Diamondback Energy
Annual Report 2017

Plain-text annual report

Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 FORM 10-K ýANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2017 OR¨TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934Commission File Number 001-35700 Diamondback Energy, Inc.(Exact Name of Registrant As Specified in Its Charter) Delaware 45-4502447(State or Other Jurisdiction ofIncorporation or Organization) (IRS EmployerIdentification Number) 500 West Texas, Suite 1200Midland, Texas 79701(Address of Principal Executive Offices) (Zip Code)(Registrant Telephone Number, Including Area Code): (432) 221-7400 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of Each Exchange on WhichRegistered Common Stock, par value$0.01 per share The Nasdaq Stock Market LLC 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 ý 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 ýIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and postedpursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post suchfiles). Yes ý No ¨Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to 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 Form 10-K. ýIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.Large Accelerated Filer ý Accelerated Filer ¨Non-Accelerated Filer ¨ Smaller Reporting Company ¨ Emerging Growth Company oIf an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Exchange Act. oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ýAggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2017 was approximately $7,801,460,276.As of February 7, 2018, 98,167,289 shares of the registrant’s common stock were outstanding.DOCUMENTS INCORPORATED BY REFERENCEPortions of Diamondback Energy, Inc.’s Proxy Statement for the 2018 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of thisForm 10-K DIAMONDBACK ENERGY, INC.FORM 10-KFOR THE YEAR ENDED DECEMBER 31, 2017TABLE OF CONTENTS PageGlossary of Oil and Natural Gas TermsiiGlossary of Certain Other TermsvCautionary Statement Regarding Forward-Looking Statementsvi PART IItems 1 and 2. Business and Properties1Item 1A. Risk Factors21Item 1B. Unresolved Staff Comments45Item 3. Legal Proceedings45Item 4. Mine Safety Disclosures45 PART IIItem 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities46Item 6. Selected Financial Data47Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations49Item 7A. Quantitative and Qualitative Disclosures about Market Risk70Item 8. Financial Statements and Supplementary Data71Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure71Item 9A. Controls and Procedures71Item 9B. Other Information74 PART IIIItem 10. Directors, Executive Officers and Corporate Governance74Item 11. Executive Compensation74Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters74Item 13. Certain Relationships and Related Transactions, and Director Independence74Item 14. Principal Accountant Fees and Services74 PART IVItem 15. Exhibits and Financial Statement Schedules74Item 16. Form 10-K Summary80SignaturesS-1GLOSSARY OF OIL AND NATURAL GAS TERMSThe following is a glossary of certain oil and natural gas industry terms used in this report:3-D seismicGeophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a moredetailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.BasinA large depression on the earth’s surface in which sediments accumulate.BblStock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquidhydrocarbons.Bbls/dBarrels per day.BOEBarrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.BOE/dBarrels of oil equivalent per day.BrentBrent sweet light crude oil.British Thermal Unit or BTUThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.CompletionThe process of treating a drilled well followed by the installation of permanent equipment for the productionof natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.CondensateLiquid hydrocarbons associated with the production that is primarily natural gas.Crude oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.Developed acreageAcreage assignable to productive wells.Development costsCapital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.DifferentialAn adjustment to the price of oil or natural gas from an established spot market price to reflect differences inthe quality and/or location of oil or natural gas.Dry hole or dry wellA well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from thesale of such production exceed production expenses and taxes.Estimated Ultimate Recovery or EUREstimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production asof that date.ExploitationA development or other project which may target proven or unproven reserves (such as probable or possiblereserves), but which generally has a lower risk than that associated with exploration projects.FieldAn 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.Finding and development costsCapital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reservesdivided by proved reserve additions and revisions to proved reserves.FracturingThe process of creating and preserving a fracture or system of fractures in a reservoir rock typically byinjecting a fluid under pressure through a wellbore and into the targeted formation.Gross acres or gross wellsThe total acres or wells, as the case may be, in which a working interest is owned.Horizontal drillingA drilling technique used in certain formations where a well is drilled vertically to a certain depth and thendrilled at a right angle with a specified interval.Horizontal wellsWells drilled directionally horizontal to allow for development of structures not reachable throughtraditional vertical drilling mechanisms.MBblsThousand barrels of crude oil or other liquid hydrocarbons.MBOEOne thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl ofcrude oil, condensate or natural gas liquids.McfThousand cubic feet of natural gas.Mcf/dThousand cubic feet of natural gas per day.Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from theextracted resources.MMBtuMillion British Thermal Units.MMcfMillion cubic feet of natural gas.iiNet acres or net wellsThe sum of the fractional working interest owned in gross acres.Net revenue interestAn owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overridinginterests.Net royalty acresGross acreage multiplied by the average royalty interest.Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.OperatorThe individual or company responsible for the exploration and/or production of an oil or natural gas well orlease.PlayA set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographicand temporal properties, such as source rock, reservoir structure, timing, trapping mechanism andhydrocarbon type.Plugging and abandonmentRefers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will notescape into another or to the surface. Regulations of all states require plugging of abandoned wells.PUDProved undeveloped.Productive wellA well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds fromthe sale of the production exceed production expenses and taxes.ProspectA 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 forthe discovery of commercial hydrocarbons.Proved developed reservesReserves that can be expected to be recovered through existing wells with existing equipment and operatingmethods.Proved reservesThe estimated quantities of oil, natural gas and natural gas liquids which geological and engineering datademonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirsunder existing economic and operating conditions.Proved undeveloped reservesProved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wellswhere a relatively major expenditure is required for recompletion.RecompletionThe process of re-entering an existing wellbore that is either producing or not producing and completing newreservoirs in an attempt to establish or increase existing production.ReservesReserves are estimated remaining quantities of oil and natural gas and related substances anticipated to beeconomically producible, as of a given date, by application of development projects to knownaccumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist,the legal right to produce or a revenue interest in the production, installed means of delivering oil and naturalgas or related substances to the market and all permits and financing required to implement the project.Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults untilthose reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned toareas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence ofreservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources(i.e., potentially recoverable resources from undiscovered accumulations).ReservoirA porous and permeable underground formation containing a natural accumulation of producible natural gasand/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.Resource playA set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographicand temporal properties, such as source rock, reservoir structure, timing, trapping mechanism andhydrocarbon type.Royalty interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having tocarry any costs of development or operations.SpacingThe distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres(e.g., 40-acre spacing) and is often established by regulatory agencies.Stratigraphic playAn oil or natural gas formation contained within an area created by permeability and porosity changescharacteristic of the alternating rock layer that result from the sedimentation process.Structural playAn oil or natural gas formation contained within an area created by earth movements that deform or rupture(such as folding or faulting) rock strata.Tight formationA formation with low permeability that produces natural gas with very low flow rates for long periods of time.iiiUndeveloped acreageLease acreage on which wells have not been drilled or completed to a point that would permit the productionof economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.Working interestAn operating interest that gives the owner the right to drill, produce and conduct operating activities on theproperty and receive a share of production and requires the owner to pay a share of the costs of drilling andproduction operations.WTIWest Texas Intermediate.ivGLOSSARY OF CERTAIN OTHER TERMSThe following is a glossary of certain other terms that are used in this report.2012 PlanThe Company’s 2012 Equity Incentive Plan.BisonBison Drilling and Field Services, LLC.CompanyDiamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.EPAU.S. Environmental Protection Agency.Exchange ActThe Securities Exchange Act of 1934, as amended.FERCFederal Energy Regulatory Commission.GAAPAccounting principles generally accepted in the United States.General PartnerViper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.2024 IndentureThe indenture relating to the 2024 Senior Notes, dated as of October 28, 2016, among the Company, the subsidiaryguarantors party thereto and Wells Fargo, as the trustee, as supplemented.2025 IndentureThe indenture relating to the 2025 Senior Notes, dated as of December 20, 2016, among the Company, the subsidiaryguarantors party thereto and Wells Fargo, as the trustee, as supplemented.NYMEXNew York Mercantile Exchange.OSHAFederal Occupational Safety and Health Act.PartnershipViper Energy Partners LP, a Delaware limited partnership.Partnership agreementThe first amended and restated agreement of limited partnership, dated as of June 23, 2014, entered into by the GeneralPartner and Diamondback in connection with the closing of the Viper Offering.Ryder ScottRyder Scott Company, L.P.SECSecurities and Exchange Commission.Securities ActThe Securities Act of 1933, as amended.2024 Senior NotesThe Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $500 million.2025 Senior NotesThe Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $500 million.Senior NotesThe 2024 Senior Notes and the 2025 Senior Notes.ViperViper Energy Partners L.P.Viper LTIPViper Energy Partners L.P. Long Term Incentive Plan.Viper OfferingThe Partnerships’ initial public offering.Wells FargoWells Fargo Bank, National Association.vCAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTSVarious statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. These forward-lookingstatements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact,regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of managementare forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,”“predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statementscontain such identifying words. In particular, the factors discussed in this Annual Report on Form 10–K, including under Part I, Item 1A. “Risk Factors” inthis report, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted orimplied in such forward-looking statements.Forward-looking statements may include statements about our:•business strategy;•exploration and development drilling prospects, inventories, projects and programs;•oil and natural gas reserves;•acquisitions•identified drilling locations;•ability to obtain permits and governmental approvals;•technology;•financial strategy;•realized oil and natural gas prices;•production;•lease operating expenses, general and administrative costs and finding and development costs;•future operating results; and•plans, objectives, expectations and intentions.All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaimany obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a verycompetitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can weassess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially fromthose contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggestedby the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will beachieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.viPART IExcept as noted, in this Annual Report on Form 10-K, we refer to Diamondback, together with its consolidated subsidiaries, as “we,” “us,” “our,”or “the Company”. This report includes certain terms commonly used in the oil and gas industry, which are defined above in the “Glossary of Oil andNatural Gas Terms.”ITEM 1. BUSINESS AND PROPERTIESOverviewWe are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional,onshore oil and natural gas reserves in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, ischaracterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons,enhanced recovery potential and a large number of operators.We began operations in December 2007 with our acquisition of 4,174 net acres in the Permian Basin. At December 31, 2017, our total acreageposition in the Permian Basin was approximately 246,012 gross (206,660 net) acres. In addition, we, through our subsidiary Viper Energy Partners LP, orViper, own mineral interests underlying approximately 247,602 gross acres, 43,843 net acres and 9,570 net royalty acres primarily in Midland County, Texasin the Permian Basin. Approximately 36% of these net royalty acres are operated by us. We own Viper Energy Partners GP LLC, the general partner of Viper,which we refer to as the general partner, and we own approximately 64% of the limited partner interest in Viper.Our activities are primarily focused on horizontal development of the Spraberry and Wolfcamp formations of the Midland Basin and the Wolfcampand Bone Spring formations of the Delaware Basin, both of which are part of the larger Permian Basin in West Texas and New Mexico. The Permian Basin ischaracterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves andhigh drilling success rates.As of December 31, 2017, our estimated proved oil and natural gas reserves were 335,352 MBOE (which includes estimated reserves of 38,246MBOE attributable to the mineral interests owned by Viper), based on reserve reports prepared by Ryder Scott Company, L.P., or Ryder Scott, ourindependent reserve engineers. Of these reserves, approximately 62.2% are classified as proved developed producing. Proved undeveloped, or PUD, reservesincluded in this estimate are from 168 gross (142 net) horizontal well locations in which we have a working interest, and nine horizontal wells in which weown only a mineral interest through our subsidiary, Viper. As of December 31, 2017, our estimated proved reserves were approximately 70% oil, 14% naturalgas liquids and 16% natural gas.Based on our evaluation of applicable geologic and engineering data, we currently have approximately 3,800 gross (2,750 net) identified economicpotential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $60.00 per Bbl WTI. We intend to continueto develop our reserves and increase production through development drilling and exploitation and exploration activities on this multi-year projectinventory of identified potential drilling locations and through additional acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.The challenging commodity price environment that we experienced in 2016 continued in 2017. Commodity prices improved during 2017, butcontinued to be volatile. Nevertheless, we believe we remain well-positioned in this environment. During 2017, we again demonstrated our operational focuson achieving best-in-class execution, low-cost operations and a conservative balance sheet as we continued to reduce drilling days, well costs and operatingexpenses while maintaining what we believe to be a peer leading leverage ratio. We intend to continue our operational focus in 2018, emphasizing full cycleeconomics and financial discipline. We are operating ten rigs now and currently intend to operate between ten and twelve rigs in 2018, depending on marketconditions. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling andcompletion plans in response to market conditions. We are prepared to decelerate our drilling program if commodity prices deteriorate and continue toaccelerate our drilling program should commodity prices remain constant or further improve. We have the option to release up to eight of our current ten rigsin 2018 should commodity prices deteriorate. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”1Our Business StrategyOur business strategy is to continue to profitably grow our business through the following:•Grow production and reserves by developing our oil-rich resource base. We intend to drill and develop our acreage base in an effort tomaximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increaseour production, reserves and cash flow while generating favorable returns on invested capital.•Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We have targeted various intervals in theMidland Basin through horizontal drilling and believe that there are opportunities to target additional intervals throughout the stratigraphiccolumn. Our initial horizontal focus had been on the Wolfcamp B interval, but our recent focus has included the Lower Spraberry, MiddleSpraberry and Wolfcamp A intervals. Our first two horizontal wells were completed in 2012 and had lateral lengths of less than 4,000 feet. As ofDecember 31, 2017, we had drilled 412 horizontal wells as operator and had participated in 61 additional horizontal wells as a non-operator,including two in which we own only a minor wellbore interest. We also acquired interest in 76 horizontal wells on properties we purchased. Ofthese 549 total horizontal wells, 466 had been completed and were on production. Of the 466 horizontal wells on production, 152 are in theWolfcamp B interval, 122 are in the Wolfcamp A interval, 163 are in the Lower Spraberry interval, nine are in the Middle Spraberry interval,three are in the Cline interval, three are in the Clearfork interval, seven are in the Bone Spring interval and seven are in various other intervals.These wells have lateral lengths ranging from approximately 2,100 feet to 13,000 feet. In 2018, we expect that our average lateral length will beabout 9,300 feet, although the actual length will vary depending on the layout of our acreage and other factors. As technology continues toimprove, we expect that our average lateral length will increase, resulting in higher per well recoveries and lower development costs per BOE.During the year ended December 31, 2017, we were able to drill our horizontal wells in the Midland Basin with approximately 7,500 foot laterallengths to total depth, or TD, in an average of 12.2 days and we drilled approximately 10,000 foot lateral wells in 14.5 days. Further advances indrilling and completion technology may result in economic development of zones that are not currently viable.•Leverage our experience operating in the Permian Basin. Our executive team, which has an average of over 25 years of industry experienceper person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining andenhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of thecontinuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that theexperience of our executive team in deviated and horizontal drilling and completions has helped reduce the execution risk normally associatedwith these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulicfracturing practices that have and are expected to continue to increase recovery and reduce completion costs. Our executive team regularlyevaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performingoperators and evaluate and adopt best practices.•Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements inoperational and cost efficiencies. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop thisacreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluidhandling facilities. We are the operator of approximately 84% of our acreage. This operational control allows us to manage more efficiently thepace of development activities and the gathering and marketing of our production and control operating costs and technical applications,including horizontal development. Our average 84% working interest in our acreage allows us to realize the majority of the benefits of theseactivities and cost efficiencies.•Pursue strategic acquisitions with substantial resource potential. We have a proven history of acquiring leasehold positions in the PermianBasin that have substantial oil-weighted resource potential. Our executive team, with its extensive experience in the Permian Basin, has what webelieve is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly reviewacquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets. During the year ended December 31,2017, we acquired approximately 99,830 gross (84,468 net) leasehold acres primarily in Pecos and Reeves counties in the Southern DelawareBasin.2•Maintain financial flexibility. We seek to maintain a conservative financial position. In connection with our fall 2017 borrowing baseredetermination, the agent lender under our revolving credit agreement recommended a borrowing base of $1.8 billion. We elected acommitment amount of $1.0 billion, of which $603.0 million was available for borrowing as of December 31, 2017. As of December 31, 2017,Viper had $93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility.Our StrengthsWe believe that the following strengths will help us achieve our business goals:•Oil rich resource base in one of North America’s leading resource plays. All of our leasehold acreage is located in one of the most prolific oilplays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the PermianBasin. Our production for the year ended December 31, 2017 was approximately 74% oil, 14% natural gas liquids and 12% natural gas. As ofDecember 31, 2017, our estimated net proved reserves were comprised of approximately 70% oil, 14% natural gas liquids and 16% natural gas.•Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potentialdrilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price ofapproximately $60.00 per Bbl WTI, we currently have approximately 3,800 gross (2,750 net) identified economic potential horizontal drillinglocations on our acreage based on our evaluation of applicable geologic and engineering data. These gross identified economic potentialhorizontal locations have an average lateral length of approximately 8,400 feet, with the actual length depending on lease geometry and otherconsiderations. These locations exist across most of our acreage blocks and in multiple horizons. Of these 3,800 locations, 2,100 are in theMidland Basin and 1,700 are in the Delaware Basin. In the Midland Basin, 860 are in the Lower Spraberry or Wolfcamp B horizons where wehave drilled a large number of wells, 825 are in the Wolfcamp A or Middle Spraberry horizons where we have drilled a limited number of wellsand 415 are in the Clearfork or Cline horizons where we have drilled very few wells. Our current location count for the Lower Spraberry horizonis based on 660 foot spacing in f Midland, southwest Martin, northeast Andrews, Howard and Glasscock counties, and 880 foot spacing in allother counties. For the Wolfcamp B horizon, the horizontal location count is based on 660 foot spacing between wells in Midland, Martin,northeast Andrews, Howard, and Glasscock counties, and 880 foot spacing in all other counties. In the Wolfcamp A horizon, the horizontallocation count in based on 660 foot spacing in Midland, Howard and Glasscock counties, 880 foot spacing in southwest Martin county and1,320 foot spacing in other counties. The horizontal location count for the Middle Spraberry is based on 880 foot spacing in Midland, Martinand northeast Andrews counties and 1,320 foot spacing in other counties. In the Cline and Clearfork horizons, the horizontal location count isbased on 1,320 foot spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. In the Delaware Basin,1,240 locations are in the Wolfcamp A or Wolfcamp B horizons, and 460 locations are in the 2nd Bone Spring or 3rd Bone Spring horizon. Thehorizontal location counts are based on 880 foot spacing in the Wolfcamp A and Wolfcamp B horizons, and 1,320 foot spacing in the BoneSpring horizons. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lowerlocation count. The two-stream gross estimated ultimate recoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scottas of December 31, 2017, range from 528 MBOE per well, consisting of 413 MBbls of oil and 687 MMcf of natural gas, to 1,665 MBOE perwell, consisting of 1,307 MBbls of oil and 2,150 MMcf of natural gas, for wells ranging in lateral length from approximately 5,000 feet toapproximately 12,500 feet, in intervals including the Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B. Ryder Scott hasestimated gross EURs of 910 MBOE for our Lower Spraberry wells in Midland County and 1,071 MBOE for our Wolfcamp A wells in PecosCounty, which constitute 36% of our remaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. In addition, we haveapproximately 1,837 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existingdrilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategicleasehold acquisitions.•Experienced, incentivized and proven management team. Our executive team has an average of over 25 years of industry experience perperson, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig developmentdrilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drillingand completing horizontal wells in addition to horizontal well reservoir and geologic expertise, which is of strategic importance as we expandour horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, LaredoPetroleum Holdings, Inc. and Burlington Resources.3•Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the longestoperating hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. Webelieve that the geological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with lessoperational risks in the Permian Basin as compared to emerging hydrocarbon basins.•High degree of operational control. We are the operator of approximately 84% of our Permian Basin acreage. This operating control allows usto better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recoveryby seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as theoperator of substantially all of our acreage, we retain the ability to increase or decrease our capital expenditure program based on commodityprice outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.Our PropertiesLocation and LandOur total acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres at December 31, 2017. We are the operator ofapproximately 84% of this Permian Basin acreage. In addition, we, through our subsidiary Viper, own mineral interests underlying approximately 247,602gross acres, 43,843 net acres and 9,570 net royalty acres primarily in the Permian Basin. Approximately 36% of these net royalty acres are operated by us.Since our initial acquisition in the Permian Basin through December 31, 2017, we drilled or participated in the drilling of 753 gross (608 net) wells on ourleasehold acreage in this area, primarily targeting the Wolfberry play. The Permian Basin area covers a significant portion of western Texas and eastern NewMexico and is considered one of the major producing basins in the United States.Area HistoryOur proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Bone Spring, Wolfcamp, Cline, Strawnand Atoka formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It waseventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin.Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependenton oil prices and drilling costs.The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionallyintersected slump blocks or debris flows with good reservoir properties. Exploration using 2-D seismic data located additional fields, but it was not until theuse of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within thisformation as reservoir rather than just source rocks was not recognized until very recently.During the late 1990s, Atlantic Richfield Company, or Arco, began a drilling program targeting the base of the Spraberry formation at 10,000 feet,with an additional 200 to 300 feet drilled to produce from the upper portion of the Wolfcamp formation. Henry Petroleum, a private firm, owned interests inthe Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely throughthe Wolfcamp section. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracturing treatmentsacross the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, andbegan replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they monetized a portion oftheir acreage position, which led to the acquisition that enabled us to begin our participation in this play. Recent advancements in enhanced recoverytechniques and horizontal drilling continue to make this play attractive to the oil and gas industry. By mid-2010, approximately half of the rigs active in thePermian Basin were drilling wells in the Wolfberry play. As of December 31, 2017, we held working interests in 1,166 gross (937 net) producing wells androyalty interests in 64 additional wells.GeologyThe Permian Basin formed as an area of rapid Pennsylvanian-Permian subsidence in response to dynamic structural influence. It is one of the largestsedimentary basins in the U.S., with established oil and gas production from several reservoirs from Permian through Ordovician in age. The term “Wolfberry”was coined initially to indicate commingled production from4the Permian Spraberry, Dean and Wolfcamp formations. Time equivalent in the Delaware Basin, the “Wolfbone” play describes vertically commingledproduction from the Permian Bone Spring and Wolfcamp formations.The Spraberry/Bone Spring was deposited as siliciclastic turbidites in a deep water submarine fan environment, while the Wolfcamp reservoirsconsist of debris-flow and grain-flow sediments, which were also deposited in a submarine fan setting. The best carbonate reservoirs within the Wolfcamp aregenerally found in proximity to the Central Basin Platform, while the shale reservoirs within the Wolfcamp thicken basinward away from the Central BasinPlatform. Both the Spraberry/Bone Spring and Wolfcamp contain organic-rich mudstones and shales which, when buried to sufficient depth for maturation,became the source of the hydrocarbons found both within the shales themselves and in the more conventional clastic and carbonate reservoirs between theshales. The Wolfberry and Wolfbone are unconventional “basin-centered oil” resource plays, in the sense that there is no regional downdip oil/water contact. We have successfully developed several shale intervals within the Clearfork, Spraberry/Bone Spring and Wolfcamp formations since we beganhorizontal drilling in 2012. The shales exhibit low permeabilities which necessitate the need for hydraulic fracture stimulation to unlock the vast storage ofhydrocarbons in these targets.We possess, or are in the process of acquiring, 3-D seismic data over substantially all of our major asset areas. Our extensive geophysical databasecurrently includes approximately 1,837 square miles of 3-D data. This data will continue to be utilized in the development of our horizontal drilling programand identification of additional resource to be exploited.Production StatusDuring the year ended December 31, 2017, net production from our Permian Basin acreage was 28,917 MBOE, or an average of 79,224 BOE/d, ofwhich approximately 74% was oil, 14% was natural gas liquids and 12% was natural gas.FacilitiesOur oil and natural gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include storagetank batteries, oil/natural gas/water separation equipment and pumping units.Recent and Future ActivityDuring 2018, we expect to complete an estimated 170 to 190 gross (146 to 163 net) horizontal wells on our acreage. We currently estimate that ourcapital expenditures in 2018 for drilling and infrastructure will be between $1.3 billion and $1.5 billion, consisting of $1.175 billion to $1.325 billion forhorizontal drilling and completions including non-operated activity and $125.0 million to $175.0 million for infrastructure and other expenditures, butexcluding the cost of any leasehold and mineral rights acquisitions. During the year ended December 31, 2017, we drilled 150 gross (130 net) and completed123 gross (105 net) horizontal wells, including five drilled but uncompleted wells we acquired. We participated in the drilling of 16 gross (two net) non-operated horizontal wells in the Permian Basin. During the year ended December 31, 2017, our capital expenditures for drilling, completing and equippingwells were $719.3 million. In addition, we spent $124.0 million for oil and gas infrastructure, $17.4 million for non-operated properties and $2.4 billion forleasehold and mineral rights acquisitions.We are operating ten rigs now and currently intend to operate between ten and twelve rigs in 2018, depending on market conditions. We willcontinue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans inresponse to market conditions. We are prepared to decelerate our drilling program if commodity prices deteriorate and continue to accelerate our drillingprogram should commodity prices remain constant or further improve. We have the option to release up to eight of our current ten rigs in 2018 shouldcommodity prices deteriorate.Oil and Natural Gas DataProved ReservesEvaluation and Review of ReservesOur historical reserve estimates as of December 31, 2017, 2016 and 2015 were prepared by Ryder Scott with respect to our assets and those of Viper.Ryder Scott is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet therequirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating andAuditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does notown an interest in any of our properties and is not employed by us on a contingent basis.5Under SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimatedwith reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions,operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates thatrenewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, theSEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves asof December 31, 2017 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determinationresults in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated withthose estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gasreserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods:(1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserveevaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or acombination of both methods. Approximately 83% of the proved producing reserves attributable to producing wells were estimated by performance methods.These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production andpressure data. The remaining 17% of the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. Theanalogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of productionperformance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves wereestimated by the analogy method.To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions,including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteriabased on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to ourestimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data,downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost andoperating expense data.We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers toensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internaltechnical team members met with our independent reserve engineers periodically during the period covered by the reserve reports to discuss the assumptionsand methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such asownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our Executive Vice President–ReservoirEngineering is primarily responsible for overseeing the preparation of all of our reserve estimates. Our Executive Vice President–Reservoir Engineering is apetroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 24 years of industryexperience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data,commodity prices and operating and development costs.The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which areintended to ensure reliability of reserve estimations, include the following:•review and verification of historical production data, which data is based on actual production as reported by us;•preparation of reserve estimates by our Executive Vice President–Reservoir Engineering or under his direct supervision;•review by our Executive Vice President–Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including thereview of all significant reserve changes and all new proved undeveloped reserves additions;•direct reporting responsibilities by our Executive Vice President–Reservoir Engineering to our Chief Executive Officer;•verification of property ownership by our land department; and•no employee’s compensation is tied to the amount of reserves booked.6The following table presents our estimated net proved oil and natural gas reserves as of December 31, 2017, 2016 and 2015 (including thoseattributable to Viper), based on the reserve reports prepared by Ryder Scott. Each reserve report has been prepared in accordance with the rules andregulations of the SEC. All of our proved reserves included in the reserve reports are located in the continental United States. December 31, 2017 2016 2015Estimated proved developed reserves: Oil (MBbls)141,246 79,457 60,569Natural gas (MMcf)190,740 105,399 96,871Natural gas liquids (MBbls)35,412 22,080 15,418Total (MBOE)208,447 119,104 92,132Estimated proved undeveloped reserves: Oil (MBbls)91,935 59,717 45,409Natural gas (MMcf)94,629 69,497 52,632Natural gas liquids (MBbls)19,198 15,054 10,586Total (MBOE)126,905 86,354 64,767Estimated Net Proved Reserves: Oil (MBbls)233,181 139,174 105,979Natural gas (MMcf)285,369 174,896 149,503Natural gas liquids (MBbls)54,610 37,134 26,004Total (MBOE)(1)335,352 205,458 156,899Percent proved developed62.2% 58.0% 58.7%(1)Estimates of reserves as of December 31, 2017, 2016 and 2015 were prepared using an average price equal to the unweighted arithmetic average ofhydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2017, 2016 and2015, respectively, in accordance with SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not includeany value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent ournet revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, developmentexpenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes ofeconomically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality ofavailable data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling,testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that areultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables andassumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A.“RiskFactors.” We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.Proved Undeveloped Reserves (PUDs)As of December 31, 2017, our proved undeveloped reserves totaled 91,935 MBbls of oil, 94,629 MMcf of natural gas and 19,198 MBbls of naturalgas liquids, for a total of 126,905 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.7The following table includes the changes in PUD reserves for 2017: (MBOE)Beginning proved undeveloped reserves at December 31, 201686,354Undeveloped reserves transferred to developed(31,666)Revisions(4,710)Net purchases6,246Extensions and discoveries70,680Ending proved undeveloped reserves at December 31, 2017126,904The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676 MBOE from 87 gross (75 net) wells in which wehave a working interest and 3,004 MBOE from 40 gross wells in which Viper owns royalty interests. Of the 87 gross wells, 26 were in the Delaware Basin.Transfers of 31,666 MBOE were the result of drilling or participating in 44 gross (37 net) horizontal wells in which we have a working interest and 27 grosswells in which we have a royalty interest or mineral interest through Viper. We own a working interest in 23 of the 27 gross Viper wells. Net purchases of6,246 MBOE were primarily from our purchase in Pecos and Reeves counties. Downward revisions of 4,710 MBOE resulted from reclassification of sevenlocations and technical revisions.Costs incurred relating to the development of PUDs were approximately $145.4 million during 2017. Estimated future development costs relating tothe development of PUDs are projected to be approximately $595.4 million in 2018, $205.6 million in 2019, $171.2 million in 2020 and $58.3 million in2021. Since our current executive team assumed management control in 2011, our average drilling costs and drilling times have been reduced. As wecontinue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experiencelower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.As of December 31, 2017, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initiallyrecorded.As of December 31, 2017, none of our total proved reserves were classified as proved developed non-producing.8Oil and Natural Gas Production Prices and Production CostsProduction and Price HistoryThe following table sets forth information regarding our net production of oil, natural gas and natural gas liquids, all of which is from the PermianBasin in West Texas, and certain price and cost information for each of the periods indicated: Year Ended December 31, 2017 2016 2015Production Data: Oil (MBbls)21,418 11,562 9,081Natural gas (MMcf)20,660 10,728 7,931Natural gas liquids (MBbls)4,056 2,399 1,678Combined volumes (MBOE)28,917 15,749 12,081Daily combined volumes (BOE/d)79,224 43,031 33,098 Average Prices: Oil (per Bbl)$48.75 $40.70 $44.68Natural gas (per Mcf)2.53 2.10 2.47Natural gas liquids (per Bbl)22.20 14.20 12.77Combined (per BOE)41.02 33.47 36.98Oil, hedged ($ per Bbl)(1)48.94 40.80 60.63Natural gas, hedged ($ per MMbtu)(1)2.65 2.06 2.47Average price, hedged ($ per BOE)(1)41.26 33.54 48.97 Average Costs per BOE: Lease operating expense$4.38 $5.23 $6.84Production and ad valorem taxes2.54 2.19 2.73Gathering and transportation expense0.44 0.74 0.50General and administrative - cash component0.80 1.03 1.11Total operating expense - cash8.16 9.19 11.18 General and administrative - non-cash component0.88 1.68 1.54Depreciation, depletion and amortization11.30 11.30 18.02Interest expense1.40 2.58 3.44Total expenses$13.58 $15.56 $23.00(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realizedgains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.Productive WellsAs of December 31, 2017, we owned an average unweighted 80% working interest in 1,166 gross (937 net) productive wells and an average 2.7%royalty interest in 64 additional wells. Through our subsidiary Viper, we own an average unweighted 9.2% royalty or mineral interest in 1,287 productivewells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commencedeliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and netwells are the sum of our fractional working interests owned in gross wells.9AcreageThe following table sets forth information as of December 31, 2017 relating to our leasehold acreage: Developed Acreage(1) Undeveloped Acreage(2) Total Acreage(3)BasinGross(4) Net(5) Gross(4) Net(5) Gross(4) Net(5)Delaware58,444 49,919 69,982 54,800 128,426 104,719Midland84,325 69,641 33,261 32,300 117,586 101,941Total142,769 119,560 103,243 87,100 246,012 206,660(1)Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease.Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in asingle horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.(2)Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities ofoil or natural gas, regardless of whether such acreage contains proved reserves.(3)Does not include Viper’s mineral interests but does include leasehold acres that we own underlying our mineral interests.(4)A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.(5)A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum ofthe fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.Undeveloped acreage expirationsMany of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unlessproduction from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production.The following table sets forth the gross and net undeveloped acreage, as of December 31, 2017, that will expire over the next five years unless production isestablished within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary termexpiration dates. 