected Financial DataOn October 1, 2013, the Company's board of directors approved a change in fiscal year end from June 30 toDecember 31. Unless otherwise noted, all references to "years" in this report refer to the twelve-month period which ends onDecember 31 of each year. The following selected financial data for the years ended December 31, 2017, 2016 and 2015 havebeen derived from the audited consolidated financial statements of Contango contained in this Form 10-K. The followingselected financial data for the years ended December 31, 2014 and 2013 have been derived from the audited consolidatedfinancial statements of Contango contained in our Form 10-K for the applicable fiscal year. The selected consolidatedfinancial data (not including proved reserve information) set forth below is for continuing operations and should be read inconjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” andwith the consolidated financial statements and notes to those consolidated financial statements included elsewhere in thisForm 10-K.Selected financial data for the years ended December 31, 2017, 2016, 2015, 2014 and 2013 include results ofoperations and cash flows of Crimson starting from October 1, 2013, the date of the Merger. Consolidated balance sheet andreserves information as of December 31, 2017, 2016, 2015, 2014 and 2013 include the balance sheet and reservesinformation of Crimson and its subsidiaries adjusted in accordance with the acquisition method of accounting, whichrequires that assets acquired and liabilities assumed in the Merger be recorded at their fair value at the date of acquisitionwith the difference between the purchase price and value of assets and liabilities be recorded as goodwill. No goodwill wasrecognized as a result of the Merger between Contango and Crimson.Selected financial information for the five years ended December 31, 2017 is as follows (dollars in thousands, exceptper share amounts): Year Ended December 31 2017 2016 2015 2014 2013 Natural gas and oil sales $78,545 $78,183 $116,505 $276,458 $164,121 Income (loss) $(17,643) $(58,029) $(335,048) $(21,874) $41,362 Net income (loss) attributable to common stock $(17,643) $(58,029) $(335,048) $(21,874) $41,362 Net income (loss) per share: Basic $(0.71) $(2.71) $(17.67) $(1.15) $2.56 Diluted $(0.71) $(2.71) $(17.67) $(1.15) $2.56 Weighted average shares outstanding: Basic 24,686 21,424 18,965 19,059 16,156 Diluted 24,686 21,424 18,965 19,059 16,158 Year Ended December 31 2017 2016 2015 2014 2013 Working capital (deficit) $(34,764) $(43,835) $(18,689) $(65,975) $(33,162) Capital expenditures $58,376 $38,966 $55,565 $188,529 $62,552 Long term debt $85,380 $54,354 $115,446 $63,359 $90,000 Shareholders’ equity $224,600 $236,405 $237,843 $567,466 $593,050 Total assets $381,453 $376,514 $416,756 $843,415 $910,304 Proved Reserve Data: Total proved reserves (Mmcfe) 189,254 151,750 187,238 275,193 313,866 Pre-tax net present value (discounted 10%) $257,283 $166,228 $249,406 $796,871 987,213 Standardized measure $255,907 $166,228 $249,406 $648,016 771,443 (1)The increase in natural gas and oil sales for the year ended December 31, 2017 is primarily attributable to higher commodity prices duringthe year. The decrease in natural gas and oil sales for the year ended December 31, 2016 is attributable to lower commodity prices duringthe year and lower production resulting from the significant reduction in our capital program. The decrease in natural gas and oil sales forthe year ended December 31, 2015 is attributable to the decline in commodity prices during the fourth quarter of 2014 and during 2015,combined with lower production as a result of a reduction in our 2015 drilling program. The increase in natural gas and oil sales for theyear ended December 31, 2014 is attributable to the Merger with Crimson and new production from our 2013 and 2014 drilling program.52 (1)(2)(3) (4) (4) Table of Contents(2)During the year ended December 31, 2017, we recognized approximately $0.3 million for impairment of proved properties, related torevised estimated reserves for our TMS properties. Additionally, we recognized $1.5 million related the partial impairment of two unusedoffshore platforms in onshore storage.During the year ended December 31, 2016, we recognized approximately $0.7 million for impairment of proved properties, substantially allof which was directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from theassociated reserves. Additionally, we recognized $6.8 million related to our unproved properties in Fayette and Gonzales counties Texas and$2.9 million related to our unproved acreage in Natrona County, Wyoming.During the year ended December 31, 2015, we recognized approximately $269.6 million for impairment of proved properties, substantiallyall of which was directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from theassociated reserves. Additionally, we recognized approximately $16.3 million for impairment and partial impairment of certain unprovedproperties and onshore prospects primarily due to the sustained low commodity price environment and expiring leases.During the year ended December 31, 2014, we reached a total depth on our Ship Shoal 255 well, and no hydrocarbons were found. As aresult, we recognized $31.5 million in exploration expense for the cost of drilling the well and $15.6 million in impairment expense,including $3.5 million related to leasehold costs and $12.1 million related to the platform located in Ship Shoal 263 block which wasexpected to be used by the Ship Shoal 255 had it been successful. Additionally, during the year ended December 31, 2014, we revisedestimated proved reserves for South Timbalier 17 and our TMS properties, resulting in non-cash impairment expenses of approximately$11.4 million. During the year ended December 31, 2014, we also recognized impairment expense of approximately $20.1 million relatedto full or partial impairment of certain unproved properties due to expiring leases and leases not likely to be drilled.(3)The increase in the deficit in working capital for the years ended December 31, 2017 and 2016 was primarily related to our activity in WestTexas, beginning in the fourth quarter of 2016. The decrease in the deficit in working capital during 2015 was a result of the decrease indrilling activity and the satisfaction of trade obligations existing at the beginning of the year, which were attributable to a more active 2014drilling program. The increase in the working capital deficit for the year ended December 31, 2014 was primarily attributable to the highertrade obligations associated with the drilling program in late 2014 and a decrease in trade receivables associated with the decline incommodity prices during the fourth quarter of 2014. On October 1, 2013, in connection with the Merger, we entered into a revolving creditfacility with Royal Bank of Canada and other lenders.(4)During the year ended December 31, 2017, our proved reserves increased by approximately 37.5 Bcfe and our standardized measureincreased by approximately $89.7 million. This increase is primarily due to 63.1 Bcfe of additions and extensions related to our assets inWest Texas and a 9.9 Bcfe positive revision of reserve estimates due to higher commodity prices, partially offset by 20.1 Bcfe in 2017production and a 12.2 Bcfe decrease due a reduction in proved undeveloped reserves required by SEC guidelines for those reserves that arenot likely to be drilled within a five year period after those reserves are initially recorded.During the year ended December 31, 2016, our proved reserves decreased by approximately 35.5 Bcfe and our standardized measuredecreased by approximately $83.2 million. This decrease is primarily due to 26.0 Bcfe of production, an 8.3 Bcfe negative revision ofreserve estimates due to low commodity prices and 4.2 Bcfe due to the sale of our Colorado properties, partially offset by 2.5 Bcfe related topositive performance revisions.During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe and our standardized measuredecreased by approximately $398.6 million. This decrease is primarily attributable to 2015 production and to the impact of the dramaticdecline in commodity prices on the value and volume of our proved reserves and in part to the impact of the significant reduction in ourcapital spending in response to the low and uncertain commodity price environment.During the year ended December 31, 2014, our proved reserves decreased by approximately 38.7 Bcfe and our standardized measuredecreased by approximately $123.4 million. This decrease is primarily attributable to 40.3 Bcfe of production and a 22.4 Bcfe negativerevision of proved developed producing reserves at our Eugene Island 11 field due to a change in forecasted condensate yield and ultimatefield abandonment pressure; these decreases were partially offset by 36.1 Bcfe for extensions and discoveries.During the year ended December 31, 2013, our proved reserves increased by approximately 92.8 Bcfe and our standardized measureincreased by approximately $383.4 million, primarily as a result of our Merger with Crimson. Also contributing to the increase was theexercise of our preferential right to purchase approximately 17.0 Bcfe related to our five Contango-operated Dutch wells, slightly offset by28.2 Bcfe of production, a 19.2 Bcfe decrease in our Dutch and Mary Rose reserve estimates based upon additional pressure data, and a 2.5Bcfe decrease in our Vermilion 170 reserve estimates, as determined by our reservoir engineer. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe following discussion and analysis of our financial condition and results of operations should be read inconjunction with the financial statements and the related notes and other information included elsewhere in this report.OverviewWe are a Houston, Texas based independent oil and natural gas company. Our business is to maximize productionand cash flow from our offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore Texas andWyoming properties and to use that cash flow to explore, develop, exploit, produce and acquire crude oil and natural gasproperties in the onshore Texas and Rocky Mountain regions of the United States.53 Table of ContentsOn October 1, 2013, we completed a merger with Crimson Exploration Inc. (“Crimson”) (the “Merger”). We havehistorically focused our operations in the GOM, but the Merger gave us access to high rate of return onshore prospects inknown, prolific producing areas as well as long-life resource plays. In 2015, prior to the decline in crude oil and natural gasprices, our drilling activity focused primarily on the Woodbine oil and liquids-rich play in Madison and Grimes counties,Texas (our Southeast Texas Region), in the Cretaceous Sands in Fayette and Gonzales counties, Texas (our South TexasRegion) and Wyoming where we were targeting the Mowry Shale and the Muddy Sandstone formations. Beginning in thesecond half of 2015, we reduced our drilling program in response to the challenging commodity price environment. As aresult, until the latter half of 2016, our only drilling activity was in Weston County, Wyoming, where we completed our thirdwell targeting the Muddy Sandstone formation. During the third quarter of 2016, we acquired a 12,100 operated gross acreposition (5,000 net) in the Southern Delaware Basin in Pecos County, Texas, (the “Acquisition”) and as of December 31,2017, had increased our acreage in the Southern Delaware Basin to 16,500 gross acres (6,800 net). Since the Acquisition, wehave begun production from seven wells in the Southern Delaware Basin and are waiting on completion of an eighth well.We currently expect that the Southern Delaware Basin position will continue to be the primary focus of our drilling programfor 2018. Additionally, we have (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”), which is primarily focused onthe development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producing fromvarious conventional formations in various counties along the Texas Gulf Coast; and (iii) operated producing properties inthe Haynesville Shale, Mid Bossier and James Lime formations in East Texas. Until their sale in December 2016, we also hadoperated producing properties in the Denver Julesburg Basin (“DJ Basin”) in Weld and Adams counties in Colorado.Our production for the year ended December 31, 2017 was approximately 20.1 Bcfe (or 55.1 Mmcfe/d) and was 68%offshore and 32% onshore. Our production for the three months ended December 31, 2017 was approximately 4.8 Bcfe (or51.8 Mmcfe/d) and was 66% offshore and 34% onshore. As of December 31, 2017, our proved reserves were approximately40% offshore and 60% onshore and were 65% proved developed, which were approximately 61% offshore and 39% onshore.Revenues and ProfitabilityOur revenues, profitability and future growth depend substantially on our ability to find, develop and acquirenatural gas and oil reserves that are economically recoverable, as well as prevailing prices for natural gas and oil.Reserve ReplacementGenerally, producing properties offshore in the Gulf of Mexico have high initial production rates, followed by steepdeclines. Likewise, initial production rates on new wells in the onshore resource plays start out at a relatively high rate with adecline curve which results in 60% to 70% of the ultimate recovery of present value occurring in the first eighteen months ofthe well’s life. We must locate and develop, or acquire, new natural gas and oil reserves to replace those being depleted byproduction. Substantial capital expenditures are required to find, develop and/or acquire natural gas and oil reserves. Aprolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities ofour proved reserve portfolio, assuming no other changes in our development plans. The Merger with Crimson allowed theCompany to add significant proved developed and undeveloped reserves and provided the Company with access to severalonshore resource plays which have substantial reserve growth potential, including in oil and liquids rich plays that positionus to move to a more balanced oil/gas profile.Use of EstimatesThe preparation of our financial statements requires the use of estimates and assumptions that affect the reportedamounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, andthe reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.Significant estimates with regard to these financial statements include estimates of remaining proved natural gas and oilreserves, the timing and costs of our future drilling, development and abandonment activities, and income taxes.See “Item 1A. Risk Factors” for a more detailed discussion of a number of other factors that affect our business,financial condition and results of operations.54 Table of ContentsResults of Operations The table below sets forth our average net daily production data in Mmcfe/d from our fields for each of the periodsindicated: Three Months Ended March 31, June 30, September 30, December 31, March 31, June 30, September 30, December 31, 2016 2016 2016 2016 2017 2017 2017 2017 Offshore GOM Dutch andMary Rose 45.9 43.3 39.3 39.5 35.4 36.3 32.2 30.8 Vermilion 170 6.5 6.2 4.0 4.9 4.6 3.1 4.2 3.5 South Timbalier17 0.6 0.6 0.6 0.6 0.5 0.2 0.1 — SoutheastTexas 16.4 13.9 12.1 10.1 8.6 8.2 7.8 7.5 South Texas 7.4 7.4 7.5 7.5 6.4 5.6 4.6 5.8 West Texas — — — — 0.6 3.3 3.2 3.2 Other 2.6 3.2 2.2 1.7 1.5 1.3 1.1 1.0 79.4 74.6 65.7 64.3 57.6 58.0 53.2 51.8 (1)Includes a 26 day shut in for compressor repair during the three months ended March 31, 2017(2)Includes a decreased production rate of 0.8 Mmcfe/d due to temporary pipeline limitations during the three months ended June 30, 2017.(3)South Timbalier 17 ceased production in August 2017.(4)Includes Woodbine production from Madison and Grimes counties and conventional production in others.(5)Includes Eagle Ford and Buda production from Karnes, Zavala and Dimmit counties, and conventional production in others.(6)Includes onshore wells primarily in Colorado, East Texas, and Wyoming during 2016 and onshore wells primarily in East Texas andWyoming during 2017.55 (1)(2)(3)(4)(5)(6) Table of ContentsYear Ended December 31, 2017 Compared to Year Ended December 31, 2016; and Year Ended December 31,2016 Compared to Year Ended December 31, 2015The table below sets forth revenue, production data, average sales prices and average production costs associatedwith our sales of natural gas, oil and natural gas liquids ("NGLs") from continuing operations for the years endedDecember 31, 2017, 2016 and 2015. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of naturalgas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six Mcf of natural gas. Reported operatingexpenses include production taxes, such as ad valorem and severance. Year Ended December 31, Year Ended December 31, 2017 2016 % 2016 2015 % Revenues (thousands): Oil and condensate sales $25,347 $23,006 10% $23,006 $43,230 (47)%Natural gas sales 41,317 43,847 (6)% 43,847 59,058 (26)%NGL sales 11,881 11,330 5% 11,330 14,217 (20)%Total revenues $78,545 $78,183 —% $78,183 $116,505 (33)% Production: Oil and condensate (thousand barrels) Dutch and Mary Rose 89 120 (26)% 120 164 (27)%Vermilion 170 10 16 (38)% 16 22 (27)%Southeast Texas 151 239 (37)% 239 493 (52)%South Texas 95 128 (26)% 128 178 (28)%West Texas 133 — 100% — — —%Other 40 94 (57)% 94 67 40%Total oil and condensate 518 597 (13)% 597 924 (35)%Natural gas (million cubic feet) Dutch and Mary Rose 9,891 12,375 (20)% 12,375 14,736 (16)%Vermilion 170 1,222 1,616 (24)% 1,616 2,050 (21)%Southeast Texas 1,328 2,059 (36)% 2,059 3,136 (34)%South Texas 1,112 1,528 (27)% 1,528 1,788 (15)%West Texas 82 — 100% — — —%Other 275 525 (48)% 525 904 (42)%Total natural gas 13,910 18,103 (23)% 18,103 22,614 (20)%Natural gas liquids (thousand barrels) Dutch and Mary Rose 310 378 (18)% 378 454 (17)%Vermilion 170 20 42 (52)% 42 60 (30)%Southeast Texas 115 217 (47)% 217 359 (40)%South Texas 60 72 (17)% 72 87 (17)%West Texas 12 — 100% — — —%Other — 7 (100)% 7 8 (13)%Total natural gas liquids 517 716 (28)% 716 968 (26)%Total (million cubic feet equivalent) Dutch and Mary Rose 12,283 15,364 (20)% 15,364 18,443 (17)%Vermilion 170 1,402 1,965 (29)% 1,965 2,545 (23)%Southeast Texas 2,924 4,792 (39)% 4,792 8,249 (42)%South Texas 2,038 2,729 (25)% 2,729 3,379 (19)%West Texas 947 — 100% — — —%Other 529 1,132 (53)% 1,132 1,345 (16)%Total production 20,123 25,982 (23)% 25,982 33,961 (23)% 56 Table of Contents Year Ended December 31, Year Ended December 31, 2017 2016 % 2016 2015 % Daily Production: Oil and condensate (thousand barrels per day) Dutch and Mary Rose 0.2 0.3 (26)% 0.3 0.4 (27)%Vermilion 170 — — (38)% — 0.1 (27)%Southeast Texas 0.4 0.7 (37)% 0.7 1.4 (52)%South Texas 0.3 0.4 (26)% 0.4 0.5 (28)%West Texas 0.4 — 100% — — —%Other 0.1 0.2 (57)% 0.2 0.1 40%Total oil and condensate 1.4 1.6 (13)% 1.6 2.5 (35)%Natural gas (million cubic feet per day) Dutch and Mary Rose 27.1 33.8 (20)% 33.8 40.4 (16)%Vermilion 170 3.3 4.4 (24)% 4.4 5.6 (21)%Southeast Texas 3.6 5.6 (36)% 5.6 8.6 (34)%South Texas 3.0 4.2 (27)% 4.2 4.9 (15)%West Texas 0.2 — 100% — — —%Other 0.9 1.5 (48)% 1.5 2.4 (42)%Total natural gas 38.1 49.5 (23)% 49.5 61.9 (20)%Natural gas liquids (thousand barrels per day) Dutch and Mary Rose 0.9 1.0 (18)% 1.0 1.2 (17)%Vermilion 170 — 0.1 (52)% 0.1 0.2 (30)%Southeast Texas 0.3 0.6 (47)% 0.6 1.0 (40)%South Texas 0.2 0.2 (17)% 0.2 0.2 (17)%West Texas — — 100% — — —%Other — 0.1 (100)% 0.1 — (13)%Total natural gas liquids 1.4 2.0 (28)% 2.0 2.6 (26)%Total (million cubic feet equivalent per day) Dutch and Mary Rose 33.7 42.0 (20)% 42.0 50.5 (17)%Vermilion 170 3.8 5.4 (29)% 5.4 7.0 (23)%Southeast Texas 8.0 13.1 (39)% 13.1 22.6 (42)%South Texas 5.6 7.5 (25)% 7.5 9.3 (19)%West Texas 2.6 — 100% — — —%Other 1.4 3.0 (53)% 3.0 3.6 (16)%Total production 55.1 71.0 (23)% 71.0 93.0 (23)% Average Sales Price: Oil and condensate (per barrel) $48.90 $38.52 27% $38.52 $46.80 (18)%Natural gas (per thousand cubic feet) $2.97 $2.42 23% $2.42 $2.61 (7)%Natural gas liquids (per barrel) $22.97 $15.79 45% $15.79 $14.68 8%Total (per thousand cubic feet equivalent) $3.90 $3.01 30% $3.01 $3.43 (12)% Expenses (thousands): Operating expenses $27,183 $29,111 (7)% $29,111 $37,840 (23)%Exploration expenses $1,106 $1,816 (39)% $1,816 $11,979 (85)%Depreciation, depletion and amortization $47,215 $63,323 (25)% $63,323 $133,380 (53)%Impairment and abandonment of oil and gas properties $2,395 $10,572 (77)% $10,572 $285,877 (96)%General and administrative expenses $24,161 $26,802 (10)% $26,802 $26,402 2%Gain (Loss) from investment in affiliates (net of taxes) $2,697 $1,545 75% $1,545 $(30,582) (105)%Other (Income) Expense $2,780 $(5,791) (148)% $(5,791) $(719) 705% Selected data per Mcfe: Operating expenses $1.35 $1.12 21% $1.12 $1.11 1%General and administrative expenses $1.20 $1.03 17% $1.03 $0.78 32%Depreciation, depletion and amortization $2.35 $2.44 (4)% $2.44 $3.93 (37)% 57 Table of ContentsNatural Gas, Oil and NGL Sales and ProductionAll of our revenues are from the sale of our natural gas, crude oil and natural gas liquids production. Our revenuesmay vary significantly from year to year depending on changes in commodity prices, which fluctuate widely, and productionvolumes. Our production volumes are subject to wide swings as a result of new discoveries, weather and mechanical relatedproblems. In addition, the production rate associated with our oil and gas properties declines over time as we produce ourreserves.We reported revenues of approximately $78.5 million for the year ended December 31, 2017, compared to revenuesof approximately $78.2 million for the year ended December 31, 2016. This slight increase in revenues was primarilyattributable to higher oil and natural gas prices in 2017, which offset the decline in production caused by only adding fivenew producing wells in the Southern Delaware Basin since late 2016 and minor non-core property sales.Total production for the year ended December 31, 2017 was approximately 20.1 Bcfe, or 55.1 Mmcfe/d, comparedto approximately 26.0 Bcfe, or 71.0 Mmcfe/d, in the prior year. The decrease was attributable to a 6.7 Mmcfe/d decline inproduction resulting from normal field decline and a limited 2016 drilling program, a 1.2 Mmcfe/d decline due to non-coreproperty sales, a 0.4 Mmcfe/d decline from downtime associated with the impact of Hurricane Harvey, and a 0.2 Mmcfe/ddecline due to temporary pipeline limitations at the Vermillion 170 field. The decrease in production was partially offset by2.6 Mmcfe/d of new production from drilling on our Southern Delaware Basin acreage. Net natural gas production for theyear ended December 31, 2017 was approximately 38.1 Mmcf/d, compared with approximately 49.5 Mmcf/d for the yearended December 31, 2016. Net oil production declined from approximately 1,600 barrels per day to 1,400 barrels per day,while NGL production decreased from approximately 2,000 barrels per day to 1,400 barrels per day.We reported revenues of approximately $78.2 million for the year ended December 31, 2016, compared to revenuesof approximately $116.5 million for the year ended December 31, 2015. This decrease in revenues was primarily attributableto lower oil and natural gas prices in 2016 and lower production resulting from the significant reduction in our capitalprogram because of the dramatic decline in, and uncertain outlook for, commodity prices.Total production for the year ended December 31, 2016 was approximately 26.0 Bcfe, or 71.0 Mmcfe/d, comparedto approximately 34.0 Bcfe, or 93.0 Mmcfe/d, in the prior year, a decline attributable in large part to our limited drillingactivity in 2016 due to the low commodity price environment. Net natural gas production for the year ended December 31,2016 was approximately 49.5 Mmcf/d, compared with approximately 61.9 Mmcf/d for the year ended December 31, 2015,due to normal decline in production from our offshore properties. Net oil production declined from approximately 2,500barrels per day to 1,600 barrels per day, while NGL production decreased from approximately 2,600 barrels per day to 2,000barrels per day. Both decreases were a result of the first half of 2015 including initial oil production from our new wellsbrought on production in Madison and Grimes counties of our Southeast Texas Region which were not offset by newproduction in 2016 due to a limited capital program.Average Sales PricesThe average equivalent sales price realized for the years ended December 31, 2017, 2016 and 2015 was $3.90 perMcfe, $3.01 per Mcfe and $3.43 per Mcfe, respectively. The price of natural gas for the years ended December 31, 2017, 2016and 2015 was $2.97 per Mcf, $2.42 per Mcf and $2.61 per Mcf, respectively. The price for oil for the years ended December31, 2017, 2016 and 2015 was $48.90 per barrel, $38.52 per barrel and $46.80 per barrel, respectively. The price for NGLs forthe years ended December 31, 2017, 2016 and 2015 was $22.97 per barrel, $15.79 per barrel and $14.68 per barrel,respectively.Operating Expenses (including production taxes)Operating expenses for the year ended December 31, 2017 were approximately $27.2 million, or $1.35 per Mcfe,compared to approximately $29.1 million, or $1.12 per Mcfe, for the year ended December 31, 2016. Operating expenses forthe year ended December 31, 2015 were approximately $37.8 million, or $1.11 per Mcfe. The table below providesadditional detail of operating expenses for the years ended December 31, 2017, 2016 and 2015.58 Table of Contents Twelve Months Ended December 31, 2017 2016 2015 (in thousands) (per Mcfe) (in thousands) (per Mcfe) (in thousands) (per Mcfe) Lease operating expenses $17,458 $0.87 $18,608 $0.72 $25,124 $0.74 Production & ad valorem taxes 2,568 0.13 3,248 0.13 4,747 0.14 Transportation & processing costs 4,866 0.24 5,491 0.20 4,714 0.13 Workover costs 2,291 0.11 1,764 0.07 3,255 0.10 Total operating expenses $27,183 $1.35 $29,111 $1.12 $37,840 $1.11 Production and ad valorem taxes decreased by 21% for the year ended December 31, 2017, compared to the yearended December 31, 2016, primarily as a result of property sales and lower legacy production, partially offset by productiontaxes on new West Texas production. Production and ad valorem taxes decreased by 32% for the year ended December 31,2016, compared to the prior year, primarily due to the decrease in revenues for the same period. Lease operating expenses decreased by 26% for the year ended December 31, 2016, compared to the year endedDecember 31, 2015, as a direct result of our efforts to reduce costs during the second half of 2015 and in 2016 in response tothe challenging commodity price environment.Exploration ExpensesWe reported approximately $1.1 million and $1.8 million of exploration expenses for the years ended December 31,2017 and 2016, respectively, which were primarily related to geological and geophysical software, seismic data licensingfees and mapping services. We reported approximately $12.0 million of exploration expenses for the year ended December31, 2015, which included $6.7 million in dry-hole costs related to our State #1H well in Natrona County, Wyoming, and $2.8million related to the early termination of a drilling rig contract.Depreciation, Depletion and AmortizationDepreciation, depletion and amortization for the year ended December 31, 2017 was approximately $47.2 million,or $2.35 per Mcfe, compared to approximately $63.3 million, or $2.44 per Mcfe, for the year ended December 31, 2016, adecrease primarily attributable to lower production during 2017.Depreciation, depletion and amortization for the year ended December 31, 2016 was approximately $63.3 million,or $2.44 per Mcfe, compared to approximately $133.4 million, or $3.93 per Mcfe, for the year ended December 31, 2015, adecrease primarily attributable to lower production during 2016. The rate decrease is primarily attributable to the impairmentrecorded in 2015.Impairment and Abandonment of Oil and Gas PropertiesImpairment and abandonment expenses for the year ended December 31, 2017 included proved property impairmentof $0.3 million related to revised estimated reserves for our Tuscaloosa Marine Shale properties. Impairment expenses for theyear ended December 31, 2017 also included a $1.5 million partial impairment of two unused offshore platforms in onshorestorage.Impairment and abandonment expenses for the year ended December 31, 2016 included proved property impairmentof $0.7 million related to the decline in commodity prices and the resulting impact on estimated future net cash flows fromassociated reserves. Impairment expenses for the year ended December 31, 2016 also included $6.8 million impairmentrelated to our unproved properties in Fayette and Gonzales counties, Texas and $2.9 million related to our unproved acreagein Natrona County, Wyoming.Impairment and abandonment expenses for the year ended December 31, 2015 included proved property impairmentof $269.6 million related to the decline in commodity prices and the resulting impact on estimated future net cash flows fromassociated reserves. Approximately $235.8 million of the total proved property impairment for the year ended December 31,2015 is attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes counties properties, our highest valuedproperties stemming from the Merger with Crimson. Impairment expenses for the year ended December 31, 2015 included a$16.3 million impairment of certain unproved properties and onshore prospects due primarily to the sustained lowcommodity price environment and expiring leases. Approximately $9.3 million of the total for the year ended December 31,2015 is related to unproved lease cost amortization of the Elm Hill project in Fayette and Gonzales counties, Texas.59 Table of ContentsGeneral and Administrative ExpensesTotal general and administrative expenses for the year ended December 31, 2017 were approximately $24.2 million,compared to $26.8 million for the year ended December 31, 2016. The decrease in general and administrative costs canprimarily be attributed to lower bonus accruals for the 2017 performance period and lower professional fees, insuranceexpense and office costs during the year ended December 31, 2017. Included in our current year expense was approximately$6.1 million in non-cash stock based compensation. Included in the prior year expense was approximately $6.5 million innon-cash stock based compensation. Exclusive of the stock compensation, cash general and administrative expenses for thecurrent year were $18.1 million, compared to cash expenses of $20.3 million for the prior year.General and administrative expenses for the year ended December 31, 2016 were approximately $26.8 million,compared to $26.4 million for the year ended December 31, 2015. Included in the 2016 expense was approximately $6.5million in non-cash stock based compensation. Included in the 2015 expense was approximately $0.6 million in cashseverance costs resulting from an August 2015 reduction in force and $6.5 million in non-cash stock based compensation.Exclusive of the stock compensation and severance related costs, cash general and administrative expenses for the yearended December 30, 2016 were $20.3 million, compared to cash expenses of $19.3 million for the year ended December 31,2015.Gain (loss) from AffiliatesFor the year ended December 31, 2017, the Company recorded a gain from affiliates of approximately $2.7 million,net of no tax expense, related to our equity investment in Exaro, compared with a gain from affiliates of approximately $1.5million, net of no tax expense, for the year ended December 31, 2016.For the year ended December 31, 2016, the Company recorded a gain from affiliates of approximately $1.5 million,net of no tax expense, related to our equity investment in Exaro, compared with a loss from affiliates of approximately $30.6million, net of tax benefit of $16.5 million, for the year ended December 31, 2015.Other Income (Expense)Other income for the year ended December 31, 2017 was approximately $2.8 million, which consists of a $2.3million gain on sale of assets, a $3.3 million net gain on derivatives, and a $1.3 million gain related to the sale of ourinvestment in a small private service company. Other income was partially offset by interest expense of $4.1 million. Other expense for the year ended December 31, 2016 was approximately $5.8 million, which is primarily related tointerest expense of $3.8 million and loss on derivatives of $1.6 million.Other expense for the year ended December 31, 2015 was approximately $0.7 million, which is primarily related to$5.6 million of costs incurred in pursuit of an unsuccessful acquisition in the fourth quarter and interest expense of $3.2million, partially offset by $6.1 million in proceeds related to favorable outcomes in two lawsuits and gain on derivatives of$2.3 million.Capital Resources and LiquidityOur primary cash requirements are for capital expenditures, working capital, operating expenses, acquisitions andprincipal and interest payments on indebtedness. Our primary sources of liquidity are cash generated by operations, net of therealized effect of our hedging agreements, and amounts available to be drawn under our credit facility.60 Table of ContentsThe table below summarizes certain measures of liquidity and capital expenditures, as well as our sources of capitalfrom internal and external sources, for the periods indicated, in thousands. Year ended December 31, 2017 2016 2015 Net cash provided by operating activities $34,686 $32,011 $24,955 Net cash used in investing activities $(65,450) $(19,798) $(76,806) Net cash provided by (used in) financing activities $30,764 $(12,213) $51,851 Cash and cash equivalents at the end of the period $ — $ — $ — Cash flow from operating activities, including changes in working capital, provided approximately $34.7 million incash for the year ended December 31, 2017 compared to $32.0 million for the year ended December 31, 2016. The changes inworking capital were approximately $5.1 million during 2017, compared to $7.8 million during 2016. Cash flow fromoperating activities, excluding changes in working capital, provided approximately $29.6 million in cash for the year endedDecember 31, 2017 compared to $24.2 million for the year ended December 31, 2016. This increase in cash provided byoperating activities was primarily attributable to higher revenues associated with higher prices, partially offset by lowerproduction.Cash flow from operating activities, including changes in working capital, provided approximately $32.0 million incash for the year ended December 31, 2016 compared to $25.0 million for the year ended December 31, 2015. The changes inworking capital were approximately $7.8 million during 2016, compared to a deficit in 2015 of approximately $27.2 million.Cash flow from operating activities, excluding changes in working capital, provided approximately $24.2 million in cash forthe year ended December 31, 2016 compared to $52.2 million for the year ended December 31, 2015. This decrease in cashprovided by operating activities was primarily attributable to lower revenues associated with lower prices and lowerproduction resulting from our reduced drilling activity in 2016 due to the low commodity price environment.For the year ended December 31, 2017, we incurred $58.4 million in capital costs, primarily related to drillingand/or completing wells in the Southern Delaware Basin and acquiring or extending unproved leases. Of this amount,approximately $66.6 million was paid during the year, partially offset by $1.1 million primarily related to the sale of ourassets in the North Bob West area and our operated assets in the Escobas area, both located in Southeast Texas, resulting innet cash used in investing activities of approximately $65.5 million for the year ended December 31, 2017.For the year ended December 31, 2016, we incurred $39.0 million in capital costs, including $20.0 million for theacquisition of our Southern Delaware Basin acreage. Of this amount, approximately $24.9 million was paid during the year,partially offset by $5.1 million received for the sale of our Colorado properties, resulting in net cash used in investingactivities of approximately $19.8 million for the year ended December 31, 2016.For the year ended December 31, 2015, we incurred $55.6 million in capital costs. Of this amount, approximately$77.8 million was paid during the year, partially offset by approximately $1.0 million in distributions from REX as a resultthe dissolution of that entity, resulting in net cash used in in investing activities of approximately $76.8 million for the yearended December 31, 2015.Cash provided by financing activities was approximately $30.8 million for the year ended December 31, 2017compared to $12.2 million used in financing activities in 2016. The 2017 activity was primarily related to net borrowingsunder our RBC Credit Facility (defined below). The 2016 activity included net repayments of outstandings under our RBCCredit Facility.Cash used in financing activities was approximately $12.2 million for the year ended December 31, 2016 comparedto $51.9 million provided by financing activities in 2015. Included in 2016 activity was $50.4 million in proceeds from ourequity offering to fund the acquisition and early development of our Southern Delaware Basin acreage and approximately$61.1 million in net repayments of outstandings under our RBC Credit Facility (defined below). 2015 activity included netborrowings under our RBC Credit Facility to reduce the working capital obligations at December 31, 2015.Credit Facility In October 2013, the Company entered into a four-year $500 million revolving credit facility with Royal Bank ofCanada and other lenders (the “RBC Credit Facility”). In October 2016, the RBC Credit Facility was amended to,61 Table of Contentsamong other things, extend the maturity to October 1, 2019. The borrowing base under the facility is redetermined eachNovember and May. Effective November 6, 2017, the borrowing base under the RBC Credit Facility was redetermined at$115 million.The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration orpayment of dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of lessthan or equal to 3.50, both as defined in the RBC Credit Facility Agreement. Our compliance with these covenants is testedeach quarter. At December 31, 2017, we were in compliance with all but the Current Ratio covenant under the RBC CreditFacility, although we obtained a waiver for such non-compliance. The RBC Credit Facility also contains events of defaultthat may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are notlimited to, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. See Note 12 toour Financial Statements -“Long-Term Debt” for a more detailed description of terms and provisions of our credit agreement.Future Capital RequirementsOur future crude oil, natural gas and natural gas liquids reserves and production, and therefore our cash flow andresults of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves andeconomically finding or acquiring additional recoverable reserves. We intend to grow our reserves and production by furtherexploiting our existing property base through drilling opportunities in our resource plays and in our conventional onshoreinventory in West Texas and the Texas Gulf Coast, with activity in any particular area and period of time to be a function ofmarket and field economics. We anticipate that acquisitions, including those of undeveloped leasehold interests, willcontinue to play a role in our business strategy as those opportunities arise from time to time; however, there can be noassurance that we will be successful in consummating any acquisitions, or that any such acquisition entered into will besuccessful. These potential acquisitions are not part of our current capital budget and would require additional capital.Natural gas and oil prices continue to be volatile and our financial resources may be insufficient to fund any of theseopportunities. While there are currently no unannounced agreements for the acquisition of any material businesses or assets,such transactions can be effected quickly and could occur at any time.We believe that our internally generated cash flow and proceeds from the sale of non-core assets, combined withavailability under our RBC Credit Facility will be sufficient to meet the liquidity requirements necessary to fund our dailyoperations and planned capital development and to meet our debt service requirements for the next twelve months. Ourability to execute on our growth strategy will be determined, in large part, by our cash flow and the availability of debt andequity capital at that time. Any decision regarding a financing transaction, and our ability to complete such a transaction,will depend on prevailing market conditions and other factors.Our 2018 capital budget will be focused primarily on the Southern Delaware Basin, while at the same time: (i)preserving our financial position, including limiting capital expenditures to internally generated cash flow and proceedsfrom the sale of non-core assets; (ii) focusing drilling expenditures on strategic projects that provide good investment returnsin the current price environment; and (iii) identifying opportunities for cost efficiencies in all areas of our operations. Ourcurrent capital budget for 2018 should allow us to meet our contractual requirements, remain in position to preserve our termacreage where appropriate and maintain a healthy financial profile during this challenging period for our industry. We willcontinuously monitor the commodity price environment, and if warranted, make adjustments to our investment strategy asthe year progresses.Inflation and Changes in PricesWhile the general level of inflation affects certain costs associated with the energy industry, factors unique to theindustry result in independent price fluctuations. Such price changes have had, and will continue to have, a material effect onour operations; however, we cannot predict these fluctuations.Income TaxesDuring the year ended December 31, 2017, we paid approximately $0.6 million in state income taxes and no federalincome taxes. During the year ended December 31, 2016, we received a refund of approximately $2.1 million in federal andstate income taxes. During the year ended December 31, 2015 we received a refund of approximately $0.2 million in federaland state income taxes.62 Table of ContentsContractual ObligationsThe following table summarizes our known contractual obligations as of December 31, 2017: Payment due by period (thousands) Less than More than Total 1 year 1 - 3 years 3 - 5 years 5 years Long term debt and interest $93,118 $4,427 $88,691 $ — $ — Delay rentals 490 83 163 163 81 Asset retirement obligations 22,405 2,017 1,502 1,562 17,324 Employment agreements 2,476 1,559 917 — — Operating leases 3,705 3,070 635 — — Hardware/software 561 390 163 8 — Uncertain income tax positions 227 — 227 — — Total $122,982 $11,546 $92,298 $1,733 $17,405 (1)Estimated interest is based on the outstanding debt at December 31, 2017 using the interest rate in effect at that time.(2)Operating leases include contracts related to office space, compressors, vehicles, office equipment and other.In addition to the above, we have a throughput agreement with a third party pipeline owner/operator through March2020. See Note 13 to our Financial Statements – “Commitments and Contingencies” for further information.Application of Critical Accounting Policies and Management’s EstimatesThe discussion and analysis of the Company’s financial condition and results of operations is based upon theconsolidated financial statements, which have been prepared in accordance with accounting principles generally accepted inthe United States. The preparation of these consolidated financial statements requires the Company to make estimates andjudgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company’s significantaccounting policies are described in Note 2 of Notes to Consolidated Financial Statements included as part of this Form 10-K. We have identified below the policies that are of particular importance to the portrayal of our financial position andresults of operations and which require the application of significant judgment by management. The Company analyzes itsestimates, including those related to natural gas and oil reserve estimates, on a periodic basis and bases its estimates onhistorical experience, independent third party reservoir engineers and various other assumptions that management believesto be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions orconditions. The Company believes the following critical accounting policies affect its more significant judgments andestimates used in the preparation of the Company’s consolidated financial statements:Oil and Gas Properties - Successful EffortsOur application of the successful efforts method of accounting for our natural gas and oil exploration andproduction activities requires judgments as to whether particular wells are developmental or exploratory, since exploratorycosts and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereasdevelopmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and thedetermination that commercial reserves have been discovered requires both judgment and application of industry experience.Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficientto be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which havetargeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation ofcosts is required to properly account for the results. Delineation seismic costs incurred to select development locations withina productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismicprograms extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs toexpense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved propertiesrequires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an areaby other companies may also effectively condemn leasehold positions.63 (1)(2) Table of ContentsReserve EstimatesWhile we are reasonably certain of recovering our reported reserves, the Company’s estimates of natural gas and oilreserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in theinterpretation of such data as well as the projection of future rates of production and the timing of development expenditures.Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficultto measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geologicalinterpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flowsnecessarily depend upon a number of variable factors and assumptions, such as historical production from the area comparedwith production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptionsgoverning future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, allof which may in fact vary considerably from actual results. The future development costs associated with reserves assigned toproved undeveloped locations may ultimately increase to the extent that these reserves are later determined to beuneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oilattributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates ofthe future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect theestimated quantity and value of the reserves, which could affect the carrying value of the Company’s natural gas and oilproperties and/or the rate of depletion of such natural gas and oil properties.Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary fromestimates, and such variances may be material. Holding all other factors constant, a reduction in the Company’s provedreserve estimate at December 31, 2017 of 5%, 10% and 15% would affect depreciation, depletion and amortization expenseby approximately $0.6 million, $1.2 million and $1.9 million, respectively.Impairment of Natural Gas and Oil PropertiesThe Company reviews its proved natural gas and oil properties for impairment whenever events and circumstances,such as the current low commodity price environment, indicate a potential decline in the recoverability of their carryingvalue. An impairment loss associated with an asset group is the amount by which the carrying amount of a long-lived asset isnot recoverable and exceeds its fair value. An asset’s fair value is preferably indicated by a quoted market price in the asset’sprincipal market. Unlike many businesses where independent appraisals can be obtained for items such as equipment, oil andgas proved reserves are unique assets. Most oil and gas valuations are based on a combination of the income approach andmarket approach methodologies. We utilize the income approach also known as the discounted cash flow (“DCF”) approach.Under the DCF method in determining fair value, there are specific guidelines and ranges within the evaluation that we canconsider and estimate.The Company compares expected undiscounted future net cash flows from each field to the unamortized capitalizedcost of the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oilprices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost,then the capitalized cost is reduced to fair market value. The factors used to determine fair value include, but are not limitedto, estimates of reserves, future commodity pricing, future production estimates, and anticipated capital expenditures.Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any suchimpairment charged to expense in the period. Drilling activities in an area by other companies may also effectively impairleasehold positions. Given the complexities associated with natural gas and oil reserve estimates and the history of pricevolatility in the natural gas and oil markets, events may arise that will require the Company to record an impairment of itsnatural gas and oil properties and there can be no assurance that such impairments will not be required in the future nor thatthey will not be material. Assuming strip pricing as of March 1, 2018 through 2022 and keeping pricing flat thereafter,instead of 2017 SEC pricing, while leaving all other parameters unchanged, the Company’s proved reserves would have been188.6 Bcfe and the PV-10 value of proved reserves would have been $258.3 million.Derivative InstrumentsThe Company elected to not designate any of its derivative positions for hedge accounting At the end of eachreporting period we record on our balance sheet the mark-to-market valuation of our derivative instruments. The estimatedchange in fair value of the derivatives, along with the realized gain or loss for settled derivatives, is reported in Other Income(Expense) as Gain (loss) on derivatives, net.64 Table of ContentsIncome TaxesIncome taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxescurrently payable plus deferred income taxes related to certain income and expenses recognized in different periods forfinancial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates tothe differences between financial statements and income tax reporting. Numerous judgments and assumptions are inherent inthe determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. We aresubject to taxation in several jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in theapplication of complex tax laws and regulations in various taxing jurisdictions.Accounting for uncertainty in income taxes prescribes a recognition threshold and a measurement attribute for thefinancial statement recognition and measurement of income tax positions taken or expected to be taken in an income taxreturn. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained uponexamination by taxing authorities.In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portionor all of the deferred tax assets will not be realized. As of December 31, 2017, we had federal net operating loss (“NOL”)carryforwards of $284.4 million which occurred due to the Merger, and subsequent taxable losses in 2014, 2015, 2016 and2017 due to lower commodity prices and impairment of oil and gas property. Generally, these NOLs are available to reducefuture taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue CodeSection 382. Given the uncertainty of our ability to generate taxable income, a valuation allowance of $49.0 million hasbeen recorded for the year ended December 31, 2017 against the deferred tax assets, reduced by the amount of the deferredtax liability.Our federal and state income tax returns are generally not filed before the consolidated financial statements areprepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of taxrate changes, tax credits and net operating and capital loss carryforwards and carrybacks. Adjustments related to differencesbetween the estimates we used and actual amounts we reported are recorded in the period in which we file our income taxreturns. See Note 15 - "Income Taxes” to our consolidated financial statements.Recent Accounting Pronouncements In January 2017, the FASB issued ASU No. 2017-01: Business Combinations (Topic 805) Clarifying the Definitionof a Business (ASU 2017-01). The amendments in this update are intended to clarify the definition of a business with theobjective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions(or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions,disposals, goodwill, and consolidation. Public business entities should apply the amendments in this update to annualperiods beginning after December 15, 2017, including interim periods within those periods. The amendments in this updateshould be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of thisaccounting update are not expected to have a material impact on the Company’s financial position or results of operations.In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of CertainCash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cashreceipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of CashFlows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existingdiversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishmentcosts; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that areinsignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after abusiness combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity methodinvestees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of thepredominance principle. The amendments in this update are effective for public business entities for fiscal years beginningafter December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are notexpected to have a material impact on the Company’s presentation of cash flows.65 Table of ContentsIn February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective ofASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and leaseliabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference betweenprevious GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified asoperating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. Intransition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presentedusing a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued forfiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application ispermitted. The Company will continue to assess the impact this may have on its financial position, results of operations, andcash flows.In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” whichoutlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts withcustomers and supersedes most current revenue recognition guidance, including industry-specific guidance. This newrevenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new modelwill require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflectsthe consideration a company expects to receive in exchange for those goods or services. Several additional standards relatedto revenue recognition have been issued that amend the original standard, with most providing additional clarification.In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferralof the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. This new standard is now effective forannual reporting periods beginning after December 15, 2017, and the Company has completed the assessment of thisstandard. The impact on the Company’s financial statements is not material, and there is no material impact expected toopening retained earnings. The standard was adopted January 1, 2018 using the modified retrospective method. Certain itemsnetted in revenue or recorded as expense prior to adoption have changed based on the requirements of the new ASU using thecontrol model and the definitions of parties to the contract as principal or agent. The company implemented processes toensure new contracts are reviewed for the appropriate accounting treatment and additional disclosures will be required in ourForm 10-Q for the three months ended March 31, 2018.Off Balance Sheet ArrangementsWe may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. As ofDecember 31, 2017, the primary off-balance sheet arrangements that we have entered into included short-term drilling rigcontracts and operating lease agreements, all of which are customary in the oil and gas industry. Other than the off-balancesheet arrangements shown under operating leases and drilling rig in the commitments and contingencies table, we have noother arrangements that are reasonably likely to materially affect our liquidity or availability of or requirements for capitalresources.66 Table of Contents Item 7A. Quantitative and Qualitative Disclosure about Market RiskCommodity RiskWe are exposed to various risks including energy commodity price risk for our oil, natural gas and natural gasliquids production. When oil, natural gas and natural gas liquids prices decline significantly our ability to finance our capitalbudget and operations may be adversely impacted. Our major commodity price risk exposure is to the prices received for oil,natural gas and natural gas liquids produced and sold. Realized commodity prices received for our production are tied to thespot prices applicable to natural gas and crude oil at the applicable delivery points. Prices received for oil, natural gas andnatural gas liquids are volatile and unpredictable. For the year ended December 31, 2017, a 10% fluctuation in the pricesreceived for oil, natural gas and natural gas liquids production would have had an approximate $7.9 million impact on ourrevenues.Derivative Instruments and Hedging ActivityWe expect commodity prices to remain volatile and unpredictable, therefore we have designed a risk managementstrategy which provides for the use of derivative instruments to provide partial protection against declines in oil and naturalgas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivativeinstruments that we typically utilize include swaps and costless collars. The total volumes which we hedge through the use ofour derivative instruments varies from period to period. As of December 31, 2017, we had the following financial derivativecontracts in place: Commodity Period Derivative Volume/Month Price/UnitNatural Gas Jan 2018 - July 2018 Swap 370,000 MMBtus $3.07 Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $3.07 Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $3.07 Oil Jan 2018 - June 2018 Swap 20,000 Bbls $56.40 Oil July 2018 - Oct 2018 Collar 20,000 Bbls $52.00 - 56.85 Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $52.00 - 56.85 Oil Jan 2018 - Dec 2018 Collar 2,000 Bbls $52.00 - 58.76 Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $50.00 - 58.00 In January 2018, we entered into the following additional derivative contracts with members of our bank group: Commodity Period Derivative Volume/Month Price/UnitOil Jan 2018 - July 2018 Collar 6,000 Bbls $58.00 - 68.00 Oil Nov 2018 - Dec 2018 Collar 5,000 Bbls $58.00 - 68.00 Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $52.00 - 59.45 (1)Based on Henry Hub NYMEX natural gas prices.(2)Based on Arugs Louisiana Light Sweet crude oil prices.(3)Based on West Texas Intermediate crude oil prices.Our hedge strategy and objectives may change significantly as our operational profile changes and/or commoditiesprices change.We are exposed to market risk on our open derivative contracts related to potential non-performance by ourcounterparties. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties67 (1)(1)(1)(2)(2)(2)(3)(2)(2)(2)(3) Table of Contentsthat are creditworthy institutions deemed by management as competent and competitive market makers. The counterpartiesto the Company's current and previous derivative contracts are large financial institutions and also lenders or affiliates oflenders in our RBC Credit Facility. We do not post collateral under any of these contracts as they are secured under our RBCCredit Facility. See Note 6 to our Financial Statements - "Derivative Instruments" for additional information.We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”).ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either anasset or liability measured at fair value. The estimated fair values for financial instruments under ASC 825, FinancialInstruments (“ASC 825”) are determined at discrete points in time based on relevant market information. These estimatesinvolve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accountsreceivable and accounts payable approximates their carrying value due to their short-term nature. See Note 6 to our FinancialStatements - "Derivative Instruments" for more details.Interest Rate SensitivityWe are exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure resultsprimarily from fluctuations in short-term rates, which are LIBOR and the U.S. prime rate based and may result in reductions ofearnings or cash flows due to increases in the interest rates we pay on these obligations. We continue to monitor our riskexposure as we incur future indebtedness at variable interest rates and will look to continue our risk management policy assituations present themselves.As of December 31, 2017, our total long-term debt was $85.4 million, which bears interest at a floating or marketinterest rate that is tied to the prime rate or LIBOR. Fluctuations in market interest rates will cause our annual interest costs tofluctuate. During the year ended December 31, 2017 our effective rate fluctuated between 4.0 percent and 7.8 percent,depending on the term of the specific debt drawdowns. At December 31, 2017, we did not have any outstanding interest rateswap agreements. As of December 31, 2017, the weighted average interest rate on our variable rate debt was 5.2% per year.Assuming our current level of borrowings, a 100 basis point increase in the interest rates we pay under our RBC CreditFacility would result in an increase of our interest expense by $0.9 million for a twelve month period.Other Financial InstrumentsAs of December 31, 2017, we had no cash or cash equivalents. Investments in fixed-rate, interest-earning instrumentscarry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impactedbecause of changes in interest rates and credit ratings. Additionally, the value of our investments may be impairedtemporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses inprincipal. Currently, we do not use any derivative or other financial instruments to hedge any changes in interest rates orcredit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of thesecurities that we may invest in, we do not believe that we have any cash flow exposure arising from changes in creditratings. Based on a sensitivity analysis performed on the financial instruments held as of December 31, 2017, an immediate10% change in interest rates is not expected to have a material effect on our near-term financial condition or results ofoperations. Item 8. Financial Statements and Supplementary DataThe financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presentedon pages F-1 through F-36 of this Form 10-K. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureNone. Item 9A. Controls and ProceduresEvaluation of Disclosure Controls and ProceduresAn evaluation was performed under the supervision and with the participation of the Company’s senior managementof the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e)68 Table of Contentsunder the Securities Exchange Act of 1934 (the “Exchange Act”)) as of December 31, 2017, the end of the period covered bythis report. Based on that evaluation, the Company’s management, including the President and Chief Executive Officer andthe Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of such dateto ensure that information required to be disclosed in the reports that the Company files under the Exchange Act is(i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and(ii) accumulated and communicated to the Company’s management, including the President and Chief Executive Officer andthe Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.Changes in Internal Control Over Financial ReportingThere was no change in our internal controls over financial reporting during the fiscal quarter ended December 31,2017 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Management’s Report on Internal Control Over Financial ReportingThe Company’s management is responsible for establishing and maintaining adequate internal control overfinancial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participationof the Company’s management, including the President and Chief Executive Officer and Chief Financial Officer, theCompany conducted an evaluation of the effectiveness of its internal control over financial reporting based on the frameworkin 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the TreadwayCommission. Based on the Company’s evaluation under the framework in 2013 Internal Control-Integrated Framework, theCompany’s management concluded that its internal control over financial reporting was effective as of December 31, 2017.Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financialstatements included in this Form 10-K, has audited the effectiveness of our internal control over financial reporting as ofDecember 31, 2017, as stated in their report which is included herein.69 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMBoard of Directors and ShareholdersContango Oil & Gas Company Opinion on internal control over financial reportingWe have audited the internal control over financial reporting of Contango Oil & Gas Company (a Delaware corporation) andsubsidiaries (the “Company”) as of December 31, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In ouropinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December31, 2017, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)(“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and ourreport dated March 9, 2018 expressed an unqualified opinion on those financial statements. Basis for opinionThe Company’s management is responsible for maintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’sReport on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internalcontrol over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and arerequired to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and performthe audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained inall material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing therisk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control basedon the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe thatour audit provides a reasonable basis for our opinion. Definition and limitations of internal control over financial reportingA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. A company’s internal control over financial reporting includes those policies andprocedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect thetransactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded asnecessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and thatreceipts and expenditures of the company are being made only in accordance with authorizations of management anddirectors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorizedacquisition, 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 of effectiveness to future periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. / s / GRANT THORNTON LLPHouston, TexasMarch 9, 201870 Table of Contents Item 9B. Other InformationNone. PART III Item 10. Directors, Executive Officers and Corporate GovernanceThe information regarding directors, executive officers, promoters and control persons required under Item 10 ofForm 10-K will be contained in our Definitive Proxy Statement for our 2018 Annual Meeting of Stockholders (the “ProxyStatement”) under the headings “Proposal 1: Election of Directors”, “Executive Compensation”, “Section 16(a) BeneficialOwnership Reporting Compliance” and “Corporate Governance and our Board” and is incorporated herein by reference. TheProxy Statement will be filed with the SEC pursuant to Regulation 14A of the Exchange Act, not later than 120 days afterDecember 31, 2017. Item 11. Executive CompensationThe information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading“Executive Compensation” and is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder MattersThe information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading“Security Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions, and Director IndependenceThe information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the headings“Corporate Governance and our Board”, “Transactions with Related Persons” and “Executive Compensation” and isincorporated herein by reference. Item 14. Principal Accountant Fees and ServicesThe information required under Item 14 of Form 10-K will be contained in the Proxy Statement under thesubheading “Principal Accountant Fees and Services” and is incorporated herein by reference.71 Table of ContentsGLOSSARY OF SELECTED TERMSThe following is a description of the meanings of some of the oil and gas industry terms used in this report.2D seismic or 3D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions,respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-Dseismic.Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, in reference to crude oil or other liquid hydrocarbons.Bcf. Billion cubic feet of natural gas.Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,condensate or natural gas liquids.Boe. Barrel of oil equivalent per day determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,condensate or natural gas liquids.Boe/d. Boe per day.Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by onedegree Fahrenheit.Completion. The process of treating a drilled well followed by the installation of permanent equipment for theproduction of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable ofproduction.Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizonknown to be productive.Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds fromthe sale of such production exceed production expenses and taxes.Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to beproductive of natural gas or crude oil in another reservoir.Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the sameindividual geological structural feature and/or stratigraphic condition.Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.Mcf. Thousand cubic feet of natural gas.Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,condensate or natural gas liquids.MMBbls. million barrels of crude oil or other liquid hydrocarbons.MMBtu. million British Thermal Units. One MMBtu equates to approximately one Mcf.MMcf. million cubic feet of natural gas.72 Table of ContentsMMcfe. million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil,condensate or natural gas liquids.MMcfe/d. Mmcfe per day.Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the casemay be.Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluidsfrom one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such thatproceeds from the sale of the production exceed production expenses and taxes.Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and alsopreliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery ofcommercial hydrocarbons.Proved developed producing reserves. Proved developed oil and gas reserves are reserves that can be expected tobe recovered through existing wells with existing equipment and operating methods.Proved developed reserves. Has the meaning given to such term in Rule 4-10(a)(6) of Regulation S-X, whichdefines proved developed reserves as reserves that can be expected to be recovered through existing wells with existingequipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost ofa new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate ifthe extraction is by means not involving a well.Proved reserves. Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which defines provedreserves as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering datademonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existingeconomic conditions, operating methods and government regulations. Existing economic conditions include prices andcosts at which economic producibility from a reservoir is to be determined. The prices include consideration of changes inexisting prices provided only by contractual arrangements, but not on escalations based upon future conditions.The area of a reservoir considered proved includes (A) the area identified by drilling and limited by fluid contacts, ifany, and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous withit and to contain economically producible oil and gas on the basis of available geological and engineering data. In theabsence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in awell penetration unless geological, engineering or performance data and reliable technology establishes a lower contact withreasonable certainty.Reserves which can be produced economically through application of improved recovery techniques (including,but not limited to, fluid injection) are included in the proved classification when successful testing by a pilot project, theoperation of an installed program in the reservoir or other evidence using reliable technology establishes the reasonablecertainty of the engineering analysis on which the project or program was based; and the project has been approved fordevelopment by all necessary parties and entities, including governmental entities.Proved undeveloped reserves. Has the meaning given to such term in Rule 4-10(a)(31) of Regulation S-X, whichdefines proved undeveloped reserves as reserves that are expected to be recovered from new wells on undrilled acreage, orfrom existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall belimited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unlessevidence using reliable technology exists that establishes reasonable certainty of economic producibility at greaterdistances. 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.Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which anapplication of fluid injection or other improved recovery technique is73 Table of Contentscontemplated, unless such techniques have been proved effective by actual projects in the same reservoir, or by otherevidence using reliable technology establishing reasonable certainty.PV-10. A non-GAAP financial measure that represents the present value, discounted at 10% per year, of estimatedfuture cash inflows from proved natural gas and crude oil reserves, less future development and production costs usingpricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure of Discounted Net CashFlows because it does not include the effects of income taxes or non-property related expenses such as general andadministrative expenses and debt service or depreciation, depletion and amortization on future net revenues. Neither PV-10nor Standardized Measure of Discounted Net Cash Flows represents an estimate of fair market value of natural gas and crudeoil properties. PV-10 is used by the industry as an arbitrary reserve asset value measure to compare against past reserve basesand the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.Reservoir. A porous and permeable underground formation containing a natural accumulation of producible naturalgas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that wouldpermit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains provedreserves.Working interest. The operating interest that gives the owner the right to drill, produce and conduct operatingactivities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling andproduction operations.74 Table of Contents PART IV Item 15. Exhibits and Financial Statement Schedules (a) Financial Statements and Schedules:The financial statements are set forth in pages F-1 to F-29 of this Form 10-K. Financial statement schedules havebeen omitted since they are either not required, not applicable, or the information is otherwise included.(b) Exhibits:The following is a list of exhibits filed as part of this Form 10-K. Where so indicated by a footnote, exhibits, whichwere previously filed, are incorporated herein by reference. ExhibitNumber Description 2.1 Agreement and Plan of Merger, among Contango Oil & Gas Company, Contango Acquisition, Inc. and CrimsonExploration Inc., dated as of April 29, 2013 (filed as Exhibit 2.1 to the Company’s report on Form 8-K, dated asof April 29, 2013, as filed with the Securities and Exchange Commission on May 1, 2013, and incorporated byreference herein). 3.1 Certificate of Incorporation of Contango Oil & Gas Company (filed as Exhibit 3.1 to the Company’s report onForm 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15,2000, and incorporated by reference herein). 3.2 Third Amended and Restated Bylaws of Contango Oil & Gas Company (filed as Exhibit 3.2 to the Company’sAnnual Report on Form 10-K for the year ended December 31, 2015, as filed with the Securities and ExchangeCommission on March 3, 2015, and incorporated by reference herein). 3.3 Amendment to the Certificate of Incorporation of Contango Oil & Gas Company (filed as Exhibit 3.4 to theCompany’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filedwith the Securities and Exchange Commission, and incorporated by reference herein ). 4.1 Facsimile of common stock certificate of Contango Oil & Gas Company (filed as Exhibit 3.1 to the Company’sForm 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16,1998, and incorporated by reference herein). 4.2 Registration Rights Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, OCMCrimson Holdings, LLC and OCM GW Holdings, LLC (filed as Exhibit 10.9 to the Company’s report on Form 8-K, dated as of April 29, 2013, as filed with the Securities and Exchange Commission on May 1, 2013, andincorporated by reference herein). 10.1*Amended and Restated 2005 Stock Incentive Plan (filed as Exhibit 10.2 to the Company’s Current Report onForm 8-K dated as of October 1, 2013, as filed with the Securities and Exchange Commission on October 2,2013, and incorporated by reference herein). 10.2*Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan (filed as an exhibit tothe Company’s Schedule 14A on Definitive Proxy Statement for 2014, as filed with the Securities and ExchangeCommission on April 11, 2014, and incorporated by reference herein). 10.3 First Amended and Restated Limited Liability Company Agreement dated as of March 31, 2012 (filed as Exhibit10.1 to the Company’s report on Form 8-K, dated as of March 31, 2012, as filed with the Securities andExchange Commission on April 5, 2012, and incorporated by reference herein). 10.4 Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, dated as of October 9,2008 between Contango Offshore Exploration LLC and Contango Operators, Inc. (filed as Exhibit 10.48 to theCompany’s report on Form 10-K for the fiscal year ended June 30, 2012, as filed with the Securities andExchange Commission on August 29, 2012, and incorporated by reference herein). 10.5 Amendment to Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, datedas of October 7, 2009 between Contango Offshore Exploration LLC and Contango Operators, Inc. (filed asExhibit 10.49 to the Company’s report on Form 10-K for the fiscal year ended June 30, 2012, as filed with theSecurities and Exchange Commission on August 29, 2012, and incorporated by reference herein). 75 Table of Contents ExhibitNumber Description 10.6 Amendment to Participation Agreement covering OCS-G 27927, Ship Shoal Block 263, South Addition, datedas of January 29, 2010 between Contango Offshore Exploration LLC and Contango Operators, Inc. (filed asExhibit 10.50 to the Company’s report on Form 10-K for the fiscal year ended June 30, 2012, as filed with theSecurities and Exchange Commission on August 29, 2012, and incorporated by reference herein). 10.7 Participation Agreement covering OCS-G 33596, Vermilion 170, dated as of July 1, 2010 between RepublicExploration LLC and Contango Operators, Inc. (filed as Exhibit 10.51 to the Company’s report on Form 10-Kfor the fiscal year ended June 30, 2012, as filed with the Securities and Exchange Commission on August 29,2012, and incorporated by reference herein). 10.8 Participation Agreement covering Tuscaloosa Marine Shale, dated as of August 27, 2012 between JuneauExploration LP and Contango Operators, Inc. (filed as Exhibit 10.56 to the Company’s report on Form 10-K forthe fiscal year ended June 30, 2012, as filed with the Securities and Exchange Commission on August 29, 2012,and incorporated by reference herein). 10.9 Letter Agreement dated as of June 8, 2012 between Juneau Exploration LP and Contango Operators, Inc. (filedas Exhibit 10.57 to the Company’s report on Form 10-K for the fiscal year ended June 30, 2012, as filed with theSecurities and Exchange Commission on August 29, 2012, and incorporated by reference herein). 10.10 Agreement to Purchase Overriding Royalty Interest, dated March 1, 2010 between Contango OffshoreExploration LLC and Juneau Exploration LP (filed as Exhibit 10.60 to the Company’s report on Form 10-K forthe fiscal year ended June 30, 2012, as filed with the Securities and Exchange Commission on August 29, 2012,and incorporated by reference herein). 10.11*Amended and Restated Employment Agreement, dated as of November 30, 2016, among Contango Oil & GasCompany and Allan D. Keel (filed as Exhibit 10.11 to the Company’s report on Form 10-K for the fiscal yearended December 31, 2016, as filed with the Securities and Exchange Commission on March 15, 2017, andincorporated by reference herein). 10.12*Amended and Restated Employment Agreement, dated as of November 30, 2016, among Contango Oil & GasCompany and E. Joseph Grady (filed as Exhibit 10.12 to the Company’s report on Form 10-K for the fiscal yearended December 31, 2016, as filed with the Securities and Exchange Commission on March 15, 2017, andincorporated by reference herein). 10.13*Amendment and Extension of Employment Agreement, dated as of October 10, 2016, among Contango Oil &Gas Company and A. Carl Isaac (filed as Exhibit 10.3 to the Company’s report on Form 8-K dated as of October10, 2016, as filed with the Securities and Exchange Commission on October 14, 2016, and incorporated byreference herein). 10.14*Amended and Restated Employment Agreement, dated as of November 30, 2016, among Contango Oil & GasCompany and Jay S. Mengle (filed as Exhibit 10.17 to the Company’s report on Form 10-K for the fiscal yearended December 31, 2016, as filed with the Securities and Exchange Commission on March 15, 2017, andincorporated by reference herein). 10.15*Amended and Restated Employment Agreement, dated as of November 30, 2016, among Contango Oil & GasCompany and Thomas H. Atkins (filed as Exhibit 10.18 to the Company’s report on Form 10-K for the fiscalyear ended December 31, 2016, as filed with the Securities and Exchange Commission on March 15, 2017, andincorporated by reference herein). 10.16 Participation Agreement covering Timbalier Island Prospect, South Timbalier Area Block 17, S.L. 21906, datedApril 3, 2013 between Republic Exploration LLC, Juneau Exploration, L.P. and Contango Operators, Inc. (filedas Exhibit 10.81 to the Company’s report on Form 10-K for the fiscal year ended June 30, 2013, as filed with theSecurities and Exchange Commission on August 29, 2013, and incorporated by reference herein). 10.17 Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank of Canada, as AdministrativeAgent, and the Lenders Signatory Hereto dated October 1, 2013 (filed as Exhibit 10.1 to the Company’s CurrentReport on Form 8-K dated as of October 1, 2013, as filed with the Securities and Exchange Commission onOctober 2, 2013, and incorporated by reference herein). 76 Table of Contents ExhibitNumber Description 10.18 First Amendment to Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank ofCanada, as Administrative Agent, and the Lenders Signatory Hereto (filed as Exhibit 10.1 to the Company’sreport on Form 8-K dated as of April 11, 2014, as filed with the Securities and Exchange Commission on April15, 2014, and incorporated by reference herein). 10.19 Second Amendment to Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank ofCanada, as Administrative Agent, and the Lenders Signatory Hereto (filed as Exhibit 10.1 to the Company’sreport on Form 8-K dated as of October 28, 2014, as filed with the Securities and Exchange Commission onOctober 31, 2014, and incorporated by reference herein). 10.20 Third Amendment to Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank ofCanada, as Administrative Agent, and the Lenders Signatory Hereto (filed as Exhibit 10.1 to the Company’sreport on Form 10-Q for the quarter ended March 31, 2016, as filed with the Securities and ExchangeCommission on May 9, 2016, and incorporated by reference herein). 10.21 Fourth Amendment to Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank ofCanada, as Administrative Agent, and the Lenders Signatory Hereto. † 10.22*Contango Oil & Gas Company Director Compensation Plan (filed as Exhibit 10.4 to the Company’s report onForm 10-Q for the quarter ended March 21, 2017, as filed with the Securities and Exchange Commission on May10, 2017, and incorporated by reference herein). 10.23 Liquidation Agreement between Juneau Exploration LP, Contango Operators, Inc. and Fairfield IndustriesIncorporated, dated December 31, 2016 (filed as Exhibit 10.27 to the Company’s report on Form 10-K for thefiscal year ended December 31, 2016, as filed with the Securities and Exchange Commission on March 15, 2017,and incorporated by reference herein). 10.24*Employment Agreement, dated as of February 26, 2017, among Contango Oil & Gas Company and James J.Metcalf Jr. (filed as Exhibit 10.28 to the Company’s report on Form 10-K for the fiscal year ended December 31,2016, as filed with the Securities and Exchange Commission on March 15, 2017, and incorporated by referenceherein). 10.25*Form of Contango Oil and Gas Company Stock Award Agreement (employees) (filed as Exhibit 10.7 to theCompany’s report on Form 10-Q for the quarter ended September 30, 2016, as filed with the Securities andExchange Commission on November 3, 2016, and incorporated by reference herein). 10.26*Form of Contango Oil and Gas Company Stock Award Agreement (executives) (filed as Exhibit 10.8 to theCompany’s report on Form 10-Q for the quarter ended September 30, 2016, as filed with the Securities andExchange Commission on November 3, 2016, and incorporated by reference herein). 21.1 List of Subsidiaries. † 21.2 Organizational Chart. † 23.1 Consent of William M. Cobb & Associates, Inc. † 23.2 Consent of Netherland, Sewell & Associates, Inc. † 23.3 Consent of W.D. Von Gonten & Co. † 23.4 Consent of Grant Thornton LLP. † 24.1 Powers of Attorney (included on signature page). † 31.1 Certification of Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Actof 1934. † 31.2 Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Actof 1934. † 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of theSarbanes-Oxley Act of 2002. † 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of theSarbanes-Oxley Act of 2002. † 99.1 Report of William M. Cobb & Associates, Inc. † 99.2 Report of Netherland, Sewell & Associates. † 99.3 Report of W.D. Von Gonten and Company. † 77 Table of Contents * Indicates a management contract or compensatory plan or arrangement† Filed herewith 78 Table of Contents SIGNATURESIn accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signedon its behalf by the undersigned, thereunto duly authorized.CONTANGO OIL & GAS COMPANYBy:/s/ ALLAN D. KEEL Date: March 9, 2018 Allan D. Keel Chief Executive Officer POWER OF ATTORNEYKnow all men by these presents, that the undersigned constitutes and appoints Allan D. Keel as his true and lawfulattorneys-in-fact and agent, with full power of substitution for him and in his name, place and stead, in any and all capacitiesto sign any and all amendments or supplements to this Annual Report on Form 10-K, and to file the same, and with allexhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting untosaid attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite andnecessary to be done as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirmingall that said attorney-in-fact and agent or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of theregistrant and in the capacities and on the dates indicated.Signature Title Date /s/ ALLAN D. KEEL Chief Executive Officer (principal executive officer) March 9, 2018 Allan D. Keel and Director /s/ E. JOSEPH GRADY Chief Financial Officer (principal financial officer) March 9, 2018 E. Joseph Grady /s/ DENISE DUBARD Chief Accounting Officer (principal accounting officer) March 9, 2018 Denise DuBard /s/ JOSEPH J. ROMANO Director March 9, 2018 Joseph J. Romano /s/ B. A. BERILGEN Director March 9, 2018 B. A. Berilgen /s/ B. JAMES FORD Director March 9, 2018 B. James Ford /s/ ELLIS L. MCCAIN Director March 9, 2018 Ellis L. McCain /s/ CHARLES M. REIMER Director March 9, 2018 Charles M. Reimer 79 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESINDEX TO CONSOLIDATED FINANCIAL STATEMENTS PageReport of Independent Registered Public Accounting Firm F-2Consolidated Balance Sheets F-3Consolidated Statements of Operations F-4Consolidated Statements of Cash Flows F-5Consolidated Statement of Shareholders’ Equity F-6Notes to Consolidated Financial Statements F-7Supplemental Oil and Gas Disclosures (Unaudited) F-30Quarterly Results of Operations (Unaudited) F-36 F-1 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and ShareholdersContango Oil & Gas Company Opinion on the financial statementsWe have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Delaware corporation)and subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations, cashflows, and shareholders’ equity for each of the three years in the period ended December 31, 2017, and the related notes(collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all materialrespects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and itscash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principlesgenerally 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)(“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria establishedin the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the TreadwayCommission (“COSO”), and our report dated March 9, 2018 expressed an unqualified opinion. Basis for opinionThese financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinionon the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB andare required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and performthe audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether dueto error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financialstatements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures includedexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits alsoincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluating theoverall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. / s / GRANT THORNTON LLPWe have served as the Company’s auditor since 2002.Houston, TexasMarch 9, 2018F-2 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands, except shares) December 31, December 31, 2017 2016 CURRENT ASSETS: Cash and cash equivalents $ — $ — Accounts receivable, net 13,059 16,727 Prepaid expenses 1,892 1,787 Current derivative asset 822 — Inventory — 540 Total current assets 15,773 19,054 PROPERTY, PLANT AND EQUIPMENT: Natural gas and oil properties, successful efforts method of accounting: Proved properties 1,239,662 1,188,065 Unproved properties 35,243 38,338 Other property and equipment 1,272 1,265 Accumulated depreciation, depletion and amortization (930,220) (887,286) Total property, plant and equipment, net 345,957 340,382 OTHER NON-CURRENT ASSETS: Investments in affiliates 18,464 15,767 Deferred tax asset 424 — Other 835 1,311 Total other non-current assets 19,723 17,078 TOTAL ASSETS $381,453 $376,514 CURRENT LIABILITIES: Accounts payable and accrued liabilities $46,755 $55,135 Current derivative liability 1,765 3,446 Current asset retirement obligations 2,017 4,308 Total current liabilities 50,537 62,889 NON-CURRENT LIABILITIES: Long-term debt 85,380 54,354 Long-term derivative liability 300 — Asset retirement obligations 20,388 22,618 Other long term liabilities 248 248 Total non-current liabilities 106,316 77,220 Total liabilities 156,853 140,109 COMMITMENTS AND CONTINGENCIES (NOTE 13) SHAREHOLDERS’ EQUITY: Common stock, $0.04 par value, 50 million shares authorized, 30,873,470 sharesissued and 25,505,715 shares outstanding at December 31, 2017, 30,557,987shares issued and 25,238,600 shares outstanding at December 31, 2016 1,223 1,211 Additional paid-in capital 302,527 296,439 Treasury shares at cost (5,367,755 shares at December 31, 2017 and 5,319,387shares at December 31, 2016) (128,583) (128,321) Retained earnings 49,433 67,076 Total shareholders’ equity 224,600 236,405 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $381,453 $376,514 The accompanying notes are an integral part of these consolidated financial statements.F-3 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per share amounts) Year Ended December 31, 2017 2016 2015 REVENUES: Oil and condensate sales $25,347 $23,006 $43,230 Natural gas sales 41,317 43,847 59,058 Natural gas liquids sales 11,881 11,330 14,217 Total revenues 78,545 78,183 116,505 EXPENSES: Operating expenses 27,183 29,111 37,840 Exploration expenses 1,106 1,816 11,979 Depreciation, depletion and amortization 47,215 63,323 133,380 Impairment and abandonment of oil and gas properties 2,395 10,572 285,877 General and administrative expenses 24,161 26,802 26,402 Total expenses 102,060 131,624 495,478 OTHER INCOME (EXPENSE): Gain (loss) from investment in affiliates (net of income taxes) 2,697 1,545 (30,582) Interest expense (4,100) (3,802) (3,164) Gain (loss) on derivatives, net 3,325 (1,632) 2,348 Other income (expense) 3,555 (357) 97 Total other income (expense) 5,477 (4,246) (31,301) NET LOSS BEFORE INCOME TAXES (18,038) (57,687) (410,274) Income tax benefit (provision) 395 (342) 75,226 NET LOSS ATTRIBUTABLE TO COMMON STOCK $(17,643) $(58,029) $(335,048) NET LOSS PER SHARE: Basic $(0.71) $(2.71) $(17.67) Diluted $(0.71) $(2.71) $(17.67) WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: Basic 24,686 21,424 18,965 Diluted 24,686 21,424 18,965 The accompanying notes are an integral part of these consolidated financial statements. F-4 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year Ended December 31, 2017 2016 2015 CASH FLOWS FROM OPERATING ACTIVITIES: Net loss (17,643) (58,029) (335,048) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 47,215 63,323 133,380 Impairment of natural gas and oil properties 1,785 10,438 285,870 Exploration expenses (recovery) (232) (1) 6,494 Deferred income taxes (424) — (92,329) Loss (gain) on sale of assets (2,321) 92 231 Loss (gain) from investment in affiliates (2,697) (1,545) 47,049 Stock-based compensation 6,100 6,457 6,516 Unrealized loss (gain) on derivative instruments (2,204) 3,446 — Changes in operating assets and liabilities: Decrease in accounts receivable & other 3,914 1,006 4,261 Decrease (increase) in prepaid expenses (105) (560) 714 Increase (decrease) in accounts payable & advances from joint owners 450 2,116 (28,672) Increase (decrease) in other accrued liabilities 1,353 2,436 (5,711) Decrease (increase) in income taxes receivable, net (332) 2,777 405 Increase (decrease) in income taxes payable, net (252) (187) 481 Other 79 242 1,314 Net cash provided by operating activities $34,686 $32,011 $24,955 CASH FLOWS FROM INVESTING ACTIVITIES: Natural gas and oil exploration and development expenditures $(66,613) $(24,929) $(77,820) Sale of oil and gas properties 1,151 5,120 — Sale of furniture and equipment 12 11 — Return of investment in affiliates — — 1,014 Net cash used in investing activities $(65,450) $(19,798) $(76,806) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings under credit facility $239,514 $148,881 $356,102 Repayments under credit facility (208,488) (209,972) (304,016) Net proceeds from equity offering — 50,435 — Purchase of treasury stock (262) (561) (235) Debt issuance costs — (996) — Net cash provided by (used in) financing activities $30,764 $(12,213) $51,851 NET DECREASE IN CASH AND CASH EQUIVALENTS $ — $ — $ — CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD — — — CASH AND CASH EQUIVALENTS, END OF PERIOD $ — $ — $ — The accompanying notes are an integral part of these consolidated financial statements. F-5 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY(in thousands, expect share amounts) Additional Total Common Stock Paid-in Treasury Retained Shareholders’ Shares Amount Capital Stock Earnings Equity Balance at December 31, 2014 19,148,000 $963 $233,278 $(127,525) $460,750 $567,466 Treasury shares at cost (31,252) — — (235) — (235) Restricted shares activity 264,398 11 (10) — — 1 Stock-based compensation — — 6,256 — — 6,256 Dissolution of REX — — — — (597) (597) Net loss — — — — (335,048) (335,048) Balance at December 31, 2015 19,381,146 $974 $239,524 $(127,760) $125,105 $237,843 Equity Offering 5,360,000 214 50,221 — — 50,435 Treasury shares at cost (63,597) — — (561) — (561) Restricted shares activity 561,051 23 (22) — — 1 Stock-based compensation — — 6,716 — — 6,716 Net loss — — — — (58,029) (58,029) Balance at December 31, 2016 25,238,600 $1,211 $296,439 $(128,321) $67,076 $236,405 Treasury shares at cost (48,368) — — (262) — (262) Restricted shares activity 315,483 12 (12) — — — Stock-based compensation — — 6,100 — — 6,100 Net loss — — — — (17,643) (17,643) Balance at December 31, 2017 25,505,715 $1,223 $302,527 $(128,583) $49,433 $224,600 The accompanying notes are an integral part of these consolidated financial statements. F-6 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS1. Organization and BusinessContango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston,Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flowfrom its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in Texas andWyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and naturalgas properties in onshore West Texas, the Texas Gulf Coast and the Rocky Mountain regions of the United States.On October 1, 2013, the Company completed a merger with Crimson Exploration Inc. ("Crimson") (the “Merger”).The Company historically focused operations in the GOM, but the Merger has given the Company access to high rate ofreturn onshore prospects in known, prolific producing areas as well as long-life resource plays. Beginning in the second halfof 2015, the Company reduced its drilling program in response to the challenging commodity price environment, and insteadfocused on: (i) the preservation of its strong and flexible financial position, including limiting its overall capital expenditurebudget to internally generated cash flow; (ii) the identification of opportunities for cost and production efficiencies in allareas of its operations; and (iii) maintaining core leases and continuing to identify new resource potential opportunitiesinternally and, where appropriate, through acquisition. As a result, until the latter half of 2016, the Company’s only drillingactivity was in Weston County, Wyoming, where it completed its third well targeting the Muddy Sandstone formation.During the third quarter of 2016, the Company acquired acreage in the Southern Delaware Basin in Pecos County, Texas (the“Acquisition”), and as of December 31, 2017, had increased its acreage in the Southern Delaware Basin to 16,500 gross acres(6,800 net). Since the Acquisition, the Company has begun production from seven wells in the Southern Delaware Basin andis waiting on completion of an eighth well. The Company currently expects that the Southern Delaware Basin position willcontinue to be the primary focus of its drilling program for 2018. Additionally, the Company has (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarilyfocused on the development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producingfrom various conventional formations in various counties along the Texas Gulf Coast; and (iii) operated producing propertiesin the Haynesville Shale, Mid Bossier and James Lime formations in East Texas. On December 30, 2016, the Companycompleted the sale of all of its Colorado assets, primarily located in the Adams and Weld counties. 2. Summary of Significant Accounting PoliciesBasis of PresentationThe Company’s consolidated financial statements have been prepared in accordance with accounting principlesgenerally accepted in the United States of America and include the accounts of Contango Oil & Gas Company and itssubsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries areconsolidated. Oil and gas exploration and development affiliates which are not controlled by the Company, such as RepublicExploration LLC (“REX”), are proportionately consolidated. REX was dissolved as of December 31, 2015. Other InvestmentsThe Company has two seats on the board of directors of Exaro and has significant influence, but not control, overthe company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equitymethod, the Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while anet loss or payment of dividends decreases its investment. In the consolidated statement of operations, the Company’sproportionate share of Exaro's net income or loss is reported as a single line-item in Gain (loss) from investment in affiliates(net of income taxes).Use of EstimatesThe preparation of financial statements in conformity with accounting principles generally accepted in the UnitedStates of America requires management to make estimates and assumptions that affect the reported amounts of assets andliabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amountsof revenues and expenses during the reporting periods. The most significant estimates include oil andF-7 Table of Contentsgas revenues, income taxes, stock-based compensation, reserve estimates, impairment of natural gas and oil properties,valuation of derivatives and accrued liabilities. Actual results could differ from those estimates.Revenue RecognitionRevenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties.Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’sentitled share, production imbalance occurs. If production imbalance exceeds the Company’s share of the remainingestimated proved natural gas reserves for a given property, the Company records a liability. As of December 31, 2017, 2016and 2015, the Company had no significant imbalances.Cash EquivalentsCash equivalents are considered to be highly liquid investment grade debt investments having an original maturityof 90 days or less. As of December 31, 2017, the Company had no cash and cash equivalents, as cash balances at the end ofeach day are transferred to reduce outstanding debt under the Company’s revolving credit facility to minimize debt servicecosts. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequentlyresult in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balancesheets. At December 31, 2017, accounts payable included $2.3 million in outstanding checks that had not been presented forpayment. At December 31, 2016, accounts payable included $3.5 million in outstanding checks that had not been presentedfor payment.Accounts ReceivableThe Company sells natural gas and crude oil to a limited number of customers. In addition, the Companyparticipates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accountsreceivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells forwhich the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offsetfuture revenues against unpaid charges related to operated wells.The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. TheCompany periodically reviews the accounts receivable from customers for any collectability issues. An allowance fordoubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economicconditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance.Accounts receivable allowance for bad debt was $0.8 and $0.7 million as of December 31, 2017 and 2016,respectively. At December 31, 2017 and 2016, the carrying value of the Company’s accounts receivable approximated fairvalue.Oil and Gas Properties - Successful EffortsThe Company follows the successful efforts method of accounting for its natural gas and oil activities. Under thesuccessful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs arecapitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed.Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred.Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, withlease acquisition costs amortized over total proved reserves and other capitalized costs amortized over proved developedreserves.Depreciation, depletion and amortization ("DD&A") of capitalized drilling and development costs of producingnatural gas and crude oil properties, including related support equipment and facilities net of salvage value, are computedusing the unit of production method on a field basis based on total estimated proved developed natural gas and crude oilreserves. Amortization of producing leaseholds is based on the unit of production method using total estimated provedreserves. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion, and amortization areeliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revisedwhenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes inaccounting estimates.F-8 Table of ContentsOther property and equipment are depreciated using the straight-line method over their estimated useful lives whichrange between three and 13 years.Impairment of Oil and Gas PropertiesWhen circumstances indicate that proved properties may be impaired, the Company compares expectedundiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimatedfuture undiscounted cash flows, based on the Company’s estimate of future reserves, natural gas and oil prices, operatingcosts and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then thecapitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimatesof proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and adiscount rate commensurate with the risk reflective of the lives remaining for the respective oil and gasproperties. Additionally, the Company may use appropriate market data to determine fair value. For the year ended December31, 2017, the Company recorded an impairment expense of approximately $0.3 million related to proved properties. For theyear ended December 31, 2016, the Company recorded an impairment expense of approximately $0.7 million related toproved properties. For the year ended December 31, 2015, the Company recorded an impairment expense of approximately$269.6 million related to proved properties. Approximately $235.8 million of this amount was attributable to theMadison/Grimes counties and Zavala/Dimmit/Karnes counties properties.Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, andany such impairment is charged to expense in the period. During the year ended December 31, 2017, the Companyrecognized impairment expense of approximately $1.5 million related to the partial impairment of two unused offshoreplatforms in onshore storage. During the year ended December 31, 2016, the Company recognized impairment expense ofapproximately $6.8 million related to unproved properties in Fayette and Gonzales counties, Texas and $2.9 million relatedto unproved acreage in Natrona County, Wyoming. During the year ended December 31, 2015, the Company recognizedimpairment expense of approximately $16.3 million related to impairment and partial impairment of certain unprovedproperties and onshore prospects due primarily to the sustained low commodity price environment and expiring leases.Approximately $9.3 million of this amount related to unproved lease cost amortization of properties in Fayette and Gonzalescounties, Texas.Asset Retirement ObligationsASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an assetretirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset andsubsequently allocated to expense using a systematic and rational method. The Company records an asset retirementobligation (“ARO”) to reflect the Company's legal obligation related to future plugging and abandonment of its oil andnatural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flowsassociated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, theCompany reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Companyevaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materiallychanged. Should these indicators suggest the estimated obligation may have materially changed on an interim basis(quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liabilityassociated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations areincurred. The liability is accreted to its present value each period and the capitalized cost is depleted over the useful life ofthe related asset. The accretion expense is included in depreciation, depletion and amortization expense.The estimated liability is based on historical experience in plugging and abandoning wells. The estimatedremaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability isdiscounted using an assumed credit-adjusted risk-free rate.Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes inthe risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging andabandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to theextent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment andabandonment of oil and gas properties expense. See Note 11 - "Asset Retirement Obligation" for additional information.F-9 Table of ContentsIncome TaxesThe Company follows the liability method of accounting for income taxes under which deferred tax assets andliabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets andliabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for taxpurposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is morelikely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its taxpositions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31,2017. The amount of unrecognized tax benefits did not materially change from December 31, 2016. The amount ofunrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to havea significant impact on its financial position or results of operations. The Company includes interest and penalties in interestincome and general and administrative expenses, respectively, in its statement of operations.The Company files income tax returns in the United States and various state jurisdictions. The Company’s federaltax returns for 1998 – 2016, and state tax returns for 2010 – 2016, remain open for examination by the taxing authorities inthe respective jurisdictions where those returns were filed.Concentration of Credit RiskSubstantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billingsto a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interestowners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economicand other conditions. See Note 3 - "Concentration of Credit Risk" for additional information.Debt Issuance CostsDebt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. Duringthe year ended December 31, 2013, the Company initially incurred $2.2 million of debt issuance costs relating to the newRBC credit facility entered into in conjunction with the Merger with Crimson. The debt issuance costs were to be amortizedover the original four year term of the credit line. In connection with RBC Credit Facility amendment in May 2016, theCompany incurred an additional $1.0 million of debt issuance costs. As of December 31, 2017, the remaining balance ofthese debt issuance costs was $0.8 million, which will be amortized through October 1, 2019, with amortization expenseincluded in the DD&A line item in the Company's income statement for the years ended December 31, 2017, 2016 and 2015.Stock-Based CompensationThe Company applies the fair value based method to account for stock based compensation. Under this method,compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisiteservice period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductionsin excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value ofeach restricted stock award is estimated as of the date of grant. The fair value of the Performance Stock Units is estimated asof the date of grant using the Monte Carlo simulation pricing model.Inventory Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Inventory isrecorded at the lower of cost or market using specific identification method.Derivative Instruments and Hedging ActivitiesThe Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet aseither an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil andnatural gas production. Derivative contracts entered into by the Company have consisted of transactions in which theCompany hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. TheCompany elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in themark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts arerecognized in "Gain (loss) on derivatives, net" on the consolidated statements ofF-10 Table of Contentsoperations for the years ended December 31, 2017, 2016 and 2015. Derivative instruments with settlement dates within oneyear are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year areincluded in non-current assets or liabilities. The Company calculates a net asset or liability for current and non-currentderivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 -"Derivative Instruments" for additional information.Subsidiary GuaranteesContango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement onForm S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time totime. Crimson Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc.,Contango Mining Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango VentureCapital Corporation, Contango Rocky Mountain Inc. and any other of the Company’s future subsidiaries specified in theprospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registrationstatement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. TheSubsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by theSubsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of theSubsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distributefunds to the Parent Company. The Parent Company has one other wholly-owned subsidiary that is inactive. Finally, theParent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recentfiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by suchsubsidiary without the consent of a third party.Recent Accounting PronouncementsIn January 2017, the FASB issued ASU No. 2017-01: Business Combinations (Topic 805) Clarifying the Definitionof a Business (ASU 2017-01). The amendments in this update are intended to clarify the definition of a business with theobjective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions(or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions,disposals, goodwill, and consolidation. Public business entities should apply the amendments in this update to annualperiods beginning after December 15, 2017, including interim periods within those periods. The amendments in this updateshould be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of thisaccounting update are not expected to have a material impact on the Company’s financial position or results of operations.In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of CertainCash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cashreceipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of CashFlows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existingdiversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishmentcosts; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that areinsignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after abusiness combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity methodinvestees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of thepredominance principle. The amendments in this update are effective for public business entities for fiscal years beginningafter December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are notexpected to have a material impact on the Company’s presentation of cash flows.In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016‑02). The main objective ofASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and leaseliabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference betweenprevious GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified asoperating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. Intransition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presentedusing a modified retrospective approach. For public entities, ASU 2016-02 is effective forF-11 Table of Contentsfinancial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscalyears; early application is permitted. The Company will continue to assess the impact this may have on its financial position,results of operations, and cash flows.In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” whichoutlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts withcustomers and supersedes most current revenue recognition guidance, including industry-specific guidance. This newrevenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new modelwill require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflectsthe consideration a company expects to receive in exchange for those goods or services. Several additional standards relatedto revenue recognition have been issued that amend the original standard, with most providing additional clarification.In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferralof the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. This new standard is now effective forannual reporting periods beginning after December 15, 2017, and the Company has completed the assessment of thisstandard. The impact on the Company’s financial statements is not material, and there is no material impact expected toopening retained earnings. The standard was adopted January 1, 2018 using the modified retrospective method. Certain itemsnetted in revenue or recorded as expense prior to adoption have changed based on the requirements of the new ASU using thecontrol model and the definitions of parties to the contract as principal or agent. The company implemented processes toensure new contracts are reviewed for the appropriate accounting treatment and additional disclosures will be required in ourForm 10-Q for the three months ended March 31, 2018. 3. Concentration of Credit RiskThe customer base for the Company is concentrated in the natural gas and oil industry. The largest purchaser of theCompany’s production for the year ended December 31, 2017 was ConocoPhillips Company (51.2%). The Company’s salesto this company is not secured with letters of credit and in the event of non-payment, the Company could lose up to twomonths of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financialposition. There are numerous other potential purchasers of the Company’s production. 4. Acquisitions, Dispositions and Gains from AffiliatesSouthern Delaware Basin AcquisitionIn July 2016, the Company purchased one-half of the seller’s interest in approximately 12,100 gross undevelopedacres (approximately 5,000 net acres) in the Southern Delaware Basin of Texas (the “Acquisition”) for up to $25 million. Thepurchase price was comprised of $10 million in cash paid on July 26, 2016, plus $10 million to be paid in the form of carriedwell costs expected to be paid over the period of drilling and completing the first six wells. Additionally, contingent uponsuccess, $5 million in spud bonuses is to be paid by the Company ratably over the following 14 wells drilled, which wouldincrease the total consideration paid by the Company to $25 million. As of December 31, 2017, the Company had paid all$10 million of the carried well costs and $1.1 million in spud bonuses. As of December 31, 2017, the Company has increasedits acreage to approximately 16,500 gross operated acres (6,800 net).Colorado Property SaleOn December 30, 2016, all of the Company’s non-core Colorado assets were sold to an independent oil and gascompany for an aggregate purchase price of $5.0 million, subject to normal post-closing adjustments. The propertiesconsisted of the Company’s approximately 16,000 gross (11,200 net) acres primarily in Adams and Weld counties, Coloradoand associated producing vertical wells.North Bob West Property Sale Effective February 1, 2017, the Company sold to a third party all of its assets in the North Bob West area and itsoperated assets in the Escobas area, both located in Southeast Texas, for a cash purchase price of $650,000. The Companyrecorded a net gain of $2.9 million after removal of the asset retirement obligations associated with the sold properties. F-12 Table of Contents5. Fair Value MeasurementsPursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fairvalue incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting inreceivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on itsown liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability inan orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair valuehierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highestpriority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority tounobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly orindirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that marketparticipants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputsto the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. TheCompany classifies fair value balances based on the observability of those inputs.As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level ofinput that is significant to the fair value measurement. The Company's assessment of the significance of a particular input tothe fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and theirplacement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3.Derivatives are recorded at fair value at the end of each reporting period. The Company records the net change in thefair value of these positions in "Gain (loss) on derivatives, net" in the Company's consolidated statements of operations. TheCompany is able to value the assets and liabilities based on observable market data for similar instruments, which resulted inthe Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity pricesbased on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 6 -"Derivative Instruments" for additional discussion of derivatives.During the year ended December 31, 2017, the Company's derivative contracts were with major financialinstitutions with investment grade credit ratings which were believed to have a minimal credit risk. As such, the Companywas exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above;however, the Company did not anticipate any nonperformance. The counterparties to the Company's current and previousderivative contracts are lenders in the Company's RBC Credit Facility. The Company did not post collateral under any ofthese contracts as they were secured under the RBC Credit Facility.Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825,Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevantmarket information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair valueof cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. Theestimated fair value of the Company's RBC Credit Facility approximates carrying value because the interest rateapproximates current market rates and are re-set at least every three months. See Note 12 - "Long-Term Debt" for furtherinformation.Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis include oil andgas properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If theunamortized cost of properties exceeds the undiscounted cash flows related to the properties, the value of the properties iscompared to the fair value estimated as discounted cash flows related to the risk-adjusted proved, probable and possiblereserves related to the properties. Fair value measurements based on these inputs are classified as Level 3.ImpairmentsContango tests proved oil and gas properties for impairment when events and circumstances indicate a decline inthe recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lowercommodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gasproperties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties.If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost isreduced to its fair value. The factors used to determine fair value include, but are not limited to,F-13 Table of Contentsestimates of proved and probable reserves, future commodity prices, the timing of future production and capital expendituresand a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gasproperties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fairvalue inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure.Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, withany such impairment charged to expense in the period.Asset Retirement Obligations The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based oninternal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair valueinclude, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves.As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities asLevel 3 at inception. 6. Derivative InstrumentsThe Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk.Derivative contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in theCompany's cash flows associated with anticipated sales of future oil and natural gas production. The Company typicallyhedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Companybelieves that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and toreduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in theprices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to aportion of its production, the Company’s strategy provides only partial protection against declines in commodity prices.Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuouslyreevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts.As of December 31, 2017, the Company’s natural gas and oil derivative positions consisted of “swaps” and “costlesscollars”. Swaps are designed so that the Company receives or makes payments based on a differential between fixed andvariable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price theCompany will receive for the volumes under contract, and a purchased put, which establishes a minimum price. A sold putoption limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit theeffectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of theput option sold.It is the Company's practice to enter into derivative contracts only with counterparties that are creditworthyinstitutions deemed by management as competent and competitive market makers. The counterparties to the Company'scurrent and previous derivative contracts are lenders or affiliates of lenders in the RBC Credit Facility. The Company doesnot post collateral under any of these contracts as they are secured under the RBC Credit Facility.The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly,derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fairvalue included in the consolidated statements of operations for the period in which the change occurs. The Company recordsthe net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settledderivative contracts, in "Gain (loss) on derivatives, net" on the consolidated statements of operations. See Note 5 – “FairValue Measurements” for additional information.F-14 Table of ContentsThe Company had the following financial derivative contracts in place as of December 31, 2017:Commodity Period Derivative Volume/Month Price/Unit Natural Gas Jan 2018 - July 2018 Swap 370,000 MMBtus $3.07 Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $3.07 Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $3.07 Oil Jan 2018 - June 2018 Swap 20,000 Bbls $56.40 Oil July 2018 - Oct 2018 Collar 20,000 Bbls $52.00 - 56.85 Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $52.00 - 56.85 Oil Jan 2018 - Dec 2018 Collar 2,000 Bbls $52.00 - 58.76 Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $50.00 - 58.00 Additionally, in January 2018, the Company entered into the following additional derivative contracts withmembers of its bank group:Commodity Period Derivative Volume/Month Price/UnitOil Jan 2018 - July 2018 Collar 6,000 Bbls $58.00 - 68.00 Oil Nov 2018 - Dec 2018 Collar 5,000 Bbls $58.00 - 68.00 Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $52.00 - 59.45 (1)Based on Henry Hub NYMEX natural gas prices.(2)Based on Argus Louisiana Light Sweet crude oil prices.(3)Based on West Texas Intermediate crude oil prices. The Company had the following financial derivative contracts in place as of December 31, 2016:Commodity Period Derivative Volume/Month Price/Unit Natural Gas Jan 2017 - July 2017 Collar 400,000 MMBtus $2.65 - 3.00 Natural Gas Aug 2017 - Oct 2017 Collar 200,000 MMBtus $2.65 - 3.00 Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtus $2.65 - 3.00 Natural Gas Jan 2017 - July 2017 Swap 300,000 MMBtus $3.51 Natural Gas Aug 2017 - Oct 2017 Swap 70,000 MMBtus $3.51 Natural Gas Nov 2017 - Dec 2017 Swap 300,000 MMBtus $3.51 Oil Jan 2017 - July 2017 Swap 9,000 Bbls $53.95 Oil Aug 2017 - Oct 2017 Swap 6,000 Bbls $53.95 Oil Nov 2017 - Dec 2017 Swap 8,000 Bbls $53.95 Oil Jan 2017 - Dec 2017 Swap 9,000 Bbls $56.20 (1)Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable.There were no derivative contracts in place as of December 31, 2015.F-15 (1) (1) (1) (2) (2) (2) (3) (2)(2)(2)(3)(1) Table of ContentsThe following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as ofDecember 31, 2017 (in thousands). Gross Netting TotalAssets $1,188 $(1,188) $ —Liabilities $(2,431) $1,188 $(1,243)(1)Represents counterparty netting under agreements governing such derivatives.The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as ofDecember 31, 2016 (in thousands): Gross Netting TotalAssets $ — $ — $ —Liabilities $(3,446) $ — $(3,446)(1)Represents counterparty netting under agreements governing such derivatives.The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations forthe years ended December 31, 2017, 2016 and 2015 (in thousands): Year Ended December 31, Contract Type 2017 2016 2015 Crude oil contracts $861 $1,814 $2,348 Natural gas contracts 260 — — Realized gain $1,121 $1,814 $2,348 Crude oil contracts $(2,065) $ — $ — Natural gas contracts 4,269 (3,446) — Unrealized gain (loss) $2,204 $(3,446) $ — Gain (loss) on derivatives, net $3,325 $(1,632) $2,348 7. Stock Based CompensationAs of December 31, 2017, the Company had in place the Contango Oil & Gas Company Amended and Restated2009 Incentive Compensation Plan (“the 2009 Plan”) which allows for stock options, restricted stock or performance stockunits to be awarded to officers, directors and employees as a performance-based award.Amended and Restated 2009 Incentive Compensation PlanOn April 10, 2014, the Company’s board of directors (the “Board”) amended and restated the Company’s thenexisting incentive compensation plan through the adoption of the 2009 Plan. The 2009 Plan provides for both cash awardsand equity awards to officers, directors, employees or consultants of the Company. Awards made under the 2009 Plan aresubject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.Under the terms of the 2009 Plan, shares of the Company’s common stock may be issued for plan awards. Stockoptions under the 2009 Plan must have an exercise price of each option equal to or greater than the market price of theCompany’s common stock on the date of grant. The Company may grant officers and employees both incentive stockoptions intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options thatF-16 (1)(1) Table of Contentsare not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, canonly be stock options that are not qualified as incentive stock options. Options granted generally expire after five or tenyears. The vesting schedule for all equity awards varies from immediately to over a four-year period. As of December 31,2017, the Company had approximately 1.6 million shares of equity awards available for future grant under the 2009 Plan,assuming Performance Stock Units are settled at 100% of target.Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009Plan for the benefit of all employees through a Cash Incentive Bonus Plan (“CIBP”) and a Long-Term Incentive Plan(“LTIP”). The specific targeted performance measures under these sub-plans are approved by the Compensation Committeeand/or the Board. Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP willbe calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each yearare expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at thetime that awards are disbursed to be eligible.The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock and/or stockoptions. The number of shares of restricted common stock and the number of shares underlying the stock options granted willbe determined based upon the fair market value of the common stock on the date of the grant.2005 Stock Incentive PlanThe 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. This planexpired on February 25, 2015, and therefore, no additional shares are available for grant.Stock OptionsDuring the years ended December 31, 2017, 2016 and 2015, the Company did not issue any stock options.A summary of stock options as of and for the years ended December 31, 2017, 2016 and 2015 is presented in thetable below (dollars in thousands, except per share data): Year Ended December 31, 2017 2016 2015 Weighted Weighted Weighted Shares Average Shares Average Shares Average Under Exercise Under Exercise Under Exercise Options Price Options Price Options Price Outstanding, beginning of the period 111,905 $55.53 116,461 $55.03 129,934 $53.85 Exercised — $ — — $ — — $ — Expired / Forfeited (17,072) $43.50 (4,556) $42.92 (13,473) $43.65 Outstanding, end of year 94,833 $57.69 111,905 $55.53 116,461 $55.03 Aggregate intrinsic value $ — $ — $ — Exercisable, end of year 94,833 $57.69 111,905 $55.53 116,461 $55.03 Aggregate intrinsic value $ — $ — $ — Available for grant, end of the period 2,002,492 323,172 885,449 Weighted average fair value of optionsgranted during the period $ — $ — $ — * Excludes Performance Stock Units.Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resultingfrom tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cashflows. For the years ended December 31, 2017, 2016 and 2015, there was no excess tax benefit recognized. See Note 2 –"Summary of Significant Accounting Policies".Compensation expense related to employee stock option grants are recognized over the stock option’s vestingperiod based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date ofgrant using the Black-Scholes options-pricing model.F-17 * Table of ContentsDuring the years ended December 31, 2017, 2016 and 2015, the Company did not recognize any stock optionexpense. The aggregate intrinsic value of stock options exercised/forfeited during each of the years ended December 31,2017, 2016 and 2015 was zero.Restricted StockDuring the year ended December 31, 2017, the Company issued 383,376 restricted stock awards to new and existingemployees, which vest over three years, plus an additional 74,325 restricted stock awards to the members of the board ofdirectors which vest on the one-year anniversary of the date of grant. During the year ended December 31, 2017, 142,218restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares grantedduring the year was $7.55, with a total grant date fair value of approximately $3.5 million after adjustment for estimatedweighted average forfeiture rate of 4.8%.During the year ended December 31, 2016, the Company issued 489,805 restricted stock awards to new and existingemployees, which vest over three or four years, an additional 49,460 restricted stock awards to the members of the board ofdirectors which vest on the one-year anniversary of the date of grant, plus an additional 40,876 immediately vested shares toemployees and board members as a result of temporarily deferring 10% of 2015 employee salaries and director fees (the“Salary Replacement Program”). During the year ended December 31, 2016, 19,090 restricted stock awards were forfeited byformer employees. The weighted average fair value of the restricted shares granted during the year was $10.99, with a totalgrant date fair value of approximately $6.4 million after adjustment for estimated weighted average forfeiture rate of 4.2%.During the year ended December 31, 2015, the Company issued 249,917 restricted stock awards to new and existingemployees, which vest over four years, plus an additional 27,204 restricted stock awards to the members of the board ofdirectors which vest on the one-year anniversary of the date of grant. During the year ended December 31, 2015, 12,723restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares grantedduring the year was $21.83, with a total grant date fair value of approximately $6.1 million after adjustment for estimatedweighted average forfeiture rate of 4.9%.Restricted stock activity as of December 31, 2017, 2016 and 2015 and for the years then ended is presented in thetable below (dollars in thousands, except per share data): 2017 2016 2015 Weighted Aggregate Weighted Aggregate Weighted Aggregate Restricted Average Intrinsic Restricted Average Intrinsic Restricted Average Intrinsic Shares Fair Value Value Shares Fair Value Value Shares Fair Value Value Outstanding, beginning of theperiod 638,158 $14.22 $5,960 337,165 $28.16 $2,161 209,962 $43.86 $6,139 Granted 457,701 7.55 3,457 580,141 10.99 6,375 277,121 21.83 6,049 Vested (222,568) 15.12 1,263 (260,058) 24.51 2,422 (137,195) 39.35 1,169 Canceled / Forfeited (142,218) 10.23 814 (19,090) 22.03 202 (12,723) 32.97 154 Not vested, end of the period 731,073 10.55 1,667 638,158 14.22 5,960 337,165 28.16 2,161 Vested, end of the period — — — — — — — — — Expected to vest, end of the period 690,016 10.58 1,574 590,511 14.28 5,515 312,986 28.17 2,006 The Company recognized approximately $6.1 million, $6.5 million and $6.5 million in stock compensationexpense during the years ended December 31, 2017, 2016 and 2015, respectively, for restricted shares granted to its officers,employees and directors. An additional $5.6 million of compensation expense will be recognized over the remaining vestingperiod.Performance Stock Units During the year ended December 31, 2017, the Company granted 30,000 Performance Stock Units (“PSUs”) to a newemployee, at a weighted average fair value of $8.32 per unit and 160,908 PSUs to executive officers, as part of their overallcompensation package, at a value of $13.91 per unit. All prices were determined using the Monte Carlo simulation model.During the year ended December 31, 2017, 99,363 PSUs were forfeited by former employees. During the year ended December 31, 2016, the Company granted 285,800 PSUs to all employees as part of its LTIP,at a fair value of $16.32 per unit, and an additional 6,699 PSUs to new employees, at a fair value of $13.06 per unit using theMonte Carlo simulation model. During the year ended December 31, 2016, 1,300 PSUs were forfeited by former employees. F-18 Table of ContentsPSUs represent a contractual right to receive shares of the Company's common stock. The settlement of PSUs mayrange from 0% to 300% of the targeted number of PSUs stated in the agreement contingent upon the achievement of certainshare price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a threeyear period.Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determinedusing the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomesgiven a variety of inputs. As the Compensation Committee intends to settle the PSUs with shares of the Company's commonstock after three years, the PSU awards are accounted for as equity awards and the fair value is calculated on the grant date.The simulation model calculates the payout percentage based on the stock price performance over the performance period.The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair valueexpense is amortized over the life of the PSU award. 8. Share Repurchase ProgramIn September 2011, the Company’s board of directors approved a $50 million share repurchase program. All sharesare to be purchased in the open market or through privately negotiated transactions. Purchases are made subject to marketconditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, andwhen the Company believes its stock price to be undervalued. Repurchased shares of common stock became authorized butunissued shares, and may be issued in the future for general corporate and other purposes. No shares were purchased duringthe years ended December 31, 2017, 2016 and 2015. As of December 31, 2017, the Company had $31.8 million availableunder the share repurchase program for future purchases.In October 2014, the Company amended its revolving credit facility with Royal Bank of Canada to, among otherthings, allow for share repurchases subject to certain conditions. The Company is currently in compliance with theseconditions.9. Other Financial InformationThe following table provides additional detail for accounts receivable, prepaids, and accounts payable and accruedliabilities which are presented on the consolidated balance sheets (in thousands): December 31, December 31, 2017 2016 Accounts receivable: Trade receivables $6,565 $8,424 Receivable for Alta Resources distribution 1,993 1,993 Joint interest billings 4,030 3,519 Income taxes receivable 424 91 Other receivables 828 3,395 Allowance for doubtful accounts (781) (695) Total accounts receivable $13,059 $16,727 Prepaid expenses and other: Prepaid insurance $1,177 $1,086 Other 715 701 Total prepaid expenses and other $1,892 $1,787 Accounts payable and accrued liabilities: Royalties and revenue payable $18,181 $16,920 Advances from partners 2,243 5,792 Accrued exploration and development 8,400 11,176 Accrued carried well costs — 7,155 Trade payables 9,559 5,406 Accrued general and administrative expenses 2,960 5,016 Accrued operating expenses 1,654 1,867 Other accounts payable and accrued liabilities 3,758 1,803 Total accounts payable and accrued liabilities $46,755 $55,135 F-19 Table of ContentsIncluded in the table below is supplemental cash flow disclosures and non-cash investing activities during the yearsended December 31, 2017, 2016 and 2015, in thousands: Year Ended December 31, 2017 2016 2015 Cash payments: Interest payments $3,699 $3,806 $3,147 Income tax payments (refunds), net of cash refunds 616 (2,089) (180) Non-cash items excluded from investing activities in the consolidated statements ofcash flows: Increase (decrease) in accrued capital expenditures (9,931) 14,672 (22,879) 10. Investment in Exaro Energy III LLCThrough the Company’s wholly-owned subsidiary, Contaro Company (“Contaro”), the Company committed toinvest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all theExaro investors was approximately $183 million. The Company did not make any contributions during the year endedDecember 31, 2017 and has no plans to invest additional funds in Exaro, as the commitment to invest in Exaro expired onMarch 31, 2017. As of December 31, 2017, the Company had invested approximately $46.9 million. The following table presents condensed balance sheet data for Exaro as of December 31, 2017 and December 31,2016. The balance sheet data was derived from the Exaro balance sheet as of December 31, 2017 and December 31, 2016 andwas not adjusted to represent Contango’s percentage of ownership interest in Exaro. Contango’s share in the equity of Exaroat December 31, 2017 was approximately $18.4 million. December 31, December 31, 2017 2016 (in thousands) Current assets $17,063 $25,296 Non-current assets: Net property and equipment 82,450 90,621 Gas processing deposit 1,150 1,150 Other non-current assets 390 8 Total non-current assets 83,990 91,779 Total assets $101,053 $117,075 Current liabilities $6,199 $65,694 Non-current liabilities: Long-term debt 40,375 — Other non-current liabilities 3,858 8,106 Total non-current liabilities 44,233 8,106 Members' equity 50,621 43,275 Total liabilities & members' equity $101,053 $117,075 (1)Approximately $12.8 million and $19.6 million of current assets as of December 31, 2017 and December 31, 2016, respectively, is cash. (2)Approximately $59.3 million of current liabilities as of December 31, 2016, was attributable to Exaro’s senior loan facility maturing in2017, which has since been refinanced. F-20 (1)(2) Table of ContentsThe following table presents the condensed results of operations for Exaro for the years ended December 31, 2017,2016 and 2015. The results of operations for the years ended December 31, 2017, 2016 and 2015 were derived from Exaro'sfinancial statements for the respective periods. The income statement data below was not adjusted to represent Contango’sownership interest but rather reflects the results of Exaro as a Company. The Company's share in Exaro's results of operationsrecognized for the years ended December 31, 2017, 2016 and 2015 was a gain of $2.7 million, net of no tax expense; a gainof $1.5 million, net of no tax expense; and a loss of $30.6 million, net of tax benefit of $16.5 million, respectively. Year Ended December 31, 2017 2016 2015 ($ in thousands) Production: Oil (MBbls) 101 127 166 Gas (MMcf) 9,019 10,626 13,059 Total (Mmcfe) 9,625 11,388 14,055 Oil and natural gas sales $32,281 $30,028 $40,474 Other gain (loss) 5,368 (3,889) 6,358 Less: Lease operating expenses 15,479 15,846 20,922 Depreciation, depletion, amortization & accretion 9,857 10,644 29,417 Impairment expense — — 118,000 General & administrative expense 2,920 3,123 3,255 Income (loss) from continuing operations 9,393 (3,474) (124,762) Net other income (expense) (2,189) 7,900 (2,910) Net income (loss) $7,204 $4,426 $(127,672) Included in Other gain (loss) are realized and unrealized gain (losses) attributable to derivatives, whose value islikely to change based on future oil and gas prices. Exaro's results of operations do not include income taxes, because Exarois treated as a partnership for tax purposes. 11. Asset Retirement ObligationThe Company accounts for its retirement obligation of long lived assets by recording the net present value of aliability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initiallyrecorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to itspresent value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement ofthe liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.Activities related to the Company’s ARO during the year ended December 31, 2017 and 2016 were as follows (inthousands): Year Ended December 31, 2017 2016 Balance as of the beginning of the period $26,926 $27,109 Liabilities incurred during period 308 69 Liabilities settled during period (4,503) (707) Accretion 1,056 1,187 Sales (2,949) (851) Change in estimate 1,567 119 Balance as of the end of the period $22,405 $26,926 All of the total liabilities incurred during the years ended December 31, 2017 and 2016 were related to new wellsdrilled during the period. All of the total liabilities settled during the years ended December 31, 2017 and 2016 were relatedto wells plugged and abandoned during the period. F-21 Table of Contents12. Long-Term DebtRBC Credit FacilityIn October 2013, the Company entered into a $500 million revolving credit facility with Royal Bank of Canada andother lenders (the “RBC Credit Facility”), which matures on October 1, 2019. The borrowing base under the facility isredetermined each November 1 and May 1. Effective November 6, 2017, the borrowing base under the RBC Credit Facilitywas redetermined at $115 million.Effective May 6, 2016, the RBC Credit Facility was amended to, among other things, extend the maturity of thefacility from October 1, 2017 to October 1, 2019, increase the LIBOR, U.S. prime rate and federal funds rate margins to 2.5% -4.0% and increase the commitment fee to 0.5%, regardless of the amount of the credit facility that is unused.Initially, the Company incurred $2.2 million of arrangement and upfront fees in connection with the RBC CreditFacility which was to be amortized over the original four-year term of the facility. In May 2016, in connection with theamendment, the Company incurred an additional $1.0 million of arrangement and upfront fees. As of December 31, 2017, theremaining balance of these fees was $0.8 million, which will be amortized through October 1, 2019.As of December 31, 2017, the Company had $85.4 million outstanding under the RBC Credit Facility, whichmatures on October 1, 2019, and $1.9 million in outstanding letters of credit. As of December 31, 2016, the Company had$54.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December31, 2017, borrowing availability under the RBC Credit Facility was $27.7 million.The RBC Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and itssubsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gasproperties.Borrowings under the RBC Credit Facility bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plusa 2.5% to 4.0% margin, dependent upon the amount outstanding. Additionally, the Company must pay a 0.5% commitmentfee regardless of the amount of the credit facility that is unused. Total interest expense under the RBC Credit Facility,including commitment fees, for the years ended December 31, 2017, 2016 and 2015 was approximately $4.1 million, $3.8million and $3.2 million, respectively.The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration orpayment of dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of lessthan or equal to 3.50, both as defined in the RBC Credit Facility Agreement. As of December 31, 2017, the Company was incompliance with all but the Current Ratio covenant under the RBC Credit Facility, although the Company obtained awaiver for such non-compliance. The RBC Credit Facility also contains events of default that may accelerate repayment ofany borrowings and/or termination of the facility. Events of default include, but are not limited to, payment defaults, breachof certain covenants, bankruptcy, insolvency or change of control events. 13. Commitments and ContingenciesContango pays delay rentals on its leases and leases its office space and certain other equipment. The Company’scorporate offices are located at 717 Texas Avenue in downtown Houston, Texas, under a lease that expires March 31, 2019.As of December 31, 2017, minimum future lease payments for delay rentals and operating leases for Contango’sfiscal years are as follows (in thousands):Fiscal years ending December 31, 2018 $3,542 2019 849 2020 112 2021 89 2022 82 2023 and thereafter 81 Total $4,755 F-22 Table of ContentsThe amounts incurred under operating leases and delay rentals during the years ended December 31, 2017, 2016,and 2015 were approximately $4.8 million, $5.4 million and $6.3 million, respectively. Throughput Contract Commitment The Company signed a throughput agreement with a third party pipeline owner/operator that constructed a naturalgas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building thepipeline itself. The Company currently forecasts that monthly gas volume deliveries through this line in its Southeast Texasarea will not meet minimum throughput requirements under the agreement. Without further development in that area, thevolume deficiency will continue through the expiration of the throughput commitment in March 2020. The throughputdeficiency fee is paid in April of each calendar year. As of December 31, 2017, the Company estimates that the net deficiencyfee will be approximately $1.0 million annually for the remaining contract period, based upon forecasted productionvolumes from existing proved producing reserves only, assuming no future development during this commitment period. Asof December 31, 2017, based upon the current commodity price market and the Company’s short term strategic drilling plans,the Company has recorded a $1.8 million loss contingency through December 31, 2018. The Company will continue toassess this commitment in light of its drilling and development plans for this area.Legal ProceedingsFrom time to time, the Company is involved in legal proceedings relating to claims associated with its properties,operations or business or arising from disputes with vendors in the normal course of business, including the material mattersdiscussed below.In July 2010, several parties associated with a limited partnership, formed to invest in oil and gas properties, andthat was dissolved in 1995, filed suit against a subsidiary of the Company and several co-defendants in district court forMadison County in Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in MadisonCounty, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution,which were distributed to the partners in connection with such dissolution. A predecessor of the subsidiary of the Companyinvolved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partnerof the aforementioned partnership in 2000. The case went to trial in December 2017. As the Court did not allow virtually allof the plaintiff’s claims, a nominal settlement agreement was executed to settle all claims. In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers werenamed in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interestin two wells that has not been recognized by the Company or by predecessor operators to which the Company had grantedindemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorlydocumented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favorof the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decisionto the applicable state Court of Appeals. In the fourth quarter of 2017 the Court of Appeals issued its opinion and affirmedthe trial court’s summary decision. The Company continues to vigorously defend this lawsuit and has filed a motion forrehearing with the Court of Appeals, and if denied, will petition the Texas Supreme Court. In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for HarrisCounty in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operatedby the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred tothe district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claimingownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it ownsan additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (thisclaimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has maderoyalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to thegrantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiffpreviously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additionalhydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiaryand the successors to the grantors under the aforementioned deeds. The plaintiff appealed the trial court’s decision to theapplicable state Court of Appeals. On December 14, 2017, the Court of AppealsF-23 Table of Contentsaffirmed the judgement in the Company’s favor. The plaintiff has filed a motion for rehearing. The Company continues tovigorously defend this lawsuit and believes that it has meritorious defenses. The Company believes if this matter were to bedetermined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights the Company may haveagainst other working interest and/or royalty interest owners in the unit.While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing toestimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of theliability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on itsconsolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. TheCompany maintains various insurance policies that may provide coverage when certain types of legal proceedings aredetermined adversely.Employment AgreementsOn November 30, 2016, all of the Company’s existing employment agreements were terminated, and the Companyand Mr. Keel, Mr. Grady, Mr. Mengle and Mr. Atkins entered into Amended and Restated Employment Agreements(“Employment Agreements”). The Employment Agreements provide for an initial term of three years for Messrs. Keel andGrady and an initial term of two years for Messrs. Mengle and Atkins. Each of the Employment Agreements willautomatically renew for additional one year terms, unless Contango or the executive provides prior notice of intention not toextend the agreement.Under the Employment Agreements, Mr. Keel is entitled to a base salary of $600,000, Mr. Grady is entitled to a basesalary of $400,000, Mr. Mengle is entitled to a base salary of $300,000 and Mr. Atkins is entitled to a base salary of$310,000. The Employment Agreements provide that each executive shall participate in the Company’s CIBP and LTIP.With respect to the CIBP, the Employment Agreements provide that the executives are eligible to receive an annual cashincentive bonus with a target award level of 100% for Messrs. Keel and Grady and 80% for Messrs. Mengle and Atkins, ofsuch executive’s base salary, under such terms and conditions as the Company may determine each applicable year. Withrespect to the LTIP, the Employment Agreements provide that the executives are eligible to participate in the Company’sequity compensation plan for each calendar year in which the executive is employed by the Company, under such terms andconditions as the Company may determine in each applicable year. F-24 Table of Contents14. Net Loss Per Common ShareA reconciliation of the components of basic and diluted net loss per common share for the years ended December 31,2017, 2016 and 2015 is presented below (in thousands): Year Ended December 31, 2017 Net Loss Shares PerShare Basic Earnings per Share: Net loss attributable to common stock $(17,643) 24,686 $(0.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $(17,643) 24,686 $(0.71) Year Ended December 31, 2016 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $(58,029) 21,424 $(2.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $(58,029) 21,424 $(2.71) Year Ended December 31, 2015 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $(335,048) 18,965 $(17.67) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options and restricted stock) — — — Net loss attributable to common stock $(335,048) 18,965 $(17.67) The numerator for basic earnings per share is net loss attributable to common stockholders. The numerator fordiluted earnings per share is net loss available to common stockholders.Potential dilutive securities (stock options, restricted stock and PSUs) have not been considered when their effectwould be antidilutive. The potentially dilutive shares would have been 1,282,590 shares for the year ended December 31,2017, 1,282,957 shares for the year ended December 31, 2016 and 453,626 shares for the year ended December 31, 2015. 15. Income Taxes The Tax Cuts and Jobs Act 2017 On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred toas the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. The Company hascompleted the accounting for the effects of the Act during 2017. Our financial statements for the year ended December 31,2017 reflect certain effects of the Act which includes a reduction in the corporate tax rate from 35% to 21% effective January1, 2018, as well as other changes. Due to the Company’s valuation allowance position and as a result of changes to tax lawsand rates under the Act, the Company recorded a net tax benefit due primarily to the remeasurement of deferred tax assets andliabilities from 35% to 21% and the removal of the valuation allowance on the estimated refundable Alternative MinimumTax (“AMT”) credits. The valuation allowance decreased by $35.7 million in 2017 due to the changes to tax laws and ratesunder the Act and increased by $7.2 million for normal operations. The staff of the US Securities and Exchange Commission has recognized the complexity of reflecting the impacts ofthe Act, and on December 22, 2017 issued guidance in Staff Accounting Bulletin 118 (“SAB 118”) which clarifiesaccounting for income taxes under ASC 740 if information is not yet available or complete and provides for upF-25 Table of Contentsto a one year period to complete the required analyses and accounting (the measurement period). SAB 118 describes threescenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with itsaccounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of taxreform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate andtherefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the Actbeing enacted. The Company has completed the accounting for the effects of the Act.Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutorycorporate rate of 35 percent to pretax income as follows (dollars in thousands): Year Ended December 31, 2017 2016 2015 Provision/(benefit) at statutorytax rate $(6,314) 35.00% $(20,190) 35.00% $(148,925) 35.00%State income tax provision, net offederal benefit (864) 4.79% (774) 1.34% (116) 0.03%Permanent differences 50 (0.28)% 67 (0.12)% 30 (0.01)%Stock based compensation (361) 2.00% 1,599 (2.77)% — —%Valuation allowance 7,209 (39.96)% 20,026 (34.72)% 55,310 (13.00)%Rate change (35% to 21% fedrate) 35,250 (195.41)% — —% — —%Valuation allowance forremeasurement and changesrelating to the Tax Cuts and JobsAct (35,674) 197.76% — —% — —%Other 309 (1.71)% (386) 0.68% 2,008 (0.47)%Income tax provision /(benefit) $(395) 2.19% $342 (0.59)% $(91,693) 21.55%The effective tax rate for the years ended December 31, 2017, 2016 and 2015 varies from the statutory rate primarilyas a result of recording a valuation allowance.The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands): Year Ended December 31, 2017 2016 2015 Current tax provision (benefit): Federal $(424) $(91) $ — State 453 433 636 Total $29 $342 $636 Deferred tax provision (benefit): Federal $(424) $ — $(92,329) State — — — Total $(424) $ — $(92,329) Total tax provision (benefit): Federal $(848) $(91) $(92,329) State 453 433 636 Total $(395) $342 $(91,693) Included in gain (loss) from investment in affiliates $ — $ — $(16,467) Total income tax provision (benefit) $(395) $342 $(75,226) F-26 Table of ContentsThe net deferred tax is comprised of the following (in thousands): December 31, 2017 2016 Deferred tax assets: Net operating loss carryforward $60,464 $69,828 Income tax credits 454 908 Derivative instruments 261 1,208 Deferred compensation 1,418 308 Oil and gas properties — 6,806 Other 491 1,477 Total deferred tax assets before valuation allowance $63,088 $80,535 Valuation allowance (49,032) (77,497) Net deferred tax assets $14,056 $3,038 Deferred tax liability: Oil and gas properties $(10,567) $ — Investment in affiliates (3,065) (3,038) Other — — Deferred tax liability $(13,632) $(3,038) Total net deferred tax $424 $ — In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not thatsome portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependentupon the generation of future taxable income during the periods in which those temporary differences becomedeductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and taxplanning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxableincome and projections for future taxable income over the periods in which the deferred tax assets are deductible, theCompany believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and hasrecorded a valuation allowance of $49.0 million.As of December 31, 2017, the Company had federal net operating loss (“NOL”) carryforwards of approximately$284.4 million and state NOLs of $20.4 million. The federal NOL carryforwards reported as of December 31, 2014 wereacquired in the 2013 Merger with Crimson. A valuation allowance was recorded at the time of the Merger to reflect theimpact of Internal Revenue Code Section 382 limitations on the use of the federal NOLs acquired. The federal NOLcarryforwards expire at various dates beginning in 2018 and ending in 2037.ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for thefinancial statement recognition and measurement of income tax positions taken or expected to be taken in an income taxreturn. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained uponexamination by taxing authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimsonin prior years. These positions are not expected to have a material impact on results of operations, financial position or cashflows. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (inthousands): Unrecognized Tax Benefits Balance at December 31, 2016 $360 Additions based on tax positions related to the current year — Additions based on tax positions related to prior years — Additions due to acquisitions — Reductions due to a lapse of the applicable statute of limitations — Change in rate due to remeasurement (133) Balance at December 31, 2017 $227 The Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit(expense) in the Company’s Consolidated Statements of Operations. The Company had no interest or penalties related tounrecognized tax benefits for the year ended December 31, 2017 or any prior years. The total amount of unrecognized taxbenefit, if recognized, that would affect the effective tax rate was zero.F-27 Table of ContentsThe Company's tax returns are subject to periodic audits by the various jurisdictions in which the Companyoperates. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available tooffset future taxable income. The Company does not anticipate that the total unrecognized tax benefits will significantlychange due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2017.Generally, the Company's income tax years of 1998 through 2016 remain open and subject to examination byFederal tax authorities, and the tax years of 2010 through 2016 remain open and subject to examination by the taxauthorities in Texas and Louisiana which are the jurisdictions where the Company carries its principal operations. 16. Related Party TransactionsOlympic Energy PartnersMr. Joseph J. Romano was elected President and Chief Executive Officer of the Company in December 2012 andnamed Chairman of the Company in April 2013. Upon the Merger with Crimson on October 1, 2013, Mr. Romano resigned asPresident and Chief Executive Officer, but continued as Chairman. Mr. Romano is also the President and Chief ExecutiveOfficer of Olympic Energy Partners LLC ("Olympic"). Olympic has historically participated with the Company in the drillingand development of certain prospects through participation agreements and joint operating agreements, which specify eachparticipant’s working interest ("WI"), net revenue interest ("NRI") and describe when such interests are earned.Olympic last participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to its Dutch and Mary Rose wells as follows: Olympic WI NRI Dutch #1 - #5 3.53% 2.84% Mary Rose #1 3.61% 2.70% Mary Rose #2 - #3 3.61% 2.58% Mary Rose #4 2.34% 1.70% Mary Rose #5 2.56% 1.87% During each of the years ended December 31, 2017 and 2016, Mr. Romano earned $56 thousand for his service as adirector of the Company. Additionally, during the year ended December 31, 2017, Mr. Romano received 14,865 shares ofrestricted stock, which vest 100% on the one-year anniversary of the date of grant, as part of his board of directorcompensation. During the year ended December 31, 2016, Mr. Romano received 261 shares of restricted stock, pursuant tothe Salary Replacement Program, and an additional 9,892 shares of restricted stock, which vest in one year, as part of Mr.Romano’s board of director compensation. The Company recognized compensation expense of $117 thousand and $99thousand related to shares granted to Mr. Romano during the years ended December 31, 2017 and 2016, respectively.Below is a summary of payments the Company received from (paid to) Olympic in the ordinary course of business inits capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types ofpayments with other well owners (in thousands): Year Ended December 31, 2017 2016 2015 Revenue payments as well owners $(2,673) $(2,485) $(4,115) Joint interest billing receipts 391 323 531 F-28 Table of ContentsAs of December 31, 2017 and 2016, the Company's consolidated balance sheets reflected the following balancesrelating to Olympic (in thousands): Year Ended December 31, 2017 2016 Accounts Receivable: Joint interest billing $48 $59 Accounts Payable: Royalties and revenue payable (442) (557) Oaktree Capital Management L.P.In November 2017, Oaktree Capital Management L.P. ("Oaktree") sold all of its shares of the Company's stock. Mr.James Ford, previously a Managing Director and Portfolio Manager within Oaktree, and a Senior Advisor to Oaktree at thetime of sale, has been on the Company’s board of directors since October 1, 2013. Mr. Ford was previously a member ofCrimson’s board of directors from February 2005 until the closing of the Merger. Historically, all cash and equity awards payable to Mr. Ford were instead granted to an affiliate of Oaktree.Beginning October 1, 2016, all cash and equity awards payable to Oaktree for Mr. Ford’s service as a director becamepayable to him directly. During the year ended December 31, 2017, Mr. Ford directly earned $68 thousand for his service.During the year ended December 31, 2016, Mr. Ford directly earned $18 thousand for his service, and the affiliate of Oaktreeearned $48 thousand, as a result of Mr. Ford’s participation. During the year ended December 31, 2017, Mr. Ford received14,865 shares of restricted stock, which vest 100% on the one-year anniversary of the date of grant, as part of his board ofdirector compensation. During the year ended December 31, 2016, the affiliate of Oaktree received 313 shares of restrictedstock, pursuant to the Salary Replacement Program, and an additional 9,892 shares of restricted stock, which also vest in oneyear, as part of Mr. Ford’s board of director compensation. During the years ended December 31, 2017 and 2016, theCompany recognized compensation expense of $117 thousand and $99 thousand, respectively, related to the shares grantedto an affiliate of Oaktree and Mr. Ford. 17. Subsequent EventsThe Company has evaluated subsequent events through the date the financial statements were available to beissued. Nothing that would require recognition or disclosure in the financial statements was identified in addition to theitems disclosed in the financial statements.F-29 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESSUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)In accordance with U.S. GAAP for disclosures regarding oil and gas producing activities, and SEC rules for oil andgas reporting disclosures, we are making the following disclosures regarding our natural gas and oil reserves and explorationand production activities.Capitalized Costs Related to Oil and Gas Producing ActivitiesThe following table presents information regarding our net capitalized costs related to oil and gas producingactivities as of the date indicated (in thousands): December 31, 2017 2016 Proved oil and gas properties $1,239,662 $1,188,065 Unproved oil and gas properties 35,243 38,338 1,274,905 1,226,403 Less accumulated depreciation, depletion, amortization and impairment (929,210) (886,303) Net capitalized costs $345,695 $340,100 Costs IncurredThe following table presents information regarding our net costs incurred in the purchase of proved and unprovedproperties and in exploration and development activities for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Property acquisition costs: Unproved $6,540 $29,767 $11,453 Proved — — — Exploration costs 8,158 9,126 29,477 Development costs 45,016 1,890 20,120 Total costs incurred $59,714 $40,783 $61,050 The following table presents information regarding our share of the net costs incurred by Exaro in the purchase ofproved and unproved properties and in exploration and development activities for the periods indicated (in thousands): Year Ended December 31, 2017 2016 2015 Property acquisition costs $ — $ — $ — Exploration costs — — — Development costs 429 395 4,503 Total costs incurred $429 $395 $4,503 Natural Gas and Oil ReservesProved reserves are the estimated quantities of natural gas, oil and natural gas liquids which geological andengineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs underexisting economic and operating conditions and current regulatory practices. Proved developed reserves are proved reserveswhich are expected to be produced from existing completion intervals with existing equipment and operating methods.Proved natural gas and oil reserve quantities at December 31, 2017, 2016, 2015 and 2014, and the relateddiscounted future net cash flows before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc.and Netherland, Sewell & Associates, Inc. All estimates have been prepared in accordance with guidelines established by theSecurities and Exchange Commission.F-30 Table of ContentsThe below table summarizes the Company’s net ownership interests in estimated quantities of proved natural gas,oil and natural gas liquids (“NGLs”) reserves and changes in net proved reserves as of December 31, 2017, 2016, 2015 and2014, all of which are located in the continental United States. Oil andCondensate NGLs NaturalGas Total (MBbls) (MBbls) (MMcf) (MMcfe) Proved Developed and Undeveloped Reserves as of: December 31, 2014 8,415 7,509 179,651 275,193 Sale of minerals in place — — — — Extensions and discoveries 460 81 543 3,788 Revisions of previous estimates (3,160) (1,229) (31,451) (57,782) Production (924) (967) (22,615) (33,961) December 31, 2015 4,791 5,394 126,128 187,238 Sale of minerals in place (250) (101) (2,045) (4,151) Extensions and discoveries 63 — — 375 Revisions of previous estimates (583) (218) (927) (5,730) Production (597) (716) (18,103) (25,982) December 31, 2016 3,424 4,359 105,053 151,750 Sale of minerals in place — — (893) (893) Extensions and discoveries 7,159 1,989 8,191 63,076 Revisions of previous estimates 584 (224) (6,722) (4,556) Production (518) (517) (13,910) (20,123) December 31, 2017 10,649 5,607 91,719 189,254 Proved Developed Reserves as of: December 31, 2014 4,114 5,637 150,235 208,734 December 31, 2015 2,869 4,354 113,952 157,288 December 31, 2016 2,158 3,509 95,396 129,399 December 31, 2017 3,364 3,596 82,133 123,895 Proved Undeveloped Reserves as of: December 31, 2014 4,301 1,872 29,416 66,459 December 31, 2015 1,922 1,040 12,176 29,950 December 31, 2016 1,266 850 9,657 22,351 December 31, 2017 7,285 2,011 9,586 65,359 During the year ended December 31, 2017, our proved reserves increased by approximately 37.5 Bcfe attributableprimarily to new additions and extensions related to our drilling program in West Texas and positive revision of reserveestimates due to higher commodity prices, partially offset by 2017 production and a reduction in proved undevelopedreserves required by SEC guidelines for those reserves that are not likely to be drilled within a five year period after thosereserves are initially recorded.During the year ended December 31, 2016, our proved reserves decreased by approximately 35.5 Bcfe attributableprimarily to the impact of the dramatic decline in commodity prices on the value and volume of our proved reserves, and inpart to the impact of the significant reduction in our capital spending in response to the low and uncertain commodity priceenvironment.During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe attributableprimarily to the impact of the dramatic decline in commodity prices on the value and volume of our proved reserves, and inpart to the impact of the significant reduction in our capital spending in response to the low and uncertain commodity priceenvironment.F-31 Table of ContentsThe below table summarizes the Company’s net ownership interests in estimated quantities of proved natural gasand oil reserves and changes in net proved reserves as of December 31, 2017, 2016, 2015 and 2014, attributable to itsInvestment in Exaro. Oil and Natural Condensate Gas Total (MBbls) (MMcf) (MMcfe) Proved Developed and Undeveloped Reserves as of: December 31, 2014 791 65,412 70,158 Sale of minerals in place — — — Extensions and discoveries 1 120 128 Revisions of previous estimates (289) (24,637) (26,373) Production (61) (4,821) (5,189) December 31, 2015 442 36,074 38,724 Sale of minerals in place — — — Extensions and discoveries — — — Revisions of previous estimates (35) (1,710) (1,919) Production (47) (3,923) (4,205) December 31, 2016 360 30,441 32,600 Sale of minerals in place — — — Extensions and discoveries — — — Revisions of previous estimates 6 1,635 1,672 Production (37) (3,330) (3,553) December 31, 2017 329 28,746 30,719 Proved Developed Reserves as of: December 31, 2014 529 45,127 48,301 December 31, 2015 442 36,074 38,724 December 31, 2016 360 30,441 32,600 December 31, 2017 325 28,443 30,390 Proved Undeveloped Reserves as of: December 31, 2014 262 20,285 21,857 December 31, 2015 — — — December 31, 2016 — — — December 31, 2017 4 303 329 During the year ended December 31, 2017, the decrease in Exaro’s proved reserves attributable to our Investment inExaro was approximately 1.9 Bcfe. During the year ended December 31, 2016, the decrease in Exaro’s proved reserves attributable to our Investment inExaro was approximately 6.1 Bcfe. This decrease was primarily attributable to the impact of the significant reduction incapital spending in response to the low and uncertain commodity price environment. During the year ended December 31, 2015, the decrease in Exaro’s proved reserves attributable to our Investment inExaro was approximately 31.4 Bcfe. This decrease was attributable to the impact of the dramatic decline in commodity priceson the value and volume of proved reserves and the impact of the significant reduction in capital spending in response to thelow and uncertain commodity price environment.F-32 Table of ContentsStandardized MeasureThe standardized measure of discounted future net cash flows relating to the Company’s ownership interests inproved natural gas and oil reserves as of December 31, 2017, 2016 and 2015 are shown below (in thousands): As of December 31, 2017 2016 2015 Future cash inflows $877,721 $447,417 $623,014 Future production costs (243,415) (154,249) (200,953) Future development costs (138,840) (51,573) (69,147) Future income tax expenses (3,226) — — Future net cash flows 492,240 241,595 352,914 10% annual discount for estimated timing of cash flows (236,333) (75,367) (103,508) Standardized measure of discounted future net cash flows $255,907 $166,228 $249,406 Future cash inflows represent expected revenues from production and are computed by applying certain prices ofnatural gas and oil to estimated quantities of proved natural gas and oil reserves. Prices are based on the first-day-of-the-month prices for the previous 12 months. As of December 31, 2017, future cash inflows were based on unadjusted prices of$2.98 per MMbtu of natural gas, $49.92 per barrel of oil, and $18.59 per barrel of NGLs. As of December 31, 2016, futurecash inflows were based on unadjusted prices of $2.49 per MMbtu of natural gas, $39.72 per barrel of oil, and $13.62 perbarrel of NGLs. As of December 31, 2015, future cash inflows were based on unadjusted prices of $2.59 per MMbtu of naturalgas, $47.36 per barrel of oil, and $14.41 per barrel of NGLs.The standardized measure of discounted future net cash flows relating to the Company’s ownership interests inproved natural gas and oil reserves as of December 31, 2017, 2016 and 2015 attributable to its Investment in Exaro are shownbelow (in thousands): As of December 31, 2017 2016 2015 Future cash inflows $102,813 $88,398 $117,211 Future production costs (60,541) (55,610) (65,042) Future development costs (2,699) (2,380) (2,399) Future income tax expenses — — — Future net cash flows 39,573 30,408 49,770 10% annual discount for estimated timing of cash flows (15,207) (10,630) (18,472) Standardized measure of discounted future net cash flows $24,366 $19,778 $31,298 (1)Exaro does not include the effect of income taxes because Exaro is treated as a partnership for tax purposes. Realized PricesThe average realized prices for the year ended December 31, 2017 production were $2.97 per MCF of gas, $48.90per barrel of oil, and $22.97 per barrel of NGL. Sales are based on market prices and do not include the effects of realizedderivative hedging gains of $1.1 million for the year ended December 31, 2017.The average realized prices for the year ended December 31, 2016 production were $2.42 per MCF of gas, $38.52per barrel of oil, and $15.79 per barrel of NGL. Sales are based on market prices and do not include the effects of realizedderivative hedging gains of $1.8 million for the year ended December 31, 2016.Future production and development costs are estimated expenditures to be incurred in developing and producingthe Company’s proved natural gas and oil reserves based on historical costs and assuming continuation of existing economicconditions. Future development costs relate to compression charges at our platforms, abandonment costs, recompletion costs,and additional development costs for new facilities.Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. Adiscount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discountedfuture net cash flows is not intended to represent the replacement cost or fair value of the Company’s naturalF-33 (1) Table of Contentsgas and oil properties. An estimate of fair value would also take into account, among other things, the recovery of reservesnot presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative ofthe time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.Change in Standardized MeasureChanges in the standardized measure of future net cash flows relating to proved natural gas and oil reserves aresummarized below (in thousands): Year Ended December 31, 2017 2016 2015 Changes in standardized measure due to current year operation: Sales of natural gas and oil produced during the period, net of productionexpenses $(51,359) $(49,046) $(78,651) Extensions and discoveries 69,179 911 8,584 Net change in prices and production costs 57,026 (44,033) (420,890) Changes in estimated future development costs — 10,751 23,771 Revisions in quantity estimates 4,546 (8,236) (156,249) Purchase of reserves — — — Sale of reserves (235) (2,509) — Accretion of discount 16,623 24,940 79,687 Changes in income taxes (1,376) — 148,854 Change in the timing of production rates and other (4,725) (15,956) (3,716) Net change 89,679 (83,178) (398,610) Beginning of year 166,228 249,406 648,016 End of year $255,907 $166,228 $249,406 During the year ended December 31, 2017, our proved reserves increased by approximately 37.5 Bcfe and ourstandardized measure increased by approximately $89.7 million. This increase is primarily attributable to the extensions andadditions related to our assets in West Texas and positive revisions of reserve estimates due to higher commodity prices,partially offset by decreases attributable to production and decreases due to the expiration of undeveloped reserves.During the year ended December 31, 2016, our proved reserves decreased by approximately 35.5Bcfe and ourstandardized measure decreased by approximately $83.2 million. This decrease is attributable primarily to the impact of thedramatic decline in commodity prices on the value and volume of our proved reserves, and in part to the impact of thesignificant reduction in our capital spending in response to the low and uncertain commodity price environment.During the year ended December 31, 2015, our proved reserves decreased by approximately 88.0 Bcfe and ourstandardized measure decreased by approximately $398.6 million. This decrease is attributable primarily to the impact of thedramatic decline in commodity prices on the value and volume of our proved reserves, and in part to the impact of thesignificant reduction in our capital spending in response to the low and uncertain commodity price environment. F-34 Table of ContentsChanges in the standardized measure of future net cash flows relating to proved natural gas and oil reservesattributable to the Company’s investment in Exaro are summarized below (in thousands): Year Ended December 31, 2017 2016 2015 Changes in standardized measure due to current year operation: Sales of natural gas and oil produced during the period, net of production expenses $(6,744) $(5,531) $(8,745) Extensions and discoveries — — 161 Net change in prices and production costs 9,951 (7,160) (49,933) Changes in estimated future development costs 5 — 3,958 Revisions in quantity estimates 1,236 (1,616) (22,973) Purchase of reserves — — — Sale of reserves — — — Accretion of discount 1,978 3,130 10,061 Changes in income taxes — — — Change in the timing of production rates and other (1,838) (343) (1,838) Net change 4,588 (11,520) (69,309) Beginning of year 19,778 31,298 100,607 End of year $24,366 $19,778 $31,298 F-35 Table of ContentsCONTANGO OIL & GAS COMPANY AND SUBSIDIARIESQUARTERLY RESULTS OF OPERATIONS (Unaudited)Quarterly Results of OperationsThe following table sets forth the results of operations by quarter for the fiscal years ended December 31, 2017 and2016, (in thousands, except per share amounts): Quarter Ended March 31, June 30, September 30, December 31, Year ended December 31, 2017: Revenues $19,424 $20,276 $18,830 $20,015 Operating Loss $(5,897) $(6,285) $(6,022) $(5,311) Net loss attributable to common stock $885 $(6,034) $(6,916) $(5,578) Net income (loss) per share : Basic: $0.04 $(0.24) $(0.28) $(0.23) Diluted: $0.04 $(0.24) $(0.28) $(0.23) Year ended December 31, 2016: Revenues $17,582 $19,362 $19,576 $21,663 Operating Loss $(14,640) $(12,493) $(12,843) $(13,465) Net loss attributable to common stock (11,404) (17,296) (12,485) (16,844) Net loss per share : Basic: $(0.60) $(0.90) $(0.55) $(0.69) Diluted: $(0.60) $(0.90) $(0.55) $(0.69) (1)Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, leaseexpirations and relinquishments, impairment of natural gas and oil properties and general and administrative expense.(2)Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, leaseexpirations and relinquishments, impairment of natural gas and oil properties, general and administrative expense, and other income andexpense after income taxes.(3)The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly computation isbased on the income for that quarter and the weighted average number of common shares outstanding during that quarter. F-36(1) (2)(3)(1) (2)(3) Exhibit 10.21FOURTH AMENDMENT AND WAIVER TO CREDIT AGREEMENTThis FOURTH AMENDMENT AND WAIVER TO CREDIT AGREEMENT(“Amendment”), dated as of March 7, 2018, is by and among Contango Oil & Gas Company, aDelaware corporation (the “Borrower”), the lenders party to the Credit Agreement described below(the “Lenders”), Royal Bank of Canada, as administrative agent for the Lenders (in such capacity, the“Administrative Agent”), and the other parties in the capacities therein identified.RECITALSWHEREAS, the Borrower, the Lenders, the Administrative Agent and certain otherPersons are parties to the Credit Agreement, dated as of October 1, 2013, as amended by the FirstAmendment to Credit Agreement dated as of April 11, 2014, the Second Amendment to CreditAgreement dated as of October 28, 2014 and the Third Amendment to Credit Agreement dated as ofMay 6, 2016 (as amended, supplemented, amended and restated or otherwise modified from time totime, the “Credit Agreement”); andWHEREAS, the Borrower, the Administrative Agent and the Lenders intend to amendand waive certain provisions of the Credit Agreement in certain respects as set forth herein.NOW, THEREFORE, in consideration of the premises and the mutual covenants,representations and warranties contained herein, and for other good and valuable consideration, thereceipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:AGREEMENTSection 1. Definitions. Capitalized terms used herein but not defined herein shallhave the meanings as given them in the Credit Agreement, unless the context otherwise requires.Section 2. Amendments Sections 8.06, 8.07 and 8.08 of the Credit Agreement. Sections 8.06 and 8.08 of the Credit Agreement are hereby amended by deleting the percentage “90%”or “80%” (as applicable) appearing therein and replacing it with the percentage “95%” everywheresuch 90% or 80% appears in such Sections.Section 3. Waiver. The Majority Lenders hereby waive the requirement in Section9.12 of the Credit Agreement that the Borrower not permit its ratio of Current Assets to CurrentLiabilities to be less than 1.00 to 1.00 for the fiscal quarter ending December 31, 2017. The foregoingwaiver is not a waiver of any other provision of the Credit Agreement and is not a waiver of Section9.12 of the Credit Agreement in respect of any fiscal quarter other than for the fiscal quarter endingDecember 31, 2017.Section 4. Conditions to Effectiveness. The Effective Date of this Amendment shallbe deemed to occur on the date (the “Effective Date”) when the Administrative Agent has received counterparts of this Amendment duly executed by the Borrower, theAdministrative Agent, the Issuing Bank, the Swing Line Lender and the Majority Lenders and uponthe prior or concurrent satisfaction of each of the following conditions:(a) the Administrative Agent shall have received, for the account of each Lender thatis a signatory hereto, from the Borrower all agreed upon fees in connection with thisAmendment;(b) the Administrative Agent shall have received a certificate dated as of the datehereof, duly executed by an officer of the Borrower, certifying the representations andwarranties set forth in Section 6 hereof are true and correct.Notwithstanding the foregoing, this Amendment shall not become effective unless each of theforegoing conditions is satisfied (or waived in writing) on or prior to February 28, 2018. Section 5. Post-Closing Condition. Within forty-five (45) days following theEffective Date (or such later date as the Administrative Agent shall agree to in its sole discretion), theBorrower shall have delivered, or cause to be delivered, to the Administrative Agent executed newMortgages or supplements to existing Mortgages (x) sufficient to cause the Borrower to be incompliance with Section 8.08 of the Credit Agreement, as amended hereby (as determined by theAdministrative Agent in its sole discretion) and (y) in form and substance substantially similar to theexisting applicable Loan Documents. Section 6. Representations and Warranties. The Borrower hereby represents andwarrants that after giving effect hereto:(a) the representations and warranties of the Borrower and its Subsidiaries containedin the Loan Documents are true and correct in all material respects (except to the extent suchrepresentations and warranties are qualified by a materiality qualifier, which shall be true and correct inall respects), other than those representations and warranties that expressly relate solely to a specificearlier date, which shall remain correct in all material respects (except to the extent such representationsand warranties are qualified by a materiality qualifier, which shall be true and correct in all respects) asof such earlier date; and(b) after giving effect to the waiver contained in this Amendment no Default, Eventof Default or Deficiency has occurred and is continuing.Section 7. Loan Document; Ratification. (a) This Amendment is a Loan Document. Each reference to the Credit Agreementin any Loan Document will deemed to be a reference to the Credit Agreement as amended bythis Amendment.(b) Except as amended hereby, the Credit Agreement remains in full force and effectand the Borrower hereby ratifies, approves and confirms in every respect all the terms,provisions, conditions and obligations of the Credit Agreement as amended hereby. -2--Contango Fourth Amendment- Section 8. GOVERNING LAW. THIS AMENDMENT AND ANY CLAIMS,CONTROVERSY, DISPUTE OR CAUSE OF ACTION (WHETHER IN CONTRACT ORTORT OR OTHERWISE) BASED UPON, ARISING OUT OF OR RELATING TO THISAMENDMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY SHALL BEGOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATEOF NEW YORK. Section 9. Severability. In the event that any one or more of the provisionscontained in this Amendment shall, for any reason, be held invalid, illegal or unenforceable in anyrespect, such invalidity, illegality or unenforceability shall not effect any other provision of thisAmendment. Section 10. Counterparts. This Amendment may be executed in any number ofcounterparts, all of which taken together shall constitute one and the same instrument, and any partyhereto may execute this Amendment by signing one or more counterparts. Any signature heretodelivered by a party by facsimile or electronic transmission shall be deemed to be an original signaturehereto. Section 11. Successors and Assigns. This Amendment shall be binding uponand inure to the benefit of the parties hereto and their respective successors and permitted assigns. Section 12. Entire Agreement. THIS AMENDMENT, THE CREDITAGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINALAGREEMENT OF THE PARTIES WITH RESPECT TO THE SUBJECT MATTER HEREOFAND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS,OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THEPARTIES. (Signature Pages Follow) -3--Contango Fourth Amendment- In Witness Whereof, the parties hereto have caused this Amendment to be dulyexecuted and delivered by their respective duly authorized officers as of the date first written above. BORROWER: CONTANGO OIL & GAS COMPANY By: /s/ SERGIO CASTRO Name: Sergio Castro Title: Vice President and Treasurer S-1-Contango Fourth Amendment- ADMINISTRATIVE AGENT: ROYAL BANK OF CANADA By: /s/ RODICA DUTKA Name: Rodica Dutka Title: Authorized Signatory S-2-Contango Fourth Amendment- ISSUING BANK: ROYAL BANK OF CANADA, By: /s/ EMILEE SCOTT Name: Emilee Scott Title: Authorized Signatory S-3-Contango Fourth Amendment- LENDER: ROYAL BANK OF CANADA, By: /s/ JAY SARTAIN Name: Jay Sartain Title: Authorized Signatory S-4-Contango Fourth Amendment- LENDER: REGIONS BANK By: /s/ DANIEL G. STEELE Name: Daniel G. Steele Title: Managing Director S-5-Contango Fourth Amendment- LENDER: CAPITAL ONE, NATIONAL ASSOCIATION By: /s/ SCOTT MACKEY Name: Scott Mackey Title: Director S-6-Contango Fourth Amendment- LENDER: COMPASS BANK By: /s/ GABRIELA AZCARATE Name: Gabriela Azcarate Title: Vice President S-7-Contango Fourth Amendment- LENDER: BARCLAYS BANK PLC By: / s/ SYDNEY G. DENNIS Name: Sydney G. Dennis Title: Director S-8-Contango Fourth Amendment- LENDER: BOKF, NA DBA BANK OF TEXAS By: / s/ BRANDON STARR Name: Brandon Starr Title: Vice President S-9-Contango Fourth Amendment- LENDER: CADENCE BANK By: / s/ ANTHONY BLACO Name: Anthony Blanco Title: Senior Vice President S-10-Contango Fourth Amendment- LENDER: CITIBANK, N.A. By: / s/ JEFF ARD Name: Jeff Ard Title: Vice President S-11-Contango Fourth Amendment- LENDER: IBERIABANK By: / s/ BLAKELY NORRIS Name: Blakely Norris Title: Vice President S-12-Contango Fourth Amendment- Exhibit 21.1CONTANGO OIL AND GAS COMPANYLIST OF WHOLLY-OWNED SUBSIDIARIESDECEMBER 31, 2017 Wholly-Owned Subsidiaries of Contango Oil & Gas Company as of 12/31/17 Crimson Exploration Inc.Crimson Exploration Operating, Inc.Contango Energy CompanyContango Rocky Mountain Inc.Contango Operators, Inc.Contango Mining Company Conterra CompanyContaro CompanyContango Alta Investments, Inc.Contango Venture Capital CorporationLTW Pipeline Co. Exhibit 21.2 Exhibit 23.1 WILLIAM M. COBB & ASSOCIATES, INC.Worldwide Petroleum Consultants 12770 Coit Road, Suite 907(972) 385-0354Dallas, Texas 75251Fax: (972) 788-5165 E-Mail: office@wmcobb.com March 9, 2018 Contango Oil & Gas Company717 Texas Avenue, Suite 2900Houston, Texas 77002 Re: Contango Oil & Gas Company, Annual Report on Form 10-K Gentlemen: The firm of William M. Cobb & Associates, Inc. consents to the use of its name and to the use of itsprojections for Contango Oil & Gas Company’s Proved Reserves and Future Net Revenue in Contango’sAnnual Report on Form 10-K for the fiscal year ended December 31, 2017. William M. Cobb & Associates, Inc. has no interests in Contango Oil & Gas Company or in any affiliatedcompanies or subsidiaries and is not to receive any such interest as payment for such reports and has nodirector, officer, or employee otherwise connected with Contango Oil & Gas Company. Contango Oil &Gas Company does not employ us on a contingent basis. Sincerely, WILLIAM M. COBB & ASSOCIATES, INC. Texas Registered Engineering Firm F-84 Exhibit 23.2CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS The firm of Netherland, Sewell & Associates, Inc. consents to the use of its name and to the use ofits projections for Contango Oil & Gas Company's Proved Reserves and Future Net Revenue inContango Oil & Gas Company's Annual Report on Form 10-K for the fiscal year ended December 31,2017. Netherland, Sewell & Associates, Inc. has no interests in Contango Oil & Gas Company or in anyaffiliated companies or subsidiaries and is not to receive any such interest as payment for such reportsand has no director, officer, or employee otherwise connected with Contango Oil & GasCompany. Contango Oil & Gas Company does not employ us on a contingent basis. NETHERLAND, SEWELL & ASSOCIATES, INC. /s/ Danny D. Simmons By: Danny D. Simmons, P.E. President and Chief Executive Officer Houston, TexasMarch 9, 2018 Exhibit 23.3 W.D.Von Gonten&Co. Petroleum Engineering 10496 Old Katy Road, Suite 200 Houston, Texas 77043 t:713 224 6333 f: 713.224.6330 www.wdygco.com W.D. VON GONTEN & CO.March 9, 2018Contango Oil & Gas Company717 Texas Avenue, Suite 2900Houston, Texas 77002Re: Contango Oil & Gas Company, Annual Report on Form 10-KGentlemen:The firm of W.D. Von Gonten & Co. consents to the use of its name and to the use of its report regarding Contango Oil& Gas Company's Proved Reserves and Future Net Revenue associated with its 37% ownership interest in Exaro Energy IIILLC, in Contango's Annual Report on Form 10-K for the fiscal year ended December 31, 2017.W.D. Von Gonten & Co. has no interests in Contango Oil & Gas Company or in any affiliated companies orsubsidiaries and is not to receive any such interest as payment for such reports and has no director, officer, or employeeotherwise connected with Contango Oil & Gas Company. Contango Oil & Gas Company does not employ us on a contingentbasis.Yours very truly,W.D. VON GONTEN & CO.Name: W.D. Von Gonten JRTitle: President Exhibit 23.4 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We have issued our reports dated March 9, 2018, with respect to the consolidated financial statements andinternal control over financial reporting included in the Annual Report of Contango Oil & Gas Company onForm 10-K for the year ended December 31, 2017. We consent to the incorporation by reference of saidreports in the Registration Statements of Contango Oil & Gas Company on Forms S-3 (File No. 333‑215784and File No. 333-193613) and on Forms S-8 (File No. 333-189302 and File No. 333-170236). /s/ GRANT THORNTON LLP Houston, TexasMarch 9, 2018 Exhibit 31.1CONTANGO OIL & GAS COMPANYCertification Required by Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934I, Allan D. Keel, President and Chief Executive Officer of Contango Oil & Gas Company (the “Company”), certify that: 1.I have reviewed this Annual Report on Form 10-K of the Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a materialfact necessary to make the statements made, in light of the circumstances under which such statements were made, notmisleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly presentin all material respects the financial condition, results of operations and cash flows of the Company as of, and for, theperiods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls andprocedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (asdefined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to bedesigned under our supervision, to ensure that material information relating to the Company, including itsconsolidated subsidiaries, is made known to us by others within those entities, particularly during the period inwhich this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reportingto be designed under our supervision, to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles; (c)Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this reportour conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the periodcovered by this report based on such evaluation; and (d)Disclosed in this report any change in the Company’s internal control over financial reporting that occurredduring the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely tomaterially affect, the Company’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control overfinancial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or personsperforming the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financialreporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarizeand report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role inthe Company’s internal control over financial reporting. Date: March 9, 2018 By: /S/ ALLAN D. KEEL Allan D. KeelPresident and Chief Executive Officer(Principal Executive Officer) Exhibit 31.2CONTANGO OIL & GAS COMPANY Certification Required by Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 I, E. Joseph Grady, Chief Financial Officer of Contango Oil & Gas Company (the “Company”), certify that: 1.I have reviewed this Annual Report on Form 10-K of the Company; 2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a materialfact necessary to make the statements made, in light of the circumstances under which such statements were made, notmisleading with respect to the period covered by this report; 3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly presentin all material respects the financial condition, results of operations and cash flows of the Company as of, and for, theperiods presented in this report; 4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls andprocedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (asdefined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have: (a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to bedesigned under our supervision, to ensure that material information relating to the Company, including itsconsolidated subsidiaries, is made known to us by others within those entities, particularly during the period inwhich this report is being prepared; (b)Designed such internal control over financial reporting, or caused such internal control over financial reportingto be designed under our supervision, to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles; (c)Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this reportour conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the periodcovered by this report based on such evaluation; and (d)Disclosed in this report any change in the Company’s internal control over financial reporting that occurredduring the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely tomaterially affect, the Company’s internal control over financial reporting; and 5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control overfinancial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or personsperforming the equivalent functions): (a)All significant deficiencies and material weaknesses in the design or operation of internal control over financialreporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarizeand report financial information; and (b)Any fraud, whether or not material, that involves management or other employees who have a significant role inthe Company’s internal control over financial reporting. Date: March 9, 2018 By: /S/ E. JOSEPH GRADY E. Joseph GradySenior Vice President and Chief Financial Officer(Principal Financial Officer) Exhibit 32.1CONTANGO OIL & GAS COMPANY CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 906OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Contango Oil & Gas Company (the “Company”) on Form 10-K for the yearended December 31, 2017 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Allan D.Keel, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant toSection 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, asamended; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results ofoperations of the Company. Date: March 9, 2018 By: /S/ ALLAN D. KEEL Allan D. KeelPresident and Chief Executive Officer(Principal Executive Officer) Exhibit 32.2CONTANGO OIL & GAS COMPANY CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TO SECTION 906OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Contango Oil & Gas Company (the “Company”) on Form 10-K for the yearended December 31, 2017 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, E. JosephGrady, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 ofthe Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, asamended; and 2.The information contained in the Report fairly presents, in all material respects, the financial condition and results ofoperations of the Company. Date: March 9, 2018 By: /S/ E. JOSEPH GRADY E. Joseph GradySenior Vice President and Chief Financial Officer(Principal Financial Officer) Exhibit 99.1 WILLIAM M. COBB & ASSOCIATES, INC.Worldwide Petroleum Consultants 12770 Coit Road, Suite 907(972) 385-0354Dallas, TexasFax: (972) 788-5165 E-Mail: office@wmcobb.com January 23, 2018 Mr. Steve MengleContango Oil & Gas Company717 Texas Avenue, Suite 2900Houston, TX 77002 Dear Mr. Mengle: In accordance with your request, William M. Cobb & Associates, Inc. (Cobb & Associates) has estimated the provedreserves and future income as of January 1, 2018, attributable to the interest of Contango Oil & Gas Company and itssubsidiaries (Contango) in certain oil and gas properties located in state and federal waters of the Gulf of Mexico, andonshore in Mississippi and Texas. This report was completed on January 23, 2018. Table 1 summarizes our estimate of the proved oil and gas reserves and their pre-federal income tax value undiscountedand discounted at ten percent. Values shown are determined utilizing constant oil and gas prices and well operatingexpenses. The discounted present worth of future income values shown in Table 1 are not intended to necessarilyrepresent an estimate of fair market value. These estimates were prepared in accordance with the definitions and regulationsof the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes,conform to the FASB Accounting Standards Certification Topic 932, Extraction Activities – Oil and Gas. TABLE 1 CONTANGO - NET RESERVES AND VALUEAS OF JANUARY 1, 2018CONSTANT SEC OIL AND GAS PRICES Future Net Pre-Tax Income – M$ Reserve Category Net Gas(MMCF) Net NGL(MBBL) Net Oil(MBBL) Undiscounted Discountedat 10% Proved Producing 62,998 2,271 1,583 219,343 148,086 Undeveloped 6,497 1,583 4,796 147,277 32,135 Total Proved 69,495 3,854 6,379 366,620 180,221 Mr. Steve MengleJanuary 23, 2018Page 2 Total proved reserves as of January 1, 2018 are 130,893 MMCFE. This amount is calculated using a six MCF per barrelratio applied to condensate and NGL volumes. Oil and NGL volumes are expressed in thousands of stock tank barrels (MBBL). A stock tank barrel is equivalent to 42United States gallons. Gas volumes are expressed in millions of standard cubic feet (MMCF) as determined at 60Fahrenheit and the legal pressure base for the specific location of the gas reserves. Our report, which was prepared for Contango’s use in filing with the SEC and will be filed with Contango’s Form 10-Kfor fiscal year ended December 31, 2017 (the “Form 10-K”), covers 130,893 MMCFE, or 70.2 percent of the total company present value discounted at ten percent (PV10) presented inContango’s Form 10-K. We have used all assumptions, data, methods, and procedures considered necessary andappropriate to prepare this report. DISCUSSION Eugene Island 10 Eugene Island 10 is located in federal and state waters of the Gulf of Mexico, at a water depth of approximately 13feet. Production is primarily from a single CibOp sand, the JRM-1 sand, at a depth of approximately 15,000 feet. Thefield was discovered in September, 2006 by the Contango Operators Dutch 1 well. Contango has since drilled four morewells, the Dutch 2, 3, 4 and 5, on Federal acreage. Contango’s Louisiana State leases in this field are referred to as the Mary Rose prospect. Five Mary Rose wells have beendrilled to date. Four Mary Rose wells, numbers 1 through 4, produce from the main CibOp sand. The Mary Rose 5 wellproduces from a separate, and much smaller, CibOp reservoir. All wells now produce to the Contango ‘H’ platform located in Eugene Island Block 11. The Dutch 1, 2, and 3 wellspreviously produced to the Chevron EI-24 platform but were switched to the Contango ‘H’ platform in 2013. Proved reserves for the Eugene Island 10 main CibOp sand are based on analysis of historical rate versus time declinecurves and P/Z performance plots, supplemented by volumetric calculations of original-gas-in-place (OGIP) using allavailable well log and 3D seismic data. The reservoir has been effectively drilled to the lowest structural datum and nosignificant aquifer has been found. Performance to date indicates a depletion drive system. All Dutch and Mary Rosewells now flow to compression on the ‘H’ platform, allowing for a decrease in producing flowing tubing pressures. Contango plans to install a second stage of compression in the third quarter of 2018, which will lower the compressor inletpressure to 200 psig or lower. Forecasts for the producing wells are modeled to increase at the time the second stage isexpected online. There are no remaining capital or startup costs for compression on the ‘H’ platform. The custody transfermeter is downstream of the compressor and other supply and fuel gas, so engineered and forecasted volumes already havethese compressor and other fuel volumes removed, at an estimated total of 1,493 MCFD. Contango’s working interest ownership is approximately 55 percent in the Dutch wells and 53 percent in the Mary Rose 1through 3 wells. The Contango working interest in the Mary Rose 4 and 5 wells is approximately 35 and 38 percent,respectively. Based on future net income, discounted at ten percent o Mr. Steve MengleJanuary 23, 2018Page 3(PV10), approximately 69.1 percent of the evaluated Contango proved reserve value is attributable to the Eugene Island 10wells. Two wells on the State acreage originally produced from gas reservoirs separate from the main CibOp reservoir. TheEloise 3 well produced and depleted a lower RobL sand and was recompleted to an isolated CibOp sand during the lastquarter of 2011. This stray CibOp producer, now called the Mary Rose 5, began producing in January 2012. The Eloise 5well has also produced and depleted a lower RobL sand and was recompleted to the main CibOp reservoir mid-year 2011. The Eloise 5 was renamed the Dutch 5 well and began producing from the main CibOp reservoir in July 2011. Ship Shoal 263 Contango drilled the Ship Shoal 263 B-1 well in 2009 and completed the well for production in a gas sand at 15,850 feet. The well began producing on June 30, 2010 and has produced approximately 8.5 BCF of gas and 561 MBBL ofcondensate to date. This well has been plugged and abandoned and will be dropped from future reports. Vermilion 170 Contango drilled the OCS-G-33596 #1 in March of 2011 and successfully completed the well in the Big A sand at a depthof approximately 13,800 feet. Production started in September 2011 upon installation of a production platform in 87 feet ofwater. Current production rates are 5.0 MMCF per day with 38 barrels of condensate. Cumulative production to date isapproximately 22.6 BCF of gas and 453 MBBL of condensate. Proved producing reserves are based on analysis of thegas rate versus time production history for the well. South Timbalier 17-1 In mid to late-2013, Contango drilled and tested a well on its South Timbalier 17 lease. The South Timbalier 17-1 wasdrilled to a total measured depth of 11,432 feet, and was completed in a sand from 11,174 - 11,200 feet. The well tested inSeptember of 2013 at a rate of 12.7 MMCF per day. Facilities were installed in 2014 and the well commenced productionin July of 2014, with peak daily rates of 15.0 MMCF per day with 166 BBL of condensate. The well has been pluggedand abandoned, having produced 3.2 BCF of gas and 20 MBBL of condensate. Tuscaloosa Marine Shale Wells Contango owns a working interest in four Tuscaloosa Marine Shale (TMS) wells drilled from 2012 to 2014, which areoperated by Goodrich Petroleum. The wells are located in Wilkinson and Amite Counties, Mississippi, and they producefrom the Cretaceous aged TMS at a true vertical depth of approximately 12,000 feet. The wells were drilled horizontallywith variable lateral lengths that average approximately 6,000’. The wells were hydraulically fracture stimulated toincrease well deliverability. Peak oil rates for the wells ranged from 225 to 875 BBL of oil per day, and averaged 585BBL of oil per day. The wells are on hydraulic pump with a current combined rate of approximately 100 BBL of oil perday. Cumulative oil production to date is approximately 608 MBBL. There are currently no gas sales for the TMS wells. Mr. Steve MengleJanuary 23, 2018Page 4Pecos County Wolfcamp Wells During 2017, Contango embarked on a drilling program for Wolfcamp Shale wells in Pecos County, Texas. Five wellshave been drilled and completed and are carried as proved developed producing (PDP) in this report. The five wells havea combined producing rate of approximately 1,150 BOPD and 2,550 MCFPD. Cumulative production to date isapproximately 295 MBBL and 535 MMCF. Reserves for the five wells are based on analysis of all available daily rate data from the wells. Four proved undeveloped(PUD) locations are assigned to each PDP well, with oil and gas reserve volumes equivalent to the specific offsetting PDPwell. OIL AND GAS PRICING Projections of proved reserves contained in this report utilize constant product prices of $2.98 per MMBTU of gas and$51.34 per barrel of oil. These are the average first-of-month prices for the prior 12-month period for Henry Hub gas andWest Texas Intermediate (WTI) oil. Appropriate oil and gas pricing differentials, residue gas shrink, NGL yields, andNGL pricing as a fraction of WTI were calculated for each field, as shown below in Table 2. TABLE 2 CONTANGO – PRODUCT PRICE DIFFERENTIALSAND NGL YIELD BY FIELD Oil/CondResidue GasResidue GasNGLNGLDifferentialDifferentialFraction afterYieldFraction ofField($/BBL)($/MMBTU)Fuel & NGL(B/MM)WTI PriceEugene Island 10 (DMR) -1.879 0.056 0.8767 27.303 0.491Vermilion 170 0.340 -0.454 0.9286 21.150 0.518Pecos County Wolfcamp -4.389 -0.236 0.5500 134 0.351HUFF 18-7H1-TMS -1.157 -0.236 0.0695 CMR Foster-TMS -0.718 -0.236 0.0695 OPERATING COSTS Future operating costs for each of the Contango wells are held constant at current values for the life of the property. Thesecosts were calculated using 12-month lease operating expense (LOE) statements provided by Contango. Following is abrief description of the gross operating cost projections for each of the Contango properties: According to the data analyzed, the ten Eugene Island 10 wells, including the Dutch 1-5 and Mary Rose 1-5 wells, had anaverage monthly operating cost of $779,326, or $77,933 per producing well. These wells produce to the ‘H Platform’ andare subject to product transportation and processing fees. These fees were calculated using LOE data and currentprocessing contracts when supplied. For the Dutch wells, transportation and processing fees of $0.095 per net producedMCF, $2.196 per net barrel of oil, Mr. Steve MengleJanuary 23, 2018Page 5and $2.872 per net barrel of NGL were scheduled. For the Mary Rose wells, transportation and processing fees of $0.086per net produced MCF, $1.975 per net barrel of oil and $2.583 per net barrel of NGL were scheduled. For Vermilion 170, a fixed monthly operating cost of $156,815 was scheduled. Transportation and processing fees of$0.044 per net MCF of produced gas, $2.679 per net barrel of oil, and $5.639 per net barrel of NGL were also scheduled. The fixed monthly operating cost for the Tuscaloosa Marine Shale wells in the CMR Foster Field were determined to be$22,630 per well. The monthly well operating cost for the Huff 18-7H1 was determined to be $21,042. 10 months of operating cost data were available for the four Pecos County Wolfcamp wells. The per well operating costwas calculated to be $15,000 using data provided through August of 2017. These wells were new drills in 2017 and morerecent data indicates that monthly well operating costs will be closer to $7,000 per well. Per well operating costs werescheduled at $15,000 per month for the first 12 months and then $7,000 per month for the remaining well life. Transportation and processing costs of $0.375 per net produced MCF and $2.611 per net produced barrel of NGL werealso scheduled. CAPITAL COSTS There are no future development projects scheduled for the Contango offshore properties. However, abandonment costs,as provided by Contango, have been scheduled. Platform abandonment costs are net of anticipated salvage value. Nosalvage value for the individual wells has been considered. The development costs for each Pecos County PUD location was scheduled at nine million dollars. This value wasprovided by Contango, and is consistent with our experience in the area. PROFESSIONAL GUIDELINES Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids, which geologicaland engineering data demonstrate with reasonable certainty to be recoverable in future years, from known reservoirs underexpected economic and operating conditions. Reserves are considered proved if economic productivity is supported byeither actual production or conclusive formation tests. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely tobe recovered than proved reserves, but more certain to be recovered than possible reserves. Possible reserves are thoseadditional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable thanprobable reserves. The reserve definitions used by Cobb & Associates are consistent with definitions set forth in the PRMS and approved bythe Society of Petroleum Engineers and other professional organizations. The reserves included in this report are estimates only and should not be construed as being exactquantities. Governmental policies, uncertainties of supply and demand, the prices actually received for the reserves, andthe costs incurred in recovering such reserves, may vary from the price and cost assumptions in this report. Estimatedreserves using price escalations may vary from values obtained Mr. Steve MengleJanuary 23, 2018Page 6using constant price scenarios. In any case, estimates of reserves, resources, and revenues may increase or decrease as aresult of future operations. Cobb & Associates has not examined titles to the appraised properties nor has the actual degree of interest owned beenindependently confirmed. The data used in this evaluation were obtained from Contango Oil & Gas Company and thenon-confidential files of Cobb & Associates and were considered accurate. We have not made a field examination of the Contango properties, therefore, operating ability and condition of theproduction equipment have not been considered. Also, environmental liabilities, if any, caused by Contango or any otheroperator have not been considered, nor has the cost to restore the property to acceptable conditions, as may be required byregulation, been taken into account. In evaluating available information concerning this appraisal, Cobb & Associates has excluded from its consideration allmatters as to which legal or accounting interpretation, rather than engineering, may be controlling. As in all aspects of oiland gas evaluation, there are uncertainties inherent in the interpretation of engineering data and conclusions necessarilyrepresent only informed professional judgments. William M. Cobb & Associates, Inc. is an independent consulting firm founded in 1983. Its compensation is notcontingent on the results obtained or reported. Frank J. Marek, a Registered Texas Professional Engineer and President ofWilliam M. Cobb & Associates, Inc., is primarily responsible for overseeing the preparation of the reserve report. Hisprofessional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining toEstimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. Hisqualifications include: Bachelor of Science degree in Petroleum Engineering from Texas A&M University 1977; memberof the Society of Petroleum Engineers; member of the Society of Petroleum Evaluation Engineers; and 40 years ofexperience in estimating and evaluating reserve information and estimating and evaluating reserves. Cobb & Associates appreciates the opportunity to be of service to you. If you have any questions regarding this report,please do not hesitate to contact us. Sincerely, WILLIAM M. COBB & ASSOCIATES, INC. Texas Registered Engineering Firm F-84 Exhibit 99.2February 1, 2018 Mr. Jay S. MengleContango Oil & Gas Company717 Texas Avenue, Suite 2900Houston, Texas 77002 Dear Mr. Mengle: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2017,to the Contango Oil & Gas Company (Contango) interest in certain oil and gas properties located in Louisiana,Mississippi, Texas, and Wyoming. We completed our evaluation on or about the date of this letter. It is ourunderstanding that the proved reserves estimated in this report constitute approximately 31 percent of all provedreserves owned by Contango. The estimates in this report have been prepared in accordance with the definitions andregulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting StandardsCodification Topic 932, Extractive Activities—Oil and Gas, except that future income taxes are excluded for allproperties and, as requested, per-well overhead expenses are excluded for the operated properties and abandonmentcosts have not been included in our estimates of future net revenue. Definitions are presented immediately following thisletter. This report has been prepared for Contango's use in filing with the SEC; in our opinion the assumptions, data,methods, and procedures used in the preparation of this report are appropriate for such purpose. We estimate the net reserves and future net revenue to the Contango interest in these properties, as of December 31,2017, to be: Net Reserves Future Net Revenue (M$) Oil NGL Gas Present WorthCategory (MBBL) (MBBL) (MMCF) Total at 10% Proved Developed Producing 1,574.6 795.4 10,696.9 56,478.0 38,011.7Proved Developed Non-Producing 206.7 529.8 8,439.5 22,652.6 14,641.1Proved Undeveloped 2,488.2 427.9 3,088.8 49,744.5 24,424.9 Total Proved 4,269.5 1,753.1 22,225.2 128,874.9 77,077.7 Totals may not add because of rounding. The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed inthousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millionsof cubic feet (MMCF) at standard temperature and pressure bases. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on developmentand production status. As requested, probable and possible reserves that exist for these properties have not beenincluded. The estimates of reserves and future revenue included herein have not been adjusted for risk. This reportdoes not include any values that could be attributed to interests in undeveloped acreage beyond those tracts for whichundeveloped reserves have been estimated. Gross revenue is Contango's share of the gross (100 percent) revenue from the properties prior to anydeductions. Future net revenue is after deductions for Contango's share of production taxes, ad valorem taxes, capitalcosts, and operating expenses but before consideration of any income taxes. The future net revenue has beendiscounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted,should not be construed as being the fair market value of the properties. Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price foreach month in the period January through December 2017. For oil and NGL volumes, the average West TexasIntermediate posted price of $47.79 per barrel is adjusted by field for quality, transportation fees, and marketdifferentials. For gas volumes, the average Henry Hub spot price of $2.976 per MMBTU is adjusted by field for energycontent, transportation fees, and market differentials. All prices are held constant throughout the lives of theproperties. The average adjusted product prices weighted by production over the remaining lives of the properties are$47.84 per barrel of oil, $12.05 per barrel of NGL, and $2.784 per MCF of gas. Operating costs used in this report are based on operating expense records of Contango. For the nonoperatedproperties, these costs include the per-well overhead expenses allowed under joint operating agreements along withestimates of costs to be incurred at and below the district and field levels. As requested, operating costs for theoperated properties include only direct lease- and field-level costs. Operating costs have been divided into per‑wellcosts and per-unit-of-production costs. For all properties, headquarters general and administrative overhead expenses ofContango are not included. Operating costs are not escalated for inflation. Capital costs used in this report were provided by Contango and are based on authorizations for expenditure and actualcosts from recent activity. Capital costs are included as required for workovers, new development wells, and productionequipment. Based on our understanding of future development plans, a review of the records provided to us, and ourknowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are notescalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment orthe cost of abandoning the properties. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine themechanical operation or condition of the wells and facilities. We have not investigated possible environmental liabilityrelated to the properties; therefore, our estimates do not include any costs due to such possible liability. We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery tothe Contango interest. Therefore, our estimates of reserves and future revenue do not include adjustments for thesettlement of any such imbalances; our projections are based on Contango receiving its net revenue interest share ofestimated future gross production. Additionally, we have made no investigation of any firm transportation contracts thatmay be in place for these properties; no adjustments have been made to our estimates of future revenue to account forsuch contracts. The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reservesare those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated withreasonable certainty to be economically producible; probable and possible reserves are those additional reserves whichare sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease asa result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition tothe primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but notlimited to, that the properties will be developed consistent with current development plans as provided to us byContango, that the properties will be operated in a prudent manner, that no governmental regulations or controls will beput in place that would impact the ability of the interest owner to recover the reserves, and that our projections of futureproduction will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and thecosts related thereto could be more or less than the estimated amounts. Because of governmental policies anduncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recoveringsuch reserves may vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologicmaps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have beenprepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas ReservesInformation promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering andgeoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy,that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SECdefinitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in theinterpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informedprofessional judgment. The data used in our estimates were obtained from Contango, public data sources, and the nonconfidential files ofNetherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in ouroffice. We have not examined the titles to the properties or independently confirmed the actual degree or type of interestowned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirementsregarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Chad E. Ireton, aLicensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAIsince 2012 and has over 11 years of prior industry experience. Mike K. Norton, a Licensed Professional Geoscientist inthe State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years ofprior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; wedo not own an interest in these properties nor are we employed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees III By: C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer /s/ Chad E. Ireton /s/ Mike K. Norton By: By: Chad E. Ireton, P.E. 115760 Mike K. Norton, P.G. 441 Vice President Senior Vice President Date Signed: February 1, 2018Date Signed: February 1, 2018 CEI:BCW Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience toour clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digitaldocument is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between thedigital document and the original document, the original document shall control and supersede the digital document. DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management Systemapproved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, ExtractiveActivities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations. (1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of leasebonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land includingmineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiringproperties. (2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluidproperties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a moreadvanced stage of development than the reservoir of interest and thus may provide concepts to assist in theinterpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogousreservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest: (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);(ii) Same environment of deposition;(iii) Similar geological structure; and(iv) Same drive mechanism. Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than inthe reservoir of interest. (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in naturaldeposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmosphericpressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons. (4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoirtemperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature. (5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single valuefor each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in thereserves estimation procedure. (6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expectedto be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the requiredequipment is relatively minor compared to the cost of a new well; and(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate ifthe extraction is by means not involving a well.Supplemental definitions from the 2007 Petroleum Resources Management System:Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that areopen and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improvedrecovery project is in operation.Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-inReserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have notyet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable ofproduction for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which willrequire additional completion work or future recompletion prior to start of production. In all cases, production can be initiated orrestored with relatively low expenditure compared to the cost of drilling a new well. Definitions - Page 1 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting,treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation andapplicable operating costs of support equipment and facilities and other costs of development activities, are costsincurred to: (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose ofdetermining specific development drilling sites, clearing ground, draining, road building, and relocating publicroads, gas lines, and power lines, to the extent necessary in developing the proved reserves.(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, includingthe costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellheadassembly.(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters,manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, andcentral utility and waste disposal systems.(iv) Provide improved recovery systems. (8) Development project. A development project is the means by which petroleum resources are brought to the statusof economically producible. As examples, the development of a single reservoir or field, an incremental development ina producing field, or the integrated development of a group of several fields and associated facilities with a commonownership may constitute a development project. (9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphichorizon known to be productive. (10) Economically producible. The term economically producible, as it relates to a resource, means a resource whichgenerates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of theproducts that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined inparagraph (a)(16) of this section. (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a givendate and cumulative production as of that date. (12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specificareas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratorywells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the relatedproperty (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types ofexploration costs, which include depreciation and applicable operating costs of support equipment and facilities and othercosts of exploration activities, are: (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conductthose studies, and salaries and other expenses of geologists, geophysical crews, and others conductingthose studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes onproperties, legal costs for title defense, and the maintenance of land and lease records.(iii) Dry hole contributions and bottom hole contributions.(iv) Costs of drilling and equipping exploratory wells.(v) Costs of drilling exploratory-type stratigraphic test wells. (13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a fieldpreviously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not adevelopment well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section. (14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.Definitions - Page 2 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individualgeological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which areseparated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs thatare associated by being in overlapping or adjacent fields may be treated as a single or common operational field. Thegeological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features asopposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. (16) Oil and gas producing activities. (i) Oil and gas producing activities include: (A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas")in their natural states and original locations;(B) The acquisition of property rights or properties for the purpose of further exploration or for thepurpose of removing the oil or gas from such properties;(C) The construction, drilling, and production activities necessary to retrieve oil and gas from theirnatural reservoirs, including the acquisition, construction, installation, and maintenance of fieldgathering and storage systems, such as:(1) Lifting the oil and gas to the surface; and(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquidhydrocarbons); and(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale,coalbeds, or other nonrenewable natural resources which are intended to be upgraded into syntheticoil or gas, and activities undertaken with a view to such extraction. Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminalpoint", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstancesexist, it may be appropriate to regard the terminal point for the production function as: a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, acommon carrier, a refinery, or a marine terminal; andb. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those naturalresources are delivered to a purchaser prior to upgrading, the first point at which the natural resources aredelivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgradessuch natural resources into synthetic oil or gas. Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons meanshydrocarbons that are saleable in the state in which the hydrocarbons are delivered. (ii) Oil and gas producing activities do not include: (A) Transporting, refining, or marketing oil and gas;(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gasby a registrant that does not have the legal right to produce or a revenue interest in such production;(C) Activities relating to the production of natural resources other than oil, gas, or natural resourcesfrom which synthetic oil and gas can be extracted; or(D) Production of geothermal steam. (17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered thanprobable reserves. (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a lowprobability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used,there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceedthe proved plus probable plus possible reserves estimates.Definitions - Page 3 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data controland interpretations of available data are progressively less certain. Frequently, this will be in areas wheregeoscience and engineering data are unable to define clearly the area and vertical limits of commercialproduction from the reservoir by a defined project.(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of thehydrocarbons in place than the recovery quantities assumed for probable reserves.(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based onreasonable alternative technical and commercial interpretations within the reservoir or subject project thatare clearly documented, including comparisons to results in successful similar projects.(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacentportions of a reservoir within the same accumulation that may be separated from proved areas by faults withdisplacement less than formation thickness or other geological discontinuities and that have not beenpenetrated by a wellbore, and the registrant believes that such adjacent portions are in communication withthe known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher orlower than the proved area if these areas are in communication with the proved reservoir.(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil(HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assignedin the structurally higher portions of the reservoir above the HKO only if the higher contact can beestablished with reasonable certainty through reliable technology. Portions of the reservoir that do not meetthis reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoirfluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered thanproved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered willexceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, thereshould be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plusprobable reserves estimates.(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data controlor interpretations of available data are less certain, even if the interpreted reservoir continuity of structure orproductivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areasthat are structurally higher than the proved area if these areas are in communication with the provedreservoir.(iii) Probable reserves estimates also include potential incremental quantities associated with a greaterpercentage recovery of the hydrocarbons in place than assumed for proved reserves.(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. (19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full rangeof values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used togenerate a full range of possible outcomes and their associated probabilities of occurrence. (20) Production costs. (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation andapplicable operating costs of support equipment and facilities and other costs of operating and maintainingthose wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: (A) Costs of labor to operate the wells and related equipment and facilities.(B) Repairs and maintenance.(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and relatedequipment and facilities.Definitions - Page 4 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (D) Property taxes and insurance applicable to proved properties and wells and related equipment andfacilities.(E) Severance taxes. (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may alsoserve transportation, refining, and marketing activities. To the extent that the support equipment andfacilities are used in oil and gas producing activities, their depreciation and applicable operating costsbecome exploration, development or production costs, as appropriate. Depreciation, depletion, andamortization of capitalized acquisition, exploration, and development costs are not production costs but alsobecome part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis ofgeoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from agiven date forward, from known reservoirs, and under existing economic conditions, operating methods, and governmentregulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates thatrenewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it willcommence 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 reservoir that can, with reasonable certainty, be judged to becontinuous with it and to contain economically producible oil or gas on the basis of availablegeoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest knownhydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data andreliable technology establishes a lower contact with reasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and thepotential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higherportions of the reservoir only if geoscience, engineering, or performance data and reliable technologyestablish the higher contact with reasonable certainty.(iv) Reserves which can be produced economically through application of improved recovery techniques(including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorablethan in the reservoir as a whole, the operation of an installed program in the reservoir or ananalogous reservoir, or other evidence using reliable technology establishes the reasonablecertainty 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, includinggovernmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is tobe determined. The price shall be the average price during the 12-month period prior to the ending date ofthe period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements,excluding escalations based upon future conditions. (23) Proved properties. Properties with proved reserves. (24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidencethat the quantities will be recovered. If probabilistic methods are used, there should be at least a 90%Definitions - Page 5 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists ifthe quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery(EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. (25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computationalmethods) that has been field tested and has been demonstrated to provide reasonably certain results with consistencyand repeatability in the formation being evaluated or in an analogous formation. (26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to beeconomically producible, as of a given date, by application of development projects to known accumulations. Inaddition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or arevenue interest in the production, installed means of delivering oil and gas or related substances to market, and allpermits and financing required to implement the project. Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing,faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assignedto areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir,structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentiallyrecoverable resources from undiscovered accumulations). Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entityparticipates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer ofthose reserves (see paragraph 932-235-50-7). Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gasreserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extentprovided by contractual arrangements in existence at year-end.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred indeveloping and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assumingcontinuation of existing economic conditions. If estimated development expenditures are significant, they shall bepresented separately from estimated production costs.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory taxrates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity'sproved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effectto tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.Future net cash flows. These amounts are the result of subtracting future development and production costs and futureincome tax expenses from future cash inflows.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future netcash flows relating to proved oil and gas reserves.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computeddiscount. Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the followingshall be disclosed as of the end of the year:a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entityparticipates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer ofthose reserves (see paragraph 932-235-50-7).The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combinedfor reporting purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reservequantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:a.Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reservesto the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided bycontractual arrangements in existence at year-end.b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred indeveloping and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assumingcontinuation of existing economic conditions. If estimated development expenditures are significant, they shall be presentedseparately from estimated production costs.c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates,with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oiland gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to taxdeductions and tax credits and allowances relating to the entity's proved oil and gas reserves.d.Future net cash flows. These amounts are the result of subtracting future development and production costs and futureincome tax expenses from future cash inflows.e.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future netcash flows relating to proved oil and gas reserves.f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computeddiscount. (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/orgas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.Definitions - Page 6 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. Aportion of the resources may be estimated to be recoverable, and another portion may be considered to beunrecoverable. Resources include both discovered and undiscovered accumulations. (29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specificpurposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, watersupply for injection, observation, or injection for in-situ combustion. (30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain informationpertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed forhydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holesrelated to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known areaor "development type" if drilled in a known area. (31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that areexpected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditureis required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas thatare reasonably certain of production when drilled, unless evidence using reliable technology exists thatestablishes reasonable certainty of economic producibility at greater distances.(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has beenadopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances,justify a longer time.From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations orenvironmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longertime periods, this determination must always take into consideration all of the facts and circumstances. No particular type of projectper se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even thoughdevelopment may extend past five years include, but are not limited to, the following:● The company's level of ongoing significant development activities in the area to be developed (for example, drilling only theminimum number of wells necessary to maintain the lease generally would not constitute significant development activities);● The company's historical record at completing development of comparable long-term projects;● The amount of time in which the company has maintained the leases, or booked the reserves, without significantdevelopment activities;● The extent to which the company has followed a previously adopted development plan (for example, if a company haschanged its development plan several times without taking significant steps to implement any of those plans, recognizingproved undeveloped reserves typically would not be appropriate); and● The extent to which delays in development are caused by external factors related to the physical operating environment`t(for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internalfactors (for example, shifting resources to develop properties with higher priority). (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for whichan application of fluid injection or other improved recovery technique is contemplated, unless suchtechniques have been proved effective by actual projects in the same reservoir or an analogous reservoir,as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishingreasonable certainty. (32) Unproved properties. Properties with no proved reserves.Definitions - Page 7 of 7 Exhibit 99.3 W.D.Von Gonten&Co. Petroleum Engineering10496 Old Katy Road, Suite 200Houston, Texas 77043t: 713 224 6333 f: 713.224.6330www.wdygco.com February 12, 2018 Mr. John P. AtwoodSenior Vice PresidentExaro Energy III, LLC1800 Bering Drive, Suite 540Houston, Texas 77057 Re: Engineering Evaluation Estimate of Reserves & Revenues SEC Year End 2017 Pricing “As of” January 1, 2018 Dear Mr. Atwood: At your request, W.D. Von Gonten & Co. has estimated future reserves and projected net revenues attributable tocertain oil and gas interests currently owned by Exaro Energy III, LLC (Exaro). The properties represented hereinare located in the Jonah field of Sublette County, Wyoming. A summary of the discounted future net revenueattributable to Exaro’s Proven and Probable reserves, “As of” January 1, 2018, is as follows: W.D.Von Gonten&Co. Petroleum Engineering Report Preparation Purpose of Report – The purpose of this report is to provide Exaro with a projection of future reserves andrevenues attributable to certain Proved and Probable oil and gas interests presently owned. Scope of Report – W.D. Von Gonten & Co. was engaged by Exaro to estimate the reserves and revenuesassociated with the properties included in this report. Once reserves were estimated, future revenue projectionswere generated utilizing SEC pricing guidelines. Reporting Requirements – Securities and Exchange Commission (SEC) Regulation S-X 210, Rule 4-10 andRegulation S-K 229, Item 1200 (as revised in December 2008, effective 1-1-10), and Financial AccountingStandards Board (FASB) Statement No. 69 require oil and gas reserve information to be reported by publiclyheld companies as supplemental financial data. These regulations and standards provide for estimates ofProved reserves and revenues discounted at 10% and based on unescalated prices and costs. Revenuesbased on alternate product price scenarios may be reported in addition to the current pricing case. Reportingprobable and possible reserves is optional. Probable and possible reserves must be reported separately fromproved reserves. The Society of Petroleum Engineers (SPE) requires Proved reserves to be economically recoverable with pricesand costs in effect on the “as of” date of the report. In conjunction with the World Petroleum Council (WPC),American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers(SPEE), the SPE has issued Petroleum Resources Management System (2007 ed.), which sets forth thedefinitions and requirements associated with the classification of both reserves and resources. In addition, theSPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information, whichsets requirements for the qualifications and independence of reserve estimators and auditors. The estimated Proved and Probable reserves herein have been prepared in conformance with all SEC, SPE,WPC, AAPG, and SPEE definitions and requirements. Projections – The reserve and revenue projections represented herein are on a calendar year basis, with thefirst time period beginning January 1, 2018 and ending December 31, 2018. Property Discussion Exaro signed an Earning and Development Agreement (EDA) with Encana Oil & Gas (Encana) in April 2012 thatallowed them to gradually obtain increasing levels of ownership in the Jonah field. As part of the EDA, Exaro’sinterest in each well drilled prior to the April 2012 agreement (old Proved Developed Producing (PDP) wells)continued to increase as Encana drilled additional wells (new wells) within the field. Exaro’s interest in the new wellsstayed constant for the life of the well. For each new well drilled within the EDA, Exaro paid for 100% of the capitalcosts and earned 32.5% of Encana’s interest in the new wellbore until Exaro was fully earned into their devotedinterest. In addition, for each new well drilled, Exaro earned 0.40% interest in the old PDP wells and relatedleasehold if Encana’s working interest in the new well location was 100% and a proportional share if not. As of the date of this report, Encana has sold its ownership to Jonah Energy, LLC (Jonah Energy). Exaro notifiedJonah Energy of its intent to terminate the EDA effective May 12, 2014, and thereafter participate under the existingJoint Operating Agreements (JOA’s) going forward. Exaro currently has no locations left under the EDA. All wellsare proposed under the JOA and Exaro has the right to participate for its working interest in each well. At the currenttime, there are no rigs running within Exaro’s acreage. Jonah Energy has several rigs running in the northern part ofthe field close to Exaro’s northern acreage blocks. Jonah Energy has submitted permits for eight vertical locationswithin section 11 and plans to begin drilling these locations in August 2018 according to Exaro. Due to theuncertainty of timing for the remaining locations in Exaro’s acreage, 19 economic vertical locations have beencategorized as Probable with the first one proposed to be drilled in December 2018. Exaro Energy III, LLC – Reserves and Revenues – SEC Year End 2017 Pricing – February 12, 2018 - Page 2 W.D.Von Gonten&Co. Petroleum Engineering Within the Proved Developed Non Producing (PNP) reserves category, Jonah Energy and Exaro have scheduled 42currently producing wells for artificial lift enhancement. The goal is to lower tubing closer to the active perfs of eachwell to more efficiently lift the produced liquids. The total gross cost of each will be approximately $24,750 and theaverage expected reserve uplift around 45 MMcf. W.D. Von Gonten & Co. was able to calculate the reserve upliftbased on wells with tubing lowered in 2016 and 2017. Production in this area is primarily from the Lance sand which can range from 8,000’ to 11,000’ in depth andapproach 3000’ in interval thickness. Exaro has divided the Jonah field into three areas based on location and production performance characteristics.The Updip area covers the western portion of Exaro’s acreage. The Downdip area covers the central and northernacreage. The Antelope area covers the acreage in the eastern portion of the field. Since the signing of the originalEDA, Encana drilled 159 wells in the Jonah field. These wells were spread across the Antelope, Downdip, and Updipareas of the field. W.D. Von Gonten & Co. originally developed three type curves for these areas. Due to anincreasing amount of production history, W.D. Von Gonten & Co. decided to further divide the Updip and Antelopesections into several parts and adjust the type curves as necessary. At the beginning of 2014, Jonah Energy drilled a horizontal well in section 29 of the Antelope area. It is currentlyproducing at a gross rate of 1.64 MMcf/day with an EUR of 8.5 Bcf. Mid 2015, a second horizontal with a longerlateral and more frac stages was drilled to the north of the original horizontal well. The horizontal portion was drilledapproximately 400’ below the original and is only producing at a gross rate of 0.43 MMcf/day. In March 2017, Jonah Energy brought an additional horizontal well online. Exaro has 2.42% working interest in thiswell. This well came online at a gross rate of 11.2 mmcf/day and has an estimated EUR of 9.0 Bcf. Due to theapparent success of the well, Jonah Energy plans to drill additional horizontal locations within the area. Two of theseproposed locations are classified as Proved and have been drilled but are awaiting completion. There arethree additional horizontal locations classified as Probable due to the lack of proximity to production. Starting in February 2015, Jonah Energy began line pressure reduction projects in the field on varying groups ofwells. They started by lowering the pressure from 200 psi to 50 psi in 17 wells located in section 35 and named theproject 10-35. Lowering the pressure caused an increase in the production rate and reserves on most of theconnected wells. Based on provided daily production data, W.D. Von Gonten & Co. was able to give these wells abrief uplift in the production projections. Jonah Energy has since begun and maintained several projects throughoutthe updip and antelope sections. Though other similar projects are reportedly planned, there are no future projectsscheduled in this report. As Exaro is not the operator of the field, and therefore has no control over theimplementation of such projects, intent and/or timing cannot be determined.Exaro Energy III, LLC – Reserves and Revenues – SEC Year End 2017 Pricing – February 12, 2018 - Page 3 W.D.Von Gonten&Co. Petroleum Engineering Figure 1 displays the comparison of Exaro’s historical monthly net production and W.D. Von Gonten & Co.’sforecasted net monthly production beginning January 1, 2018. Figure 1: Historical Net Production and PDP Reserves Forecast as of January 1, 2018 Figure 2 below is a graphical comparison of Exaro’s December 2016 through November 2017 historical net revenueand W.D. Von Gonten & Co.’s forecasted net revenue beginning January 2018. Figure 2: Historical Net Revenue and Forecasted Net Revenue as of January 1, 2018Exaro Energy III, LLC – Reserves and Revenues – SEC Year End 2017 Pricing – February 12, 2018 - Page 4 W.D.Von Gonten&Co. Petroleum Engineering Reserves Discussion Reserves estimates represented herein were generally determined through the implementation of various methodsincluding, but not limited to, performance decline, analogy, and type curve analysis. Based on the amount ofavailable data, one or more of the above methods was utilized as deemed appropriate. Reserves and schedules of production included in this report are only estimates. The amount of available data,reservoir and geological complexity, reservoir drive mechanism, and mechanical aspects can have a material effecton the accuracy of these reserve estimates. Due to inherent uncertainties in future production rates, commodityprices, and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, therevenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts. Product Prices Discussion SEC pricing is determined by averaging the first day of each month’s closing price for the previous calendar yearusing published benchmark oil and gas prices. This method, as applied for the purposes of this report, renders aprice of $51.34 per barrel of oil and $3.02 per MMBtu of gas. These prices were held constant throughout the life ofthe properties as per SEC guidelines. Pricing differentials were applied on a field basis to reflect the actual prices received at the wellhead. Differentialstypically account for transportation costs, geographical differentials, marketing bonuses or deductions, and any otherfactors that may affect the price actually received at the wellhead. W.D. Von Gonten & Co. determined thehistorical pricing differentials from lease operating data provided by Exaro representing the time period of December2016 through November 2017. Figures 3 and 4 illustrate the comparison between historical differentials versus what is being projected. Figure 3: Historical and Forecasted Oil DifferentialExaro Energy III, LLC – Reserves and Revenues – SEC Year End 2017 Pricing – February 12, 2018 - Page 5 W.D.Von Gonten&Co. Petroleum Engineering Figure 4: Historical and Forecasted Gas Differential W.D. Von Gonten & Co. has included the historical NGL revenue and processing fees within the gas price differentialfor the new wells only. Due to existing and new contracts, the old wells do not include any NGL revenue or fees. Operating Expenses and Capital Costs Discussion Projected monthly operating expenses associated with the Jonah properties were based on the review of leaseoperating data provided by Exaro for the time period of December 2016 through November 2017. Using the supplieddata, W.D. Von Gonten & Co. applied a gross direct expense to each well based on its classification of new or old.If the well was involved in a line pressure reduction project, the operating expenses include additional fees. Thehorizontal wells also have an increased monthly expense compared to vertical wells based on historical numbers. Allwells have a gross variable revenue deduct of $0.46 per Mcf which covers gathering fees. In addition, all wells havea gross $4.16/bbl salt water disposal (SWD) variable expense. All direct and variable operating expenses were heldconstant for the economic life of each property. Exaro Energy III, LLC – Reserves and Revenues – SEC Year End 2017 Pricing – February 12, 2018 - Page 6 W.D.Von Gonten&Co. Petroleum Engineering Figure 5 below is a graphical comparison of historical net lease operating expenses for December 2016 throughNovember 2017 versus comparable forecasted expenses for the twelve month calendar year 2018. April and October2017 are irregularly high due to property taxes. Figure 5: Historical and Forecasted Lease Operating Expense Capital costs necessary to perform well completion operations and to drill undeveloped locations were supplied byExaro. These costs were not verified from actual recent work in the area of interest, and therefore W.D. Von Gonten& Co. expresses no warranties as to the accuracy or reasonableness of these assumptions. Other Considerations Abandonment Costs – Cost estimates regarding future plugging and abandonment liabilities associated withthese properties were supplied by Exaro for the purposes of this report. As we have not inspected the propertiespersonally, W.D. Von Gonten & Co. expresses no warranties as to the accuracy or reasonableness of Exaro’sestimates regarding abandonment. A third party study would be necessary in order to accurately estimate allfuture abandonment liabilities. Data Sources – Data furnished by Exaro included basic well information, lease operating statements,ownership, pricing, and production information on certain leases. IHS Energy archives was utilized to view themonthly production for some of the wells included in this report. Context – We specifically advise that any particular reserve estimate for a specific property not be used out ofcontext with the overall report. The revenues and present worth of future net revenues are not representedto be market value either for individual properties or on a total property basis.Exaro Energy III, LLC – Reserves and Revenues – SEC Year End 2017 Pricing – February 12, 2018 - Page 7 W.D.Von Gonten&Co. Petroleum Engineering While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industryparticipant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions whichwould restrict the recovery of the estimated oil and gas volumes represented herein. The reserves in this report canbe produced under current regulatory guidelines. Actual future commodity prices may differ substantially from theutilized pricing scenario which may or may not extend or limit the estimated reserve and revenue quantitiespresented in this report. We have not inspected the properties included in this report, nor have we conducted independent well tests. W.D.Von Gonten & Co. and our employees have no direct ownership in any of the properties included in this report. Ourfees are based on hourly expenses, and are not related to the reserve and revenue estimates produced in thisreport. Thank you for the opportunity to assist Exaro Energy III, LLC with this project. Respectfully submitted, Phillip Hunter, P.E. TX #96590 Jamie Foster Reviewed by: W.D. Von Gonten, Jr., P.E.TX #73244 I:/data/company/reports/client_letters/Miscellaneous\Exaro Energy III - SEC 01-2018.docExaro Energy III, LLC – Reserves and Revenues – SEC Year End 2017 Pricing – February 12, 2018 - Page 8
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