2018 2019 2020 2021 2022BasinGross Net Gross Net Gross Net Gross Net Gross NetDelaware28,572 22,198 31,091 19,415 13,097 1,286 3,639 719 — —Midland897 715 908 255 19,678 18,933 — — — —Total29,469 22,913 31,999 19,670 32,775 20,219 3,639 719 — —10Drilling ResultsThe following table sets forth information with respect to the number of wells completed during the periods indicated. Each of these wells wasdrilled in the Permian Basin of West Texas. The information should not be considered indicative of future performance, nor should it be assumed that there isnecessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those thatproduce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. Year Ended December 31, 2017 2016 2015 Gross Net Gross Net Gross NetDevelopment: Productive27 23 6 3 8 6Dry— — — — — —Exploratory: Productive112 84 82 62 71 57Dry— — — — — —Total: Productive139 107 88 65 79 63Dry— — — — — —As of December 31, 2017, we had 83 gross (66 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure thatare not reflected in the above table.Title to PropertiesAs is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties. At such time as wedetermine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significantdefects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we aretypically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured anymaterial title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactorytitle to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition ofproducing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain atitle opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject tocustomary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect ourcarrying value of the properties.Marketing and CustomersWe typically sell production to a relatively small number of customers, as is customary in the exploration, development and production business.For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply& Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of ourrevenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31,2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No othercustomer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasing oil and natural gas from us,revenue could decline and our operating results and financial condition could be harmed.We have entered into an oil purchase agreement with Shell Trading (US) Company in which we agreed to sell specified quantities of oil to ShellTrading (US) Company. Our agreement with Shell Trading (US) Company has an initial term of five years ending September 30, 2018. The agreement mayalso be terminated by Shell Trading (US) Company by written notice to us in the event that Shell Trading (US) Company’s contract for transportation on thepipeline is terminated. Our maximum delivery obligation under this agreement is 8,000 gross barrels per day. We have a one-time right to elect to decreasethe contract quantity by not more than 20% of the then-current quantity. This decreased contract quantity, if elected, would be effective for11the remainder of the term of the agreement. Shell Trading (US) Company has agreed to pay to us the price per barrel of oil based on the arithmetic average ofthe daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, as adjusted basedon adjustment formulas specified in the agreement. If we fail to deliver the required quantities of oil under the agreement during any three-month periodfollowing the service commencement date, we have agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying(i) the volume of oil that we failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect fortransportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated.CompetitionThe oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of thesecompanies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and otherproducts on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratoryprospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition,these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or moreintegrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than wecan, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will bedependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition,because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratoryprospects and producing oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarilybased on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other formsof energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy mayaffect the demand for oil and natural gas.TransportationDuring the initial development of our fields we evaluate all gathering and delivery infrastructure in the areas of our production. Currently, a majorityof our production in the Midland Basin is transported to purchasers by pipeline. We anticipate that our production in the Delaware Basin transported topurchasers by pipeline will increase to 80% by the end of 2018. During 2018, several oil and saltwater disposal gathering systems were installed. We believethat these gathering systems will help us reduce our lease operating expense and improve our margins on sales in future periods. The following table presents the average percentage of produced oil sold by pipeline and the average percentage of produced water connected tosaltwater disposals by pipeline: Midland Basin Delaware Basin Total% of produced oil sold by pipeline93% 22% 80%% of produced water connected to pipeline93% 87% 91%The following table presents the average cost per Bbl to transport produced oil and water by truck and by pipeline as well as the average savings oftransporting produced oil and water by pipeline versus truck: Midland Basin Delaware BasinOil transportation costs per Bbl: Trucked$1.84 $2.28Pipeline$1.09 $1.31Average savings$0.75 $0.97 Water transportation costs per Bbl: Trucked$2.08 $1.86Pipeline$0.23 $0.39Average savings$1.85 $1.4712Oil and Natural Gas LeasesThe typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil andnatural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from12.50% to 25.00%, resulting in a net revenue interest to us generally ranging from 75.00% to 87.50%.Seasonal Nature of BusinessGenerally, demand for oil increases during the summer months and decreases during the winter months while natural gas decreases during thesummer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipatedwinter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit ourdrilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challengesfor meeting our well drilling objectives and can increase competition for equipment, supplies and personnel during the spring and summer months, whichcould lead to shortages and increase costs or delay operations.RegulationOil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted bygovernmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion.Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost ofdoing business and, consequently, affects our profitability.Environmental Matters and RegulationOur oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge ofmaterials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the EPA,issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may resultin injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict thetypes, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities,limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and otherprotected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result inthe suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantialliabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict(i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to fileclaims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into theenvironment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control orwaste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oiland natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations andwe have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in thefuture.Waste Handling. The Resource Conservation and Recovery Act, as amended, and comparable state statutes and regulations promulgated thereunder,affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment,storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions ofthe Resource Conservation and Recovery Act, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated withthe exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the Resource Conservationand Recovery Act, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA orstate or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes ashazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration,development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil andgas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the laws and regulations could have a materialadverse effect on our capital expenditures and operating expenses.13Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are insubstantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and otherauthorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing ourwastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes couldincrease our costs to manage and dispose of such wastes.Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we referto as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, onclasses of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the currentowner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed orarranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” aresubject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (includingwastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to naturalresources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims forpersonal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we usematerials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold usresponsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have beenreleased.Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking WaterAct, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorizeddischarge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. Thedischarge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill prevention,control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent thecontamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implementedthereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by anappropriately issued permit. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the USACE, jointly promulgated final rules redefining thescope of waters protected under the Clean Water Act. To the extent the rule expands the range of properties subject to the Clean Water Act’s jurisdiction, wecould face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Following its promulgation, numerousstates and industry groups challenged the rule and, on October 9, 2015, a federal court stayed the rule’s implementation nationwide, pending further action incourt. In response to this decision, the EPA and the USACE have resumed nationwide use of the agencies’ prior regulations defining the term “waters of theUnited States.” Further, on February 28, 2017, President Trump signed an executive order directing the relevant executive agencies to review the rules and toinitiate rulemaking to rescind or revise them, as appropriate under the stated policies of protecting navigable waters from pollution while promotingeconomic growth, reducing uncertainty, and showing due regard for Congress and the states. On July 27, 2017, the EPA and the USACE published aproposed rule to rescind the 2015 rules, and, on November 22, 2017, the agencies published a proposed rule to maintain the status quo pending the agenciesreview of the 2015 rules.The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits orcoverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge ofwastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed inmore detail below under the caption “–Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing andimplementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some statesalso maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to theprevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certainonshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels offinancial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that,in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but notlimited to, the costs of responding to a release of oil to surface waters.14Non-compliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well asinjunctive obligations. We believe we are in material compliance with the requirements of each of these laws.Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutantsthrough the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governingemissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may berequired to obtain additional permits and incur capital costs in order to remain in compliance. For example, on August 16, 2012, the EPA published finalregulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, whichregulations are discussed in more detail below in “–Regulation of Hydraulic Fracturing.” Also, on May 12, 2016, the EPA issued a final rule regarding thecriteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rulecould cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements.These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can imposeadministrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state lawsand regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and validconstruction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gasprojects.Climate Change. In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and othergreenhouse gases present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute towarming of the earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new greenhouse gas emissionsthresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of theClean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD orTitle V permitting solely by reason of their greenhouse gas emissions. The Court ruled, however, that the EPA may require installation of best availablecontrol technology for greenhouse gas emissions at sources otherwise subject to the PSD and Title V programs. On August 26, 2016, the EPA proposedchanges needed to bring the EPA’s air permitting regulations in line with the Supreme Court’s decision on greenhouse gas permitting. The proposed rule waspublished in the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.Additionally, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhousegas emission sources in the U.S., including natural gas liquids fractionators and local natural gas distribution companies, beginning in 2011 for emissionsoccurring in 2010. In November 2010, the EPA expanded the greenhouse gas reporting rule to include onshore and offshore oil and natural gas productionand onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissionsoccurring in 2011. In October 2015, the EPA amended the greenhouse gas reporting rule to add the reporting of greenhouse gas emissions from gathering andboosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half ofthe states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emissioninventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so inthe future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring majorsources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emissionallowances corresponding with their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year until theoverall greenhouse gas emission reduction goal is achieved. As the number of greenhouse gas emission allowances declines each year, the cost or value ofallowances is expected to escalate significantly.At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations FrameworkConvention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the averageglobal temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. TheAgreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, PresidentTrump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely newagreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice ofits withdrawal until three years from the effective date, with such withdrawal taking effect15one year from such notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreementcan be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders havestated their intent to intensify efforts to uphold the commitments set forth in the international accord.Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of ourproducts and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increaseour own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions wouldimpact our business.In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereignwealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in theextraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interferewith our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging thatgreenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, privateindividuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or otherliabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in anysuch case could significantly impact our operations and could have an adverse impact on our financial condition.Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes,thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility inseasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than theirhistorical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may notbe fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazardsaffecting our operations.Regulation of Hydraulic FracturingHydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tightformations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture thesurrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recentsessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,”to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in thefracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA hastaken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program,specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposedmechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28,2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publiclyowned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment,or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWTfacilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWTfacilities, and the environmental impacts of discharges from CWT facilities.On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and naturalgas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissionsof sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oiland natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring theuse of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rulesalso establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. TheEPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the ruleswere also filed. In response, the EPA has issued, and will16likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulationsto impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, andactivities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development ofthe nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, theEPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. These standards,as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities orthe construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment ortechnologies to control emissions.Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturingpractices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources,finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, theEPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The reportrecommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, includingthe U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various otheraspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make itmore difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibithydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulicfracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose the chemicalsused in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wellsfor which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list ofchemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas RailroadCommission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filedwith the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and otherstandards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, onOctober 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for newdisposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S.Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed newdisposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority tomodify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas RailroadCommission has used this authority to deny permits for waste disposal wells.There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity,impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number oflawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations thatsignificantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate productionfrom tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegationsthat specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal,state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent constructionspecifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permittingdelays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failureto comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impacton our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.Other Regulation of the Oil and Natural Gas IndustryThe oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and naturalgas industry is under constant review for amendment or expansion, frequently increasing the17regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are bindingon the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatoryburden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do notaffect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations ofproduction.The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale ofoil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and variousother matters, primarily by FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’sregulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. Wecannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress orthe various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are notcurrently regulated and are made at market prices.Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulationinclude requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, inwhich we operate also regulate one or more of the following:•the location of wells;•the method of drilling and casing wells;•the timing of construction or drilling activities, including seasonal wildlife closures;•the rates of production or “allowables”;•the surface use and restoration of properties upon which wells are drilled;•the plugging and abandoning of wells; and•notice to, and consultation with, surface owners and other third parties.State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Somestates allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances,forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation lawsestablish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirementsregarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit thenumber of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the productionand sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation,but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas thatmay be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning ofproduction facilities and pipelines and for site restoration in areas where we operate. Although the U.S. Army Corps of Engineers does not require bonds orother financial assurances, some state agencies and municipalities do have such requirements.Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produceand the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce bynatural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted whichhave resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales ofour own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas marketsand enforce its rules and orders, including the ability to assess substantial civil penalties.18FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstatenatural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas andrelease of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantlyfostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatorytransportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of naturalgas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore,we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor canwe determine what effect, if any, future regulatory changes might have on our natural gas related activities.Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-discriminatory basis at cost-based rates ornegotiated rates. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters.Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities,which has the tendency to increase our costs of transporting gas to point-of-sale locations.Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices.Nevertheless, Congress could reenact price controls in the future.Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is alsosubject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipelinetransportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatoryoversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicableto all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than suchregulation will affect the operations of our competitors.Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard,common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity,access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportationservices generally will be available to us to the same extent as to our competitors.State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxesand requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gasproduction. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gasresources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on marketdemand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assureyou that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from ourwells and to limit the number of wells or locations we can drill.The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate toresource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.Operational Hazards and InsuranceThe oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in somecases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. Ifany of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction toproperty, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which ourbusiness is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, rig physicaldamage protection, control of well protection for selected wells,19comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date),excess umbrella liability and other coverage.Our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us againstliability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A lossnot fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. See Item 1A. “RiskFactors–Risks Related to the Oil and Natural Gas Industry and Our Business–Operating hazards and uninsured risks may result in substantial losses and couldprevent us from realizing profits.”We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and mayinclude higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believeare economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and wemay elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by newgovernmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significantevent, not fully insured against, could have a material adverse effect on our financial condition and results of operations.Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths ofthe service provider’s employees as well as contractors and subcontractors hired by the service provider.EmployeesAs of December 31, 2017, we had approximately 251 full time employees. None of our employees are represented by labor unions or covered by anycollective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assistour full time employees.FacilitiesOur corporate headquarters is located in Midland, Texas. We also lease additional office space in Midland and in Oklahoma City, Oklahoma. Webelieve that our facilities are adequate for our current operations.Availability of Company ReportsOur annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are available freeof charge on the Investor Relations page of our website at www.diamondbackenergy.com as soon as reasonably practicable after such material iselectronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Form 10-Kand should not be considered part of this or any other report that we file with or furnish to the SEC.20ITEM 1A. RISK FACTORSThe nature of our business activities subjects us to certain hazards and risks. The following is a summary of some of the material risks relating to ourbusiness activities. Other risks are described in Item 1. “Business and Properties” and Item 7A. “Quantitative and Qualitative Disclosures About MarketRisk.” These risks are not the only risks we face. We could also face additional risks and uncertainties not currently known to the Company or that wecurrently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations andthe trading price of our shares could decline.Risks Related to the Oil and Natural Gas Industry and Our BusinessMarket conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in thefuture adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantlyupon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response tochanges in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:•the domestic and foreign supply of oil and natural gas;•the level of prices and expectations about future prices of oil and natural gas;•the level of global oil and natural gas exploration and production;•the cost of exploring for, developing, producing and delivering oil and natural gas;•the price and quantity of foreign imports;•political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;•the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;•speculative trading in crude oil and natural gas derivative contracts;•the level of consumer product demand;•weather conditions and other natural disasters;•risks associated with operating drilling rigs;•technological advances affecting energy consumption;•the price and availability of alternative fuels;•domestic and foreign governmental regulations and taxes;•the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;•the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and•overall domestic and global economic conditions.These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with anycertainty. During the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI,has ranged from a low of $26.19 per barrel, or Bbl, in February 201621to a high of $110.62 per Bbl in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016to a high of $8.15 per MMBtu in February 2014. During 2017, WTI prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price ofnatural gas ranged from $2.44 to $3.71 per MMBtu. On January 29, 2018, the WTI posted price for crude oil was $65.71 per Bbl and the Henry Hub spotmarket price of natural gas was $3.60 per MMBtu, representing increases of 9% and 3%, respectively, from the high of $60.46 per Bbl of oil and $3.71 perMMBtu for natural gas during 2017. If the prices of oil and natural gas decline, our operations, financial condition and level of expenditures for thedevelopment of our oil and natural gas reserves may be materially and adversely affected.In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in ourhaving to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration ordevelopment activities are curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oiland natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which couldfurther limit our liquidity and ability to conduct additional exploration and development activities.Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financialcondition.Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian andthe United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations forthe global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or othercountries could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence andunemployment rates, may precipitate an economic slowdown. Concerns about global economic growth may have an adverse impact on global financialmarkets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish,which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations andultimately adversely impact our results of operations, liquidity and financial condition.A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive,which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future productionand, therefore, our future cash flow and income.A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point thatwould permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many ofour oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose ourrights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent onsuccessfully developing our undeveloped leasehold acreage.Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain neededcapital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business andoperations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2017, our total capital expenditures,including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $3.2 billion. Our 2018 capital budget for drilling,completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately$1.3 billion to $1.5 billion, representing an increase of 60% over our 2017 capital budget. Since completing our initial public offering in October 2012, wehave financed capital expenditures primarily with borrowings under our revolving credit facility, cash generated by operations and the net proceeds frompublic offerings of our common stock and the senior notes.We intend to finance our future capital expenditures with cash flow from operations, proceeds from offerings of our debt and equity securities andborrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:•our proved reserves;•the volume of oil and natural gas we are able to produce from existing wells;22•the prices at which our oil and natural gas are sold;•our ability to acquire, locate and produce economically new reserves; and•our ability to borrow under our credit facility.We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels ofcapital expenditures. Further, our actual capital expenditures in 2018 could exceed our capital expenditure budget. In the event our capital expenditurerequirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which mayinclude traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt orequity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of ourprospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable toimplement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which couldhave a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or futureinfrastructure projects could delay or eliminate potential efficiencies and related cost savings.Our success depends on finding, developing or acquiring additional reserves.Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable.Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities oracquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacementactivities or use third parties to accomplish these activities. We have made, and expect to make in the future, substantial capital expenditures in our businessand operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquireadditional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significantadditional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our currentproduction, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore,although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings and slowour growth.There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessmentof several factors, including:•recoverable reserves;•future oil and natural gas prices and their applicable differentials;•operating costs; and•potential environmental and other liabilities.The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection withthese assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not revealall existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities.Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observableeven when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protectionagainst all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so oncommercially acceptable terms.23Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions isdependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitionsmay be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinatinggeographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional andunfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and ourmanagement, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliancewith such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquiredbusiness into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionateamount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher thanthose paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financingfor acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquiredbusinesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect onour financial condition and results of operations. The inability to effectively manage the integration of acquisitions, including our recently completed andpending acquisitions, could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings andgrowth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions arecompleted in particular periods.Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with theproperties that we acquire or obtain protection from sellers against such liabilities.Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, developmentand operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with theassessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of ourdue diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, whenan inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. Wemay be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance withour expectations.We may incur losses as a result of title defects in the properties in which we invest.It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineralinterest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriategovernmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthlessand can adversely affect our results of operations and financial condition.Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator ofthe well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certaincurative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects maydelay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves.Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment ofleasehold rights in properties in which we hold an interest, we will suffer a financial loss.Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas thatconsist of recently acquired leasehold acreage or that have limited drilling or production history. From inception through December 31, 2017, we drilled atotal of 412 gross horizontal wells and 262 gross vertical wells and participated in an additional 61 gross horizontal wells and 18 gross vertical non-operatedwells, of which 670 wells were completed as producing wells and 83 wells were in various stages of completion. If future wells or the wells in the process ofbeing completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.24Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materiallyalter the occurrence or timing of their drilling.At an assumed price of approximately $60.00 per Bbl WTI, we currently have approximately 3,800 gross (2,750 net) identified economic potentialhorizontal drilling locations in multiple horizons on our acreage. As of December 31, 2017, only 168 of our gross identified potential horizontal drillinglocations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part ofour growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, constructionof infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further,our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will requiresubstantial additional interpretation. In addition, we have identified approximately 873 horizontal drilling locations in intervals in which we have drilledvery few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. Wecannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recoverdrilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us toknow conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities tobe economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation orexperience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of thewell. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materiallyharm our business. Through December 31, 2017, we are the operator of or have participated in a total of 466 horizontal wells completed on our acreage, wecannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will beapplicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future orlong-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if wewill be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ fromthose presently identified, which could adversely affect our business.Multi-well pad drilling may result in volatility in our operating results.We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad aredrilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production, which may causevolatility in our quarterly operating results.Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highlycompetitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost or, if renewal is not feasible,loss of our lease and prospective drilling opportunities.Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production isestablished within the spacing units covering the undeveloped acres. As of December 31, 2017, we had leases representing 22,913 net acres expiring in 2018,19,670 net acres expiring in 2019, 20,219 net acres expiring in 2020, 719 net acres expiring in 2021 and no net acres expiring in 2022. The cost to renewsuch leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our currentdrilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through leaseexpirations. In addition, in order to hold our current leases expiring in 2018, we will need to operate at least a one-rig program. We cannot assure you that wewill have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses ofleases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.We have entered into fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options and may inthe future enter into forward sale contracts or additional fixed price swap, fixed price basis swap derivatives or costless collars for a portion of ourproduction. Although we have hedged a portion of our estimated 2018 and 2019 production, we may still be adversely affected by continuing andprolonged declines in the price of oil.We use fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce pricevolatility associated with certain of our oil and natural gas sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floatingmarket price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resultingin a net amount due to or from the counterparty. Under the Company’s costless collar contracts, we are required to make a payment to the counterparty if thesettlement price for any settlement period is greater than the call option price. The counterparty is required to make a payment25to us if the settlement price for any settlement period is less than the put option price. These contracts and any future economic hedging arrangements mayexpose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase.As of December 31, 2017, we had the following commodity contracts in place covering NYMEX WTI crude oil, Brent crude oil and NYMEX HenryHub natural gas for the production period of January 2018 through December 2018:•crude oil swap contracts priced at a weighted average price of $51.10 WTI for 9,761,000 aggregate Bbls;•crude oil swap contracts priced at a weighted average price of $54.89 Brent for 1,830,000 aggregate Bbls;•crude oil basis swap contracts priced at a weighted average price of $0.88 for 5,475,000 aggregate Bbls for the spread between the WTI Midlandprice and the WTI Cushing price;•natural gas swap contracts priced at a weighted average price of $3.14 for 7,750,000 aggregate MMBtu; and•crude oil costless collars contracts with a floor price of $47.00 for 540,000 aggregate Bbls and a ceiling price of $56.34 for 270,000 aggregateBbls.We have crude oil swap contracts priced at a weighted average price of $49.82 WTI for 1,095,000 aggregate Bbls with a production period ofJanuary 2019 through December 2019. To the extent that the prices of oil and natural gas remain at current levels or decline further, we will not beable to economically hedge future production at the same level as our current hedges, and our results of operations and financial condition would benegatively impacted.Our derivative transactions expose us to counterparty credit risk.Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in thefinancial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivativecontract and we may not be able to realize the benefit of the derivative contract.If production from our Permian Basin acreage decreases due to decreased developmental activities, production related difficulties or otherwise, we mayfail to meet our obligations to deliver specified quantities of oil under our oil purchase contract, which will result in deficiency payments to thecounterparty and may have an adverse effect on our operations.We are a party to an agreement with Shell Trading (US) Company under which we are obligated to deliver specified quantities of oil to Shell Trading(US) Company. Our maximum delivery obligation under this agreement is 8,000 gross barrels per day. We have a one-time right to decrease the contractquantity by not more than 20% of the then-current quantity. This decreased quantity, if elected, would be effective for the remainder of the term of theagreement. If production from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity priceenvironment, production related difficulties or otherwise, we may be unable to meet our obligations under the oil purchase agreement, which may result indeficiency payments to the counterparty and may have an adverse effect on our operations.The inability of one or more of our customers to meet their obligations may adversely affect our financial results.In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables fromjoint interest owners on properties we operate (approximately $73.0 million at December 31, 2017) and receivables from purchasers of our oil and natural gasproduction (approximately $158.6 million at December 31, 2017). Joint interest receivables arise from billing entities that own partial interests in the wellswe operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to controlwhich co-owners participate in our wells.We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the yearended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & TradingLP (19%) and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue:Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, twopurchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customeraccounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entitiesmay be similarly affected by changes in economic and other conditions.26Current economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significantcustomers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financialresults.Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in theacquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costsand annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicingequipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil andnatural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves wouldsignificantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceedrelated costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gasproperties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total provedreserves. The average depletion rate per barrel equivalent unit of production was $11.11, $11.23 and $17.84 for the years ended December 31, 2017, 2016and 2015, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2017, 2016 and2015 was $321.9 million, $176.4 million and $216.1 million, respectively.The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed toexceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net ofaccumulated depreciation, depletion, amortization and impairment, exceed the discounted future net revenues of proved oil and natural gas reserves, theexcess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month pricefor oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.Impairments on proved oil and natural gas properties of $245.5 million and $814.8 million were recorded for the years ended December 31, 2016and 2015, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017. See Item 7.“Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies and Estimates–Method ofaccounting for oil and natural gas properties” for a more detailed description of our method of accounting.Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimatesor underlying assumptions will materially affect the quantities and present value of our reserves.Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gasand assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result,estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historicalestimates of proved reserves as of December 31, 2017, 2016 and 2015 (which include those attributable to Viper) are based on reports prepared by RyderScott, which conducted a well-by-well review of all our properties for the periods covered by its reserve reports using information provided by us. The EURsfor our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account theresults of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating anddevelopment costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, theeconomically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk ofrecovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history,which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimatesare based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates.Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undevelopedacreage. The reserve estimates represent our net revenue interest in our properties.The estimates of reserves as of December 31, 2017, 2016 and 2015 included in this report were prepared using an average price equal to theunweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periodsDecember 31, 2017, 2016 and 2015, respectively, in accordance with the SEC guidelines applicable to reserve estimates for such periods.27The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas propertieswill affect the timing of actual future net cash flows from proved reserves.The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimatedproved oil reserves.The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent thecurrent market value of our estimated proved oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow fromour estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month pricefor each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates usingthen current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted futurenet cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities–Oil and Gas,”may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gasindustry in general.SEC rules could limit our ability to book additional proved undeveloped reserves in the future.SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilledwithin five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undevelopedreserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells withinthe required five-year timeframe because they have become uneconomic or otherwise.The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.Approximately 37.8% of our total estimated proved reserves as of December 31, 2017, were proved undeveloped reserves and may not be ultimatelydeveloped or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reservedata included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop suchreserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that theresults of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or furtherdecreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becominguneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographicarea. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.All of our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, wemay be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area causedby governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitationsor interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demandmay become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditionsto occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of ourproperties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they mighthave on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on ourfinancial condition and results of operations.In addition to the geographic concentration of our producing properties described above, as of December 31, 2017, all of our proved reserves wereattributable to the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additionalrisks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.28We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchaserscould, among other factors, limit our access to suitable markets for the oil and natural gas we produce.The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management,including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of natural gas pipelines, the availability ofskilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of natural gas sold ininterstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the year endedDecember 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP(19%) and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of our revenue: ShellTrading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, twopurchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). No other customeraccounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets forour future oil and natural gas production. The loss of one or more of these customers, and our inability to sell our production to other customers on terms weconsider acceptable, could materially and adversely affect our business, financial condition, results of operations and cash flow.The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and otherproppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wagerates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, whattheir timing and duration will be. In accordance with customary industry practice, we rely on independent third party service providers to provide most of theservices necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results ofoperations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securingthe use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. Shortages of drilling rigs, equipment, raw materials(particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment coulddelay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on ourfinancial condition, results of operations and cash flows.Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes.Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extremedrought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction forhydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectivelyutilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financialcondition, results of operations and cash flows.We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.Our business operations have grown substantially since our initial public offering in October 2012 and we expect our business operations tocontinue to grow in the future. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will beadditional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative,operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experiencedmanagers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financialcondition and results of operations and our ability to timely execute our business plan.We have incurred losses from operations during certain periods since our inception and may do so in the future.29Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantialcapital expenditures. The uncertainty and risks described in this report may impede our ability to economically find, develop and acquire oil and natural gasreserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from our operating activities in the future.Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques;therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drillingresults may not meet our expectations for reserves or production.Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face whiledrilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontallythrough the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through thehorizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number ofstages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion ofthe final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfullydrill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case ofmulti-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new oremerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production.Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results inthese areas.Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profilesare established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because ofcapital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areasmay not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gasproperties and the value of our undeveloped acreage could decline in the future.Conservation measures and technological advances could reduce demand for oil and natural gas.Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technologicaladvances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and naturalgas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities areunavailable, our operations could be interrupted and our revenues reduced. The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilitiesowned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oilby truck to a pipeline for transportation. Our natural gas production is generally transported by our gathering lines from the wellhead to an interconnectionpoint with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied.Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of ouror third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gasand thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batterieswith occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas inthe Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounterproduction related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced andsold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessivepressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack ofcontracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in manycases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inabilityto obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results ofoperations.30Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time inresponse to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reportsconcerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed pricecontrols and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oiland gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof andother substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local lawsand regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in theassessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls andinjunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations imposed strict requirements for water and air pollutioncontrol and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. Even iffederal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in thelong-term, and at the state and local levels. See Item 1. “Business–Regulation” for a description of certain laws and regulations that affect us.Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operatingrestrictions or delays.Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tightformations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture thesurrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recentsessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,”to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in thefracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA hastaken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program,specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.In addition, the EPA previously announced its plans to develop a Notice of Proposed Rulemaking by June 2018, which would describe a proposedmechanism - regulatory, voluntary, or a combination of both - to collect data on hydraulic fracturing chemical substances and mixtures. Also, on June 28,2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publiclyowned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment,or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWTfacilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWTfacilities, and the environmental impacts of discharges from CWT facilities.On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and naturalgas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissionsof sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oiland natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring theuse of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPAreceived numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules werealso filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration.Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturingpractices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources,finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, theEPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The reportrecommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, includingthe U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office,31have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulatehydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doingbusiness.Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibithydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulicfracturing fluids. For a more detailed discussion of state and local laws and initiatives concerning hydraulic fracturing, see “Items 1 and 2. Business andProperties–Regulation–Regulation of Hydraulic Fracturing.” We use hydraulic fracturing extensively in connection with the development and production ofcertain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce thevolumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity,impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number oflawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations thatsignificantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate productionfrom tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegationsthat specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal,state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent constructionspecifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permittingdelays and potential increases in costs. Such changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failureto comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impacton our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to ourbusiness activities.We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicableto our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permitsor other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing andother operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drillingactivities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent ormitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills,pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These lawsand regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws andregulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, thesuspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in someinstances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict aswell as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third partiesthat received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of ourown actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property,including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/orunpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. To the extentlaws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal andcleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of theareas where we operate.Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designedto protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfieldequipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resultingshortages or high costs could delay our32operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling incertain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate asthreatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our explorationand production activities that could have an adverse impact on our ability to develop and produce our reserves.The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect ofcommodity price, interest rate and other risks associated with our business.The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce theeffect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd Frank Wall Street Reform andConsumer Protection Act, or Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivativesmarket and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under thelegislation, the Commodities Futures Trading Commission has issued a final rule on position limits for certain futures and option contracts in the majorenergy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The Commodities FuturesTrading Commission’s final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to theCommodities Futures Trading Commission to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary andappropriate were satisfied. As a result, the rule has not yet taken effect, although the Commodities Futures Trading Commission has indicated that it intendsto appeal the court’s decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our businessis not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce ourability to enter into hedging transactions.In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather thanhedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when theCommodities Futures Trading Commission will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require usto comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, althoughwhether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for ourhedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose otherrequirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedgingstrategy. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirementsin connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reformlegislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may notbe as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts(including through requirements to post collateral which could adversely affect our available liquidity), 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 our derivative contracts in existenceat that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of thelegislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect ourability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, whichsome legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore beadversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverseeffect on our consolidated financial position, results of operations or cash flows.Recently enacted U.S. tax legislation as well as future U.S. tax legislations may adversely affect our business, results of operations, financial condition andcash flow. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cutsand Jobs Ac, which we refer to as the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, which we refer to as the Code.Among other changes, the Tax Act (i) reduces the maximum U.S. corporate income tax rate from 35% to 21%, (ii) preserves long-standing upstream oil andgas tax provisions such as immediate deduction of intangible drilling, (iii) allows for immediate expensing of capital expenditures for tangible personalproperty for a period of time, (iv) modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporationsand (v) enacts new limitations regarding the deductibility of interest expense. The Tax Act is complex and far-reaching, and we cannot predict with certaintythe resulting impact its enactment will have on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations andassumptions made by us as well as additional33regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results ofoperations, financial condition and cash flow.In addition, from time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state incometax laws affecting the oil and gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal ofthe percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysicalexpenditures. While these specific changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changeswill be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposedchanges in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currentlyavailable with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financialcondition and cash flows.Regulation of greenhouse gas emissions could result in increased operating costs and reduced demand for the oil and natural gas we produce.In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series ofgreenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time,considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of greenhouse gasesprimarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. While we are subject tocertain federal greenhouse gas monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and localclimate change initiatives. For a description of existing and proposed greenhouse gas rules and regulations, see “Items 1 and 2. Business and Properties–Regulation–Environmental Regulation-Climate Change.”At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations FrameworkConvention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the averageglobal temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Agreement went into effect on November 4, 2016. TheAgreement establishes a framework for the parties to cooperate and report actions to reduce greenhouse gas emissions. However, on June 1, 2017, PresidentTrump announced that the United States would withdraw from the Paris Agreement, and begin negotiations to either re-enter or negotiate an entirely newagreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice ofits withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. It is not clear what steps the TrumpAdministration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such anagreement. Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify efforts to uphold thecommitments set forth in the international accord.Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the demand for, price of, and value of ourproducts and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increaseour own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions wouldimpact our business.In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereignwealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in theextraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interferewith our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging thatgreenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, privateindividuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or otherliabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in anysuch case could significantly impact our operations and could have an adverse impact on our financial condition.Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes,thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility inseasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than theirhistorical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may notbe fully34insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting ouroperations.Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability todispose of produced water gathered from such activities, which could have a material adverse effect on our business.State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly theunderground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuingto study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, mostrecently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rulesregulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirementsregarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example,on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for newdisposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. GeologicalSurvey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well.If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or ifscientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspendor terminate the permit application or existing operating permit for that well. The Commission has used this authority to deny permits for waste disposalwells.We dispose of large volumes of produced water gathered from our drilling and production operations by injecting it into wells pursuant to permitsissued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, theselegal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reportingrequirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoptionand implementation of any new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered from our drillingand production activities by owned disposal wells, could have a material adverse effect on our business, financial condition and results of operations.A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agenciesmay result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.Section 1(b) of the Natural Gas Act of 1938 exempts natural gas gathering facilities from regulation by the FERC. We believe that the natural gaspipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore areexempt from FERC’s jurisdiction under the Natural Gas Act of 1938. However, the distinction between FERC–regulated transmission services and federallyunregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, sothe classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, whichcould cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results ofoperations. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure tocomply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financialcondition or results of operations.We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate ourassets.Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. Asa result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competitionand may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualifiedpersonnel than we are able to offer.Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead toa reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect onour business, financial condition and results of operations.We rely on a few key employees whose absence or loss could adversely affect our business.35Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affectour business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, Travis D. Stice,could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event theycease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do notmaintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our keyemployees.Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adverselyaffect our business, financial condition or results of operations.Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we willrecover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but alsofrom wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating andother costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present orthat it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond ourcontrol, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed,canceled or otherwise negatively impacted as a result of other factors, including:•unusual or unexpected geological formations;•loss of drilling fluid circulation;•title problems;•facility or equipment malfunctions;•unexpected operational events;•shortages or delivery delays of equipment and services;•compliance with environmental and other governmental requirements; and•adverse weather conditions.Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources andequipment, pollution, environmental contamination or loss of wells and other regulatory penalties.Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue toundertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that nocommercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance ourgrowth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will notabandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitablydeveloped, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in suchunproved property or wells.Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not producesufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, andmany factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpecteddrilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells thatare profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices36for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost.Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including therisk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormallypressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, ouroperations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration offracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life,severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatoryinvestigations and penalties, suspension of operations and repairs required to resume operations.We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, whichinclude pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Underour agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume allresponsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with suchvendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contaminationwhich may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any otheruncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify ourvendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on afootage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite thisgeneral allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of suchallocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incursubstantial losses which could materially and adversely affect our financial condition and results of operations.In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of ourbusiness risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is,its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurancecoverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability toconduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additionalinsurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact ourfinancial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not becovered by insurance.Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, propertydamage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollutionevent and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage forgradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurancecoverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss notfully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of thesecompanies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and otherproducts on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratoryprospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition,these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitorsmay be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adverselyaffect our competitive position. Our ability to acquire additional properties and to37discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highlycompetitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at adisadvantage in bidding for exploratory prospects and producing oil and natural gas properties.Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adverselyaffect the results of our drilling operations.Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists inidentifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in thosestructures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies,and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.We may not be able to keep pace with technological developments in our industry.The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products andservices using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced bycompetitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial,technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologiesbefore we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If oneor more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materiallyand adversely affected.We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or ourauditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reportedinformation and our stock price may be negatively affected.We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. Section 404 requiresthat we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting.This section also requires that our independent registered public accounting firm opine on those internal controls. If we fail to comply with the requirementsof Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify and report material weaknesses in internal control over financial reporting, theaccuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence inour reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in theeffectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability toobtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business,results of operations and financial condition.Increased costs of capital could adversely affect our business.Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or areduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limitour ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuingdisruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our abilityto finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affectour ability to achieve our planned growth and operating results.We recorded stock-based compensation expense in 2017, 2016 and 2015, and we may incur substantial additional compensation expense related to ourfuture grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.As a result of outstanding stock-based compensation awards, for the years ended December 31, 2017, 2016 and 2015 we incurred $34.2 million,$33.5 million and $24.6 million, respectively, of stock based compensation expense, of which we capitalized $8.6 million, $7.1 million and $6.0 millionrespectively, pursuant to the full cost method of accounting for oil and natural gas properties. In addition, our compensation expenses may increase in thefuture as compared to our historical expenses because of the costs associated with our existing and possible future incentive plans. These additional expensescould adversely38affect our net income. The future expense will be dependent upon the number of share-based awards issued and the fair value of the options or shares ofcommon stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generallyover the vesting period of awards made to recipients.Loss of our information and computer systems could adversely affect our business.We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data,electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or softwarenetwork infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas andinability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence couldhave a material adverse effect on our business.A terrorist attack or armed conflict could harm our business.Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the UnitedStates and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting politicalinstability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services andcausing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adverselyimpacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result ofthese threats, and some insurance coverage may become more difficult to obtain, if available at all.We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/orfinancial loss.The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development,production, and processing activities. For example, the oil and natural gas industry depends on digital technologies to interpret seismic data, manage drillingrigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data.At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings thatindicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers andother business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering,monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyberincidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risksmay not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance ourprotective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liabilityresulting from a cyberattack on our assets that may shut down all or part of our business.Risks Related to Our IndebtednessOur substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the senior notesand our other indebtedness.As of December 31, 2017, we had total long-term debt of $1.5 billion, including $1.0 billion outstanding under the 2024 senior notes and 2025senior notes, and we had an unused borrowing base availability of $603.0 million under our revolving credit facility. On January 29, 2018, we issued $300.0million aggregate principal amount of new 5.375% Senior Notes due 2025, which we refer to as the new 2025 notes, as additional notes under our existingindenture, and repaid $308.5 million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new2025 notes. Immediately following the issuance of the new 2025 notes and the application of our net proceeds thereof, we had total long-term debt of $1.39billion (including $1.3 billion attributable to all of our outstanding senior notes), our borrowing base remained $1.8 billion (as the lenders waived theborrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion,and we had $911.4 million of available borrowing capacity under our revolving credit facility. As of December 31, 2017, Viper, one of our subsidiaries, had$93.5 million in outstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. We may in the future incursignificant additional indebtedness under our revolving credit facility or otherwise in order to make acquisitions, to develop our properties or for otherpurposes. Our level of indebtedness could have important consequences to you and affect our operations in several ways, including the following:39•our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the senior notes, including anyrepurchase obligations that may arise thereunder;•a significant portion of our cash flows could be used to service the senior notes and our other indebtedness, which could reduce the fundsavailable to us for operations and other purposes;•a high level of debt could increase our vulnerability to general adverse economic and industry conditions;•the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose ofassets, pay dividends and make certain investments;•a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be ableto take advantage of opportunities that our indebtedness would prevent us from pursuing;•our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to,changes in the economy and in our industry;•a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us torepay a portion of our then-outstanding bank borrowings;•a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;•a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions,general corporate or other purposes; and•we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduceour level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and otherfactors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows topay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that willaffect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assetsand our performance at the time we need capital.Restrictive covenants in our revolving credit facility, the indentures governing the senior notes and future debt instruments may limit our ability to respondto changes in market conditions or pursue business opportunities.Our revolving credit facility and the indentures governing our outstanding senior notes contain, and the terms of any future indebtedness maycontain, restrictive covenants that limit our ability to, among other things:•incur or guarantee additional indebtedness;•make certain investments;•create additional liens;•sell or transfer assets;•issue preferred stock;•merge or consolidate with another entity;•pay dividends or make other distributions;•designate certain of our subsidiaries as unrestricted subsidiaries;•create unrestricted subsidiaries;40•engage in transactions with affiliates; and•enter into certain swap agreements.In connection with the closing of Viper’s initial public offering on June 23, 2014, we entered into an amendment to our revolving credit facility,which modified certain provisions of our revolving credit facility to allow us, among other things, to designate one or more of our subsidiaries as“unrestricted subsidiaries” that are not subject to certain restrictions contained in the revolving credit facility. Under the amended revolving credit facility,we designated Viper, the general partner and Viper’s subsidiary as unrestricted subsidiaries, and upon such designation, they were automatically releasedfrom any and all obligations under the amended revolving credit facility, including the related guaranty, and all liens on the assets of, and the equity interestsin, Viper, the general partner and Viper’s subsidiary under the amended revolving credit facility were automatically released. Further Viper, the generalpartner and Viper’s subsidiaries, Viper Energy Partners LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC), are designated asunrestricted subsidiaries under the indentures governing our outstanding senior notes.We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictivecovenants contained in our revolving credit facility and the indentures governing our senior notes. In addition, our revolving credit facility requires us tomaintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react tochanges in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expendituresor withstand a continuing or future downturn in our business.A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under ourrevolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable,which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances toterminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under ourrevolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under ourrevolving credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full thatindebtedness.Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations orotherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving creditfacility if required as a result of a borrowing base redetermination.Availability under our revolving credit facility is currently subject to a borrowing base of $1.8 billion, of which we have elected a commitmentamount of $1.0 billion. The borrowing base is subject to scheduled annual and other elective collateral borrowing base redeterminations based on our oil andnatural gas reserves and other factors. As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Ourweighted average interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017. On January 29, 2018, we repaid $308.5million of our outstanding borrowings under the revolving credit facility with the net proceeds from the issuance of our new 2025 notes. Immediatelyfollowing the issuance of the new 2025 notes and the application of our net proceeds thereof, our borrowing base remained $1.8 billion (as the lenderswaived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was$1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility. We expect to borrow under our revolving creditfacility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impactour liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cashflow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, wewould be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwiseunable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverseeffect on our business and financial results.Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantialindebtedness.Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends onour future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flowfrom operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may berequired to adopt one or more41alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may beonerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debtobligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations toattempt to meet our debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes restrict our ability to usethe proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceedsthat we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capitalmarkets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms,which could result in a default on our debt obligations and have an adverse effect on our financial condition.We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face.We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and theindentures governing our senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2017, our borrowing baseunder our revolving credit facility was set at $1.8 billion, of which we have elected a commitment amount of $1.0 billion and we had $397.0 millionoutstanding borrowings under this facility. As of December 31, 2017, Viper had $93.5 million in outstanding borrowings, and $306.5 million available forborrowing, under its revolving credit facility. Further, the indentures governing the senior notes allow us to issue additional notes under certaincircumstances which will also be guaranteed by the guarantors. The indentures governing the senior notes also allow us to incur certain other additionalsecured debt and allows us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurallysenior to the senior notes. In addition, the indentures governing the senior notes do not prevent us from incurring other liabilities that do not constituteindebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), includingadditional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in anyproceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or otherliabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of,current or future financings or trade credit.Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned toour debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of timeor that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our creditratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, coststructure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increaseour borrowing costs.Borrowings under our and Viper’s revolving credit facilities expose us to interest rate risk.Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. The terms of our revolving credit facilityprovide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Fundseffective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstandingin relation to the borrowing base. As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Our weightedaverage interest rate on borrowings under our revolving credit facility was 2.97% on December 31, 2017. Viper’s weighted average interest rate onborrowings from its revolving credit facility was 3.19% during the year ended December 31, 2017. As of December 31, 2017, Viper had $93.5 million inoutstanding borrowings, and $306.5 million available for borrowing, under its revolving credit facility. If interest rates increase, so will our interest costs,which may have a material adverse effect on our results of operations and financial condition.42Risks Related to Our Common StockThe corporate opportunity provisions in our certificate of incorporation could enable affiliates of ours to benefit from corporate opportunities that mightotherwise be available to us.Subject to the limitations of applicable law, our certificate of incorporation, among other things:•permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;•permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind ofproperty in which we may make investments; and•provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potentialbusiness opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or hercapacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will bepermitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in amanner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a mannerinconsistent with our best interests.These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of ouraffiliates.We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts thatmay arise may not always be in our or our stockholders’ best interests.In the past, we have engaged in transactions with affiliated companies and may do so again in the future. These transactions, and the resolution ofany conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in ouror our stockholders’ best interests.If the price of our common stock fluctuates significantly, your investment could lose value.Although our common stock is listed on the Nasdaq Select Global Market, we cannot assure you that an active public market will continue for ourcommon stock. If an active public market for our common stock does not continue, the trading price and liquidity of our common stock will be materiallyand adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more thanthe stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, asa result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unableto liquidate their investment in us. Furthermore, the stock market is subject to significant price and volume fluctuations, and the price of our common stockcould fluctuate widely in response to several factors, including:•our quarterly or annual operating results;•changes in our earnings estimates;•investment recommendations by securities analysts following our business or our industry;•additions or departures of key personnel;•changes in the business, earnings estimates or market perceptions of our competitors;•our failure to achieve operating results consistent with securities analysts’ projections; •changes in industry, general market or economic conditions; and•announcements of legislative or regulatory changes.The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of thesecurities of many companies, including companies in our industry. The changes often appear to occur43without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with ourcompany and these fluctuations could materially reduce our stock price.Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price ofour common stock to decline. In addition, the sale of such shares, or the perception that such sales may occur, could impair our ability to raise capital throughthe sale of additional common or preferred stock. Except for any shares purchased by our affiliates, all of the shares of common stock sold in our initial publicoffering and our subsequent equity offerings are freely tradable. In the event that one or more of our stockholders sells a substantial amount of our commonstock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.The declaration of dividends on our common stock is within the discretion of our board of directors based upon a review of relevant considerations, andthere is no guarantee that we will pay any dividends in the future or at levels anticipated by our stockholders.On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per share of our common stock payablequarterly beginning with the first quarter of 2018. The decision to pay this first dividend or any future dividends, however, is solely within the discretion of,and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, thepayment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposedby applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board ofdirectors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns toour stockholders.A change of control could limit our use of net operating losses.As of December 31, 2017, we had a net operating loss, or NOL, carry forward of approximately $357.0 million for federal income tax purposes. If wewere to experience an “ownership change,” as determined under Section 382 of the Code, our ability to offset taxable income arising after the ownershipchange with NOLs generated prior to the ownership change would be limited, possibly substantially. In general, an ownership change would establish anannual limitation on the amount of our pre-change NOLs we could utilize to offset our taxable income in any future taxable year to an amount generallyequal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change willoccur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the InternalRevenue Code) at any time during a rolling three-year period.If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stockor if our operating results do not meet their expectations, our stock price could decline.The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or ourbusiness. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financialmarkets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgradeour stock or if our operating results do not meet their expectations, our stock price could decline.We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock. Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stockhaving such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions,as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of ourcommon stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening ofspecified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign toholders of preferred stock could affect the residual value of the common stock.44Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, whichcould adversely affect the price of our common stock.The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change incontrol of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that maymake acquiring control of our company difficult, including:•provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of ourstockholders;•limitations on the ability of our stockholders to call a special meeting and act by written consent;•the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing atleast 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;•the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stockbe obtained to remove directors;•the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stockbe obtained to amend our certificate of incorporation; and•the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take othercorporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders,which may limit the price that investors are willing to pay in the future for shares of our common stock.ITEM 1B. UNRESOLVED STAFF COMMENTSNone.ITEM 3. LEGAL PROCEEDINGSDue to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our businessactivities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation,disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.ITEM 4. MINE SAFETY DISCLOSURESNot applicable.45PART IIITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITYSECURITIESPrice Range of Common StockOur common stock is listed on the Nasdaq Global Select Market under the symbol “FANG”.The following table sets forth the range of high and low sales prices of our common stock for the periods presented: High Low2017 1st Quarter$114.00 $96.052nd Quarter$108.17 $83.223rd Quarter$98.36 $82.774th Quarter$127.45 $95.692016 1st Quarter$79.87 $55.482nd Quarter$96.01 $73.123rd Quarter$99.69 $83.904th Quarter$113.23 $88.74Holders of RecordThere were nine holders of record of our common stock on February 9, 2018.Dividend Policy We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility restrict the payment of cashdividends on our common stock. See Item 1A. “Risk Factors–Risks Related to the Oil and Natural Gas Industry and Our Business–Our revolving creditfacility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.” and Item 7.“Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity and Capital Resources–Credit Facility.”On February 13, 2018, we announced that we are initiating an annual cash dividend in the amount of $0.50 per share of our common stock payablequarterly beginning with the first quarter of 2018. The decision to pay this first dividend or any future dividends, however, is solely within the discretion of,and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, thepayment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposedby applicable law and other factors that the board deems relevant at the time of such determination.Recent Sales of Unregistered SecuritiesNone.Repurchases of Equity SecuritiesNone.46ITEM 6. SELECTED FINANCIAL DATAThis section presents our selected historical combined consolidated financial data. The selected historical combined consolidated financial datapresented below is not intended to replace our historical consolidated financial statements. You should read the following data along with Item 7.“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, eachof which is included elsewhere in this Annual Report on Form 10-K.Presented below is our historical financial data for the periods and as of the dates indicated. The historical financial data for the years endedDecember 31, 2017, 2016 and 2015 and the balance sheet data as of December 31, 2017 and 2016 are derived from our audited consolidated financialstatements included elsewhere in this Annual Report on Form 10-K. The historical financial data for the year ended December 31, 2014 and 2013 and thebalance sheet data as of December 31, 2015, 2014 and 2013 are derived from our audited financial statements not included in this Annual Report on Form10-K. Year Ended December 31,(In thousands, except per share amounts)2017 2016 2015 2014 2013Statements of Operations Data: Total revenues$1,205,111 $527,107 $446,733 $495,718 $208,002Total costs and expenses600,091 595,724 1,187,002 283,048 112,808Income (loss) from operations605,020 (68,617) (740,269) 212,670 95,194Other income (expense)(107,831) (96,099) (8,831) 92,286 (8,853)Income (loss) before income taxes497,189 (164,716) (749,100) 304,956 86,341Provision for (benefit from) income taxes(19,568) 192 (201,310) 108,985 31,754Net income (loss)516,757 (164,908) (547,790) 195,971 54,587Less: Net income attributable to non-controlling interest34,496 126 2,838 2,216 —Net income (loss) attributable to Diamondback Energy, Inc.$482,261 $(165,034) $(550,628) $193,755 $54,587Earnings per common share Basic$4.95 $(2.20) $(8.74) $3.67 $1.30Diluted$4.94 $(2.20) $(8.74) $3.64 $1.29Weighted average common shares outstanding Basic97,458 75,077 63,019 52,826 42,015Diluted97,688 75,077 63,019 53,297 42,255 As of December 31,(In thousands)2017 2016 2015 2014 2013Balance Sheet Data: Cash and cash equivalents$112,446 $1,666,574 $20,115 $30,183 $15,555Net property and equipment7,343,617 3,390,857 2,597,625 2,791,807 1,446,337Total assets7,770,985 5,349,680 2,750,719 3,095,481 1,521,614Current liabilities577,428 209,342 141,421 266,729 121,320Long-term debt1,477,347 1,105,912 487,807 673,500 460,000Total stockholders’/ members’ equity(1)5,254,860 3,697,462 1,875,972 1,751,011 845,541Total equity5,581,737 4,018,292 2,108,973 1,985,213 — Year Ended December 31,(In thousands)2017 2016 2015 2014 2013Other Financial Data: Net cash provided by operating activities$888,625 $332,080 $416,501 $356,389 $155,777Net cash used in investing activities(3,132,282) (1,310,242) (895,050) (1,481,997) (940,140)Net cash provided by financing activities689,529 2,624,621 468,481 1,140,236 773,56047 Year Ended December 31,(In thousands)2017 2016 2015 2014 2013Consolidated Adjusted EBITDA(2)$928,039 $387,535 $449,245 $398,334 $157,604(1)For the years ended December 31, 2017, 2016, 2015 and 2014, total stockholders’ equity excludes $326.9 million, $320.8 million, $233.0 million and$234.2 million, respectively, of non-controlling interest related to Viper Energy Partners LP. There was no equity related to non-controlling interest forthe year ended December 31, 2013.(2)Consolidated Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Consolidated Adjusted EBITDA and areconciliation of Consolidated Adjusted EBITDA to net income (loss) see “–Non-GAAP financial measure and reconciliation” below.Non-GAAP financial measure and reconciliationConsolidated Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financialstatements, such as industry analysts, investors, lenders and rating agencies. We define Consolidated Adjusted EBITDA as net income (loss) plus net non-cash (gain) loss on derivative instruments, net interest expense, depreciation, depletion and amortization expense, impairment of oil and natural gasproperties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, losson extinguishment of debt, income tax (benefit) provision and non-controlling interest in net (income) loss. Consolidated Adjusted EBITDA is not a measureof net income (loss) as determined by GAAP. Management believes Consolidated Adjusted EBITDA is useful because it allows it to more effectively evaluateour operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Weadd the items listed above to net income (loss) in arriving at Consolidated Adjusted EBITDA because these amounts can vary substantially from company tocompany within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets wereacquired. Consolidated Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined inaccordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Consolidated Adjusted EBITDA aresignificant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well asthe historic costs of depreciable assets, none of which are components of Consolidated Adjusted EBITDA. Our computations of Consolidated AdjustedEBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our revolving credit facility or any of our othercontracts.The following presents a reconciliation of the non-GAAP financial measure of Consolidated Adjusted EBITDA to the GAAP financial measure of netincome (loss). Year Ended December 31,(In thousands)2017 2016 2015 2014 2013Net income (loss)$516,757 $(164,908) $(547,790) $195,971 $54,587Non-cash (gain) loss on derivative instruments, net84,240 26,522 112,918 (117,109) (5,346)Interest expense, net40,554 40,684 41,510 34,515 8,059Depreciation, depletion and amortization326,759 178,015 217,697 170,005 66,597Impairment of oil and natural gas properties— 245,536 814,798 — —Non-cash equity-based compensation expense34,178 33,532 24,572 14,253 2,724Capitalized equity-based compensation expense(8,641) (7,079) (6,043) (4,437) (972)Asset retirement obligation accretion expense1,391 1,064 833 467 201Loss on extinguishment of debt— 33,134 — — —Income tax (benefit) provision(19,568) 192 (201,310) 108,985 31,754Non-controlling interest in net (income) loss(47,631) 843 (7,940) (4,316) —Consolidated Adjusted EBITDA$928,039 $387,535 $449,245 $398,334 $157,60448Table of ContentsITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSThe following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto appearingelsewhere in this Annual Report on Form 10–K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates,beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statementsdue to a number of factors. See Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”OverviewWe are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional,onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the horizontal development of the Wolfcampand Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop ourreserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potentialdrilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenuesare generated through the sale of oil, natural gas liquids and natural gas production.The following table sets forth our production data for the periods indicated: Year Ended December 31, 2017 2016 2015Oil (MBbls)74% 73% 75%Natural gas (MMcf)12% 11% 11%Natural gas liquids (MBbls)14% 16% 14% 100% 100% 100%On December 31, 2017, our acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres, which consisted ofapproximately 117,586 gross (101,941 net) acres in the Northern Midland Basin and approximately 128,426 gross (104,719 net) acres in the SouthernDelaware Basin.2017 Transactions and Recent DevelopmentsOur Delaware Basin AcquisitionOn February 28, 2017, we completed an acquisition of oil and natural gas properties, midstream assets and other related assets in the Delaware Basinfor an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of our common stock, of which approximately 1.15 million shareswere placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos andReeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. We used the net proceeds from our December 2016equity offering, net proceeds from our December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase pricefor this acquisition.New Senior NotesOn January 29, 2018, we issued $300.0 million aggregate principal amount of new 2025 notes as additional notes under our existing indenture,dated as of December 20, 2016, as supplemented, among us, subsidiary guarantors party thereto and Wells Fargo, as trustee, under which we previously issued$500.0 million aggregate principal amount of our existing 5.375% Senior Notes due 2025. We received approximately $308.4 million in net proceeds, afterdeducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes.We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.49Table of ContentsViper Equity OfferingsIn January 2017, Viper completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issuedpursuant to an option to purchase additional common units granted to the underwriters. Viper received net proceeds from this offering of approximately$147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $120.5 million to repay theoutstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additionalacquisitions.In July 2017, Viper completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issuedpursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, an affiliate ofthe General Partner purchased 3,000,000 common units and certain officers and directors of our Company and the General Partner purchased an aggregate of114,000 common units, in each case directly from the underwriters. Following this offering, we had an approximate 64% limited partner interest in Viper.Viper received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimatedoffering expenses, of which Viper used $152.8 million to repay all of the then-outstanding borrowings under Viper’s revolving credit facility and the balancewas used to fund a portion of the purchase price for acquisitions and for general partnership purposes.Operational UpdateWe are operating ten rigs now and currently intend to operate between ten and twelve drilling rigs in 2018 across our asset base in the Midland andDelaware Basins. We plan to operate six to seven of these rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberryformations, with four to five rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring formations.In the Midland Basin, we continue have positive results across our core development areas located within Midland, Martin, Howard, Glasscock andAndrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations. Weare currently operating six rigs on the acreage and expect to average approximately six to eight operated rigs in 2018.In the Delaware Basin, we have now drilled and completed multiple wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which webelieve has been de-risked across a significant portion of our total acreage position and remains our primary development target. Additionally, we havesuccessfully completed additional wells targeting such zones as the Wolfcamp B and 2nd Bone Spring, and expect to test these zones further in 2018. We arecurrently operating four rigs in the Delaware Basin and plan to average approximately four to five rigs in 2018.We continue to focus on low cost operations and best in class execution. In doing so, we are focused on controlling oilfield service costs as ourservice providers seek to increase pricing following continued strength in the oil market. To combat rising service costs, we have looked to lock in pricing fordedicated activity levels and will continue to seek opportunities to control additional well cost where possible. Our 2018 drilling and completion budgetaccounts for rising capital costs that we believe will cover potential increases in our service costs during the year.2018 Capital BudgetWe have currently budgeted a 2018 total capital spend of $1.3 billion to $1.5 billion, consisting of $1.175 billion to $1.325 billion for horizontaldrilling and completions including non-operated activity and $125.0 million to $175.0 million for infrastructure and other expenditures, but excluding thecost of any leasehold and mineral interest acquisitions. We expect to drill and complete 170 to 190 gross horizontal wells in 2018.Operating Results OverviewThe following table summarizes our average daily production for the periods presented: Year Ended December 31, 2017 2016 2015Oil (Bbls)/d58,678 31,590 24,880Natural Gas (Mcf)/d56,602 29,313 21,729Natural Gas Liquids (Bbls)/d11,112 6,556 4,596Total average production per day79,224 43,031 33,09850Table of ContentsOur average daily production for the year ended December 31, 2017 as compared to the year ended December 31, 2016 increased by 36,193 BOE/d,or 84%.During the year ended December 31, 2017, we drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated horizontal wells in the Permian Basin.Reserves and pricingRyder Scott prepared estimates of our proved reserves at December 31, 2017, 2016 and 2015 (which include estimated proved reserves attributableto Viper). The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life ofthe properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affectingthe price received at the wellhead. 2017 2016 2015Estimated Net Proved Reserves: Oil (MBbls)233,181 139,174 105,979Natural gas (MMcf)285,369 174,896 149,503Natural gas liquids (MBbls)54,610 37,134 26,004Total (MBOE)335,352 205,458 156,899 Unweighted Arithmetic Average First-Day-of-the-Month Prices 2017 2016 2015Oil (per Bbl)$48.03 $39.94 $45.07Natural gas (per Mcf)$2.06 $1.36 $1.83Natural gas liquids (per Bbl)$20.79 $12.91 $12.56Sources of our revenueOur revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our naturalgas during processing. Our oil and natural gas revenues do not include the effects of derivatives. Our revenues may vary significantly from period to period asa result of changes in volumes of production sold, production mix or commodity prices.The following table presents the sources of our revenues for the years presented: Year Ended December 31, 2017 2016 2015Revenues Oil sales88% 89% 91%Natural gas sales4% 4% 4%Natural gas liquid sales8% 7% 5% 100% 100% 100% Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gasliquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2017, WTI posted prices ranged from$42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On December 29, 2017, the WTI postedprice for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. Lower prices may not only decrease ourrevenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in areduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.51Table of ContentsPrincipal components of our cost structureLease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the dailycosts incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gasproperties.Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold atfixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxingjurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuationof our oil and gas properties.General and administrative expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs ofmaintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional servicesand legal compliance.Midstream services expense. These are costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, naturalgas lift, compression infrastructure and water transportation facilities.Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematicallyexpense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types ofcosts: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yetbe assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimateddismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight linemethod over their estimated useful lives, which range from three to fifteen years.Impairment of oil and natural gas properties. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.Other income (expense)Interest income (expense). We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowingsunder our revolving credit facility and our net proceeds from the issuance of the senior notes. We incur interest expense that is affected by both fluctuationsin interest rates and our financing decisions. This amount reflects interest paid to our lender plus the amortization of deferred financing costs (includingorigination and amendment fees), commitment fees and annual agency fees net of interest received on our cash and cash equivalents.Gain (loss) on derivative instruments, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the priceof crude oil. This amount represents (i) the recognition of the change in the fair value of open non-hedge derivative contracts as commodity prices changeand commodity derivative contracts expire or new ones are entered into, and (ii) our gains and losses on the settlement of these commodity derivativeinstruments.Deferred tax assets (liabilities). We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilitiesare recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existingassets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable tothe future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets andliabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likelythan not the deferred tax assets will not be realized.52Table of ContentsResults of OperationsThe following table sets forth selected historical operating data for the periods indicated. Year Ended December 31, 2017 2016 2015 (in thousands)Revenues Oil, natural gas liquids and natural gas$1,186,275 $527,107 $446,733Lease bonus11,764 — —Midstream services7,072 — —Total revenues1,205,111 527,107 446,733Operating expenses Lease operating expenses126,524 82,428 82,625Production and ad valorem taxes73,505 34,456 32,990Gathering and transportation12,834 11,606 6,091Midstream services10,409 — —Depreciation, depletion and amortization326,759 178,015 217,697Impairment of oil and natural gas properties— 245,536 814,798General and administrative expenses48,669 42,619 31,968Asset retirement obligation accretion1,391 1,064 833Total expenses600,091 595,724 1,187,002Income (loss) from operations605,020 (68,617) (740,269)Interest expense, net(40,554) (40,684) (41,510)Other income, net10,235 3,064 728Gain (loss) on derivative instruments, net(77,512) (25,345) 31,951Loss on extinguishment of debt— (33,134) —Total other expense, net(107,831) (96,099) (8,831)Income (loss) before income taxes497,189 (164,716) (749,100)Provision for (benefit from) income taxes(19,568) 192 (201,310)Net income (loss)516,757 (164,908) (547,790)Net income attributable to non-controlling interest34,496 126 2,838Net income (loss) attributable to Diamondback Energy, Inc.$482,261 $(165,034) $(550,628)53Table of Contents Year Ended December 31, 2017 2016 2015Production Data: Oil (MBbls)21,418 11,562 9,081Natural gas (MMcf)20,660 10,728 7,931Natural gas liquids (MBbls)4,056 2,399 1,678Combined volumes (MBOE)28,917 15,749 12,081Daily combined volumes (BOE/d)79,224 43,031 33,098 Average Prices: Oil (per Bbl)$48.75 $40.70 $44.68Natural gas (per Mcf)2.53 2.10 2.47Natural gas liquids (per Bbl)22.20 14.20 12.77Combined (per BOE)41.02 33.47 36.98Oil, hedged ($ per Bbl)(1)48.94 40.80 60.63Natural gas, hedged ($ per MMbtu)(1)2.65 2.06 2.47Average price, hedged ($ per BOE)(1)41.26 33.54 48.97 Average Costs per BOE: Lease operating expense$4.38 $5.23 $6.84Production and ad valorem taxes2.54 2.19 2.73Gathering and transportation expense0.44 0.74 0.50General and administrative - cash component0.80 1.03 1.11Total operating expense - cash$8.16 $9.19 $11.18 General and administrative - non-cash component$0.88 $1.68 $1.54Depreciation, depletion and amortization11.30 11.30 18.02Interest expense1.40 2.58 3.44Total expenses$13.58 $15.56 $23.00 Average realized oil price ($/Bbl)$48.75 $40.70 $44.68Average NYMEX ($/Bbl)$50.80 $43.29 $48.66Differential to NYMEX$(2.05) $(2.59) $(3.98)Average realized oil price to NYMEX96% 94% 92% Average realized natural gas price ($/Mcf)$2.53 $2.10 $2.47Average NYMEX ($/Mcf)$2.99 $2.52 $2.62Differential to NYMEX$(0.46) $(0.42) $(0.15)Average realized natural gas price to NYMEX85% 83% 94% Average realized natural gas liquids price ($/Bbl)$22.20 $14.20 $12.77Average NYMEX oil price ($/Bbl)$50.80 $43.29 $48.66Average realized natural gas liquids price to NYMEX oil price44% 33% 26%(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realizedgains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.54Table of ContentsComparison of the Years Ended December 31, 2017 and 2016Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $659.2million, or 125%, to $1.2 billion for the year ended December 31, 2017 from $527.1 million for the year ended December 31, 2016. Our revenues are afunction of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily productionsold increased by 36,193 BOE/d to 79,224 BOE/d during the year ended December 31, 2017 from 43,031 BOE/d during the year ended December 31, 2016.The total increase in revenue of approximately $659.2 million is attributable to higher oil, natural gas liquids and natural gas production volumes and higheraverage sales prices for the year ended December 31, 2017 as compared to the year ended December 31, 2016. The increases in production volumes were dueto a combination of increased drilling activity and growth through acquisitions. Our production increased by 9,856 MBbls of oil, 1,656 MBbls of natural gasliquids and 9,931 MMcf of natural gas for the year ended December 31, 2017 as compared to the year ended December 31, 2016.The net dollar effect of the increases in prices of approximately $213.7 million (calculated as the change in period-to-period average pricesmultiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production ofapproximately $445.4 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the periodaverage prices) are shown below. Change in prices Productionvolumes(1) Total net dollareffect of change (in thousands)Effect of changes in price: Oil$8.05 21,418 $172,403Natural gas liquids$8.00 4,056 $32,446Natural gas$0.43 20,660 $8,884Total revenues due to change in price $213,733 Change inproductionvolumes(1) Prior periodaverage prices Total net dollareffect of change (in thousands)Effect of changes in production volumes: Oil9,856 $40.70 $401,080Natural gas liquids1,656 $14.20 $23,521Natural gas9,931 $2.10 $20,834Total revenues due to change in production volumes $445,435Total change in revenues $659,168(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.Lease Bonus Revenue. Lease bonus revenue was $11.8 million for the year ended December 31, 2017, $2.8 million of which was attributable tolease bonus payments to extend the term of seven leases, reflecting an average bonus of $3,442 per acre and the remaining $9.1 million was attributable tolease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre. We had no lease bonus revenue for the year ended December 31,2016.Midstream Services Revenue. Midstream services revenue was $7.1 million for the year ended December 31, 2017. We had no midstream servicesrevenue for the year ended December 31, 2016. Our midstream services revenue represents fees charged to our joint interest owners and third parties for thetransportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where wehave significant production.Lease Operating Expenses. Lease operating expenses were $126.5 million ($4.38 per BOE) for the year ended December 31, 2017, an increase of$44.1 million from $82.4 million ($5.23 per BOE) for the year ended December 31, 2016. The increase in lease operating expense was due to an increase of234 producing wells compared to 2016. This increase was offset by higher production volumes which resulted in a decrease in lease operating expense perBOE.Production and Ad Valorem Taxes. Production and ad valorem taxes increased to $73.5 million for the year ended December 31, 2017 from $34.5million for the year ended December 31, 2016. In general, production taxes and ad valorem55Table of Contentstaxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas productiontaxes are based upon current year commodity prices. The increase in production and ad valorem taxes during the year ended December 31, 2017 as comparedto 2016 was primarily due to an increase in our production taxes as a result of increased commodity prices and volumes.Midstream Services Expense. Midstream services expense was $10.4 million for the year ended December 31, 2017. We had no midstream servicesexpense for the year ended December 31, 2016. Midstream services expense represents costs incurred to operate and maintain our oil and natural gasgathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $148.7 million, or 84%, from $178.0million for the year ended December 31, 2016 to $326.8 million for the year ended December 31, 2017.The following table provides components of our depreciation, depletion and amortization expense for the periods presented: Year Ended December 31, 2017 2016 (in thousands, except BOE amounts)Depletion of proved oil and natural gas properties$321,870 $176,369Depreciation of midstream assets3,451 252Depreciation of other property and equipment1,438 1,394Depreciation, depletion and amortization expense$326,759 $178,015Oil and natural gas properties depreciation, depletion and amortization expense per BOE$11.11 $11.23Total depreciation, depletion and amortization expense per BOE$11.30 $11.30The increase in depletion of proved oil and natural gas properties of $145.5 million for the year ended December 31, 2017 as compared to the yearended December 31, 2016 resulted primarily from higher production levels and an increase in net book value on new reserves added.Impairment of Oil and Natural Gas Properties. During the year ended December 31, 2016, we recorded an impairment of oil and gas properties of$245.5 million as a result of the significant decline in commodity prices, which resulted in a reduction of the discounted present value of our proved oil andnatural gas reserves. We did not record an impairment of oil and natural gas properties during the year ended December 31, 2017. General and Administrative Expenses. General and administrative expenses increased $6.1 million from $42.6 million for the year ended December31, 2016 to $48.7 million for the year ended December 31, 2017. The increase was due to an increase in salaries and benefits expense as a result of an increasein workforce.Net Interest Expense. Net interest expense for the year ended December 31, 2017 was $40.6 million as compared to $40.7 million for the year endedDecember 31, 2016, a decrease of $0.1 million. This decrease was due primarily to the issuance in October 2016 of new senior notes due 2024 with a lowerinterest rate than the senior notes which we redeemed in the fourth quarter of 2016 partially offset by the interest on the additional senior notes due in 2025that we issued in December 2016.Gain (Loss) on Derivative Instruments, Net. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilitiesmeasured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instrumentsto fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the lineitem captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2017 and 2016, we had a cash gain on settlement of derivativeinstruments of $6.7 million and $1.2 million, respectively. For the year ended December 31, 2017 and 2016, we had a negative change in the fair value ofopen derivative instruments of $84.2 million and $26.5 million, respectively.Provision for (Benefit from) Income Taxes. We recorded an income tax benefit of $19.6 million for the year ended December 31, 2017 as comparedto an income tax provision of $0.2 million for the year ended December 31, 2016. Our effective tax rate was (3.9)% for the year ended December 31, 2017 ascompared to (0.1)% for the year ended December 31, 2016. The change in our income tax provision for the year ended December 31, 2017 as compared to theyear ended December 31, 2016 is primarily due to the reduction in our valuation allowance against deferred tax assets, as well as the favorable impact of the56Table of Contentsreduction in the federal statutory tax rate enacted in December 2017. While we generated positive pre-tax income from continuing operations in 2017, our2017 effective tax rate was negative due to the income tax benefit generated by these items.57Table of ContentsComparison of the Years Ended December 31, 2016 and 2015Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $80.4million, or 18%, to $527.1 million for the year ended December 31, 2016 from $446.7 million for the year ended December 31, 2015. Our revenues are afunction of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily productionsold increased by 9,933 BOE/d to 43,031 BOE/d during the year ended December 31, 2016 from 33,098 BOE/d during the year ended December 31, 2015.The total increase in revenue of approximately $80.4 million is largely attributable to higher oil, natural gas liquids and natural gas production volumespartially offset by lower average sales prices for the year ended December 31, 2016 as compared to the year ended December 31, 2015. The increases inproduction volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 2,481 MBbls ofoil, 722 MBbls of natural gas liquids and 2,797 MMcf of natural gas for the year ended December 31, 2016 as compared to the year ended December 31,2015.The net dollar effect of the decreases in prices of approximately $46.6 million (calculated as the change in period-to-period average pricesmultiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production ofapproximately $126.9 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the periodaverage prices) are shown below. Change in prices Productionvolumes(1) Total net dollareffect of change (in thousands)Effect of changes in price: Oil$(3.98) 11,562 $(46,031)Natural gas liquids$1.43 2,399 $3,431Natural gas$(0.37) 10,728 $(3,970)Total revenues due to change in price $(46,570) Change inproductionvolumes(1) Prior periodaverage prices Total net dollareffect of change (in thousands)Effect of changes in production volumes: Oil2,481 $44.68 $110,815Natural gas liquids722 $12.77 $9,219Natural gas2,797 $2.47 $6,910Total revenues due to change in production volumes $126,944Total change in revenues $80,374(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.Lease Operating Expenses. Lease operating expenses were $82.4 million ($5.23 per BOE) for the year ended December 31, 2016, a decrease of $0.2million from $82.6 million ($6.84 per BOE) for the year ended December 31, 2015. The decrease is a result of efficiencies we achieved in our field operations.Upon becoming the operator of wells acquired in our acquisitions, we seek to achieve the efficiencies in those wells that we have established with ourexisting portfolio of wells.Production and Ad Valorem Taxes. Production and ad valorem taxes increased to $34.5 million for the year ended December 31, 2016 from $33.0million for the year ended December 31, 2015. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however,Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. The increase inproduction and ad valorem taxes during the year ended December 31, 2016 as compared to 2015 was primarily due to an increase in our production taxes as aresult of increased production partially offset by lower ad valorem taxes.Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $39.7 million, or 18%, from $217.7 millionfor the year ended December 31, 2015 to $178.0 million for the year ended December 31, 2016.58Table of ContentsThe following table provides components of our depreciation, depletion and amortization expense for the periods presented: Year Ended December 31, 2016 2015 (in thousands, except BOE amounts)Depletion of proved oil and natural gas properties$176,369 $216,056Depreciation of midstream assets252 239Depreciation of other property and equipment1,394 1,402Depreciation, depletion and amortization expense$178,015 $217,697Oil and natural gas properties depreciation, depletion and amortization expense per BOE$11.23 $17.84Total depreciation, depletion and amortization expense per BOE$11.30 $18.02The decreases in depletion of proved oil and natural gas properties of $39.7 million for the year ended December 31, 2016 as compared to the yearended December 31, 2015 resulted primarily from the impairment of oil and gas properties recorded in 2016.Impairment of Oil and Natural Gas Properties. During the years ended December 31, 2016 and 2015, we recorded impairments of oil and gasproperties of $245.5 million and $814.8 million, respectively, as a result of the significant decline in commodity prices, which resulted in a reduction of thediscounted present value of our proved oil and natural gas reserves. General and Administrative Expenses. General and administrative expenses increased $10.7 million from $32.0 million for the year endedDecember 31, 2015 to $42.6 million for the year ended December 31, 2016. The increase was due to increases in salaries and benefits expense as a result of anincrease in workforce and equity-based compensation.Net Interest Expense. Net interest expense for the year ended December 31, 2016 was $40.7 million as compared to $41.5 million for the year endedDecember 31, 2015, a decrease of $0.8 million. This decrease was due primarily to the lower average level of outstanding borrowings under our credit facilityduring 2016.Gain (Loss) on Derivative Instruments, Net. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilitiesmeasured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instrumentsto fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the lineitem captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2016 and 2015, we had a cash gain on settlement of derivativeinstruments of $1.2 million and $144.9 million, respectively. For the year ended December 31, 2016 and 2015, we had a negative change in the fair value ofopen derivative instruments of $26.5 million and $112.9 million, respectively.Provision for (Benefit from) Income Taxes. We recorded an income tax expense of $0.2 million for the year ended December 31, 2016 as comparedto an income tax benefit of $201.3 million for the year ended December 31, 2015. Our effective tax rate was (0.1%) for the year ended December 31, 2016 ascompared to 26.9% for the year ended December 31, 2015.59Table of ContentsLiquidity and Capital ResourcesOur primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds fromthe issuance of the senior notes and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oiland natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings,are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow provedreserves and production will be highly dependent on the capital resources available to us.Liquidity and Cash FlowOur cash flows for the years ended December 31, 2017, 2016 and 2015 are presented below: Year Ended December 31, 2017 2016 2015 (in thousands)Net cash provided by operating activities$888,625 $332,080 $416,501Net cash used in investing activities(3,132,282) (1,310,242) (895,050)Net cash provided by financing activities$689,529 $2,624,621 $468,481Net change in cash$(1,554,128) $1,646,459 $(10,068)Operating ActivitiesNet cash provided by operating activities was $888.6 million for the year ended December 31, 2017 as compared to $332.1 million for the yearended December 31, 2016. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase inaverage prices and production growth during the year ended December 31, 2017.Net cash provided by operating activities was $332.1 million for the year ended December 31, 2016 as compared to $416.5 million for the yearended December 31, 2015. The decrease in operating cash flows is primarily the result of a higher gain on settlement of derivative instruments during the yearended December 31, 2015 as compared to the year ended December 31, 2016.Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce.Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and othersubstantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “–Sourcesof our revenue” and Item 1A. “Risk Factors” above.Investing ActivitiesThe purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cashfor investing activities of $3.1 billion, $1.3 billion and $895.1 million during the years ended December 31, 2017, 2016 and 2015, respectively.During the year ended December 31, 2017, we spent (a) $860.7 million on capital expenditures in conjunction with our drilling program, in whichwe drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated wells, (b) $68.1 million on additions tomidstream assets, (c) $407.5 million for the acquisition of mineral interests, (d) $1,960.6 million on leasehold acquisitions, (e) $50.3 million for theacquisition of midstream assets and (f) $22.8 million for the purchase of other property and equipment.During the year ended December 31, 2016, we spent (a) $364.3 million on capital expenditures in conjunction with our drilling program, in whichwe drilled 73 gross (61 net) horizontal wells and two gross (one net) vertical wells and participated in the drilling of 19 gross (five net) non-operated wells, (b)$611.3 million on leasehold acquisitions, (c) $205.7 million on royalty interest acquisitions, (d) $9.9 million for the purchase of other property andequipment and (e) $121.4 million was placed in escrow as a deposit under the purchase agreement for oil and natural gas assets located in Pecos and Reevescounties in Texas.60Table of ContentsDuring the year ended December 31, 2015, we spent (a) $419.5 million on capital expenditures in conjunction with our drilling program, in whichwe drilled 64 gross (54 net) horizontal wells and four gross (three net) vertical wells and participated in the drilling of 15 gross (six net) non-operated wells,(b) $437.5 million on leasehold acquisitions, (c) $43.9 million on royalty interest acquisitions and (d) $1.2 million for the purchase of other property andequipment.Our investing activities for the years ended December 31, 2017, 2016 and 2015 are summarized in the following table: Year Ended December 31, 2017 2016 2015 (in thousands)Drilling, completion and infrastructure$(860,738) $(363,087) $(419,512)Additions to midstream assets(68,139) (1,188) —Acquisition of leasehold interests(1,960,591) (611,280) (437,455)Acquisition of mineral interests(407,450) (205,721) (43,907)Acquisition of midstream assets(50,279) — —Purchase of other property and equipment(22,779) (9,891) (1,213)Proceeds from sale of property and equipment65,656 4,661 9,739Funds held in escrow104,087 (121,391) —Equity investments(188) (2,345) (2,702)Net cash used in investing activities$(3,200,421) $(1,310,242) $(895,050)Financing Activities Net cash provided by financing activities for the years ended December 31, 2017, 2016 and 2015 was $689.5 million, $2.6 billion and $468.5million, respectively.During the year ended December 31, 2017, the amount provided by financing activities was primarily attributable to proceeds from Viper’s Januaryand July 2017 equity offerings of $370.3 million as well as borrowings net of repayments of $370.0 million partially offset by distributions to non-controlling interests of $41.4 million.During the year ended December 31, 2016, the amount provided by financing activities was primarily attributable to the aggregate proceeds of $2.1billion from our January, July and December 2016 equity offerings partially offset by repayments of net borrowings of $75.0 million under our credit facility.During the year ended December 31, 2015, the amount provided by financing activities was primarily attributable to the aggregate proceeds of$650.7 million from our January, May and August 2015 equity offerings of $650.7 million partially offset by repayments of net borrowings of $184.5 millionunder our credit facility.2024 Senior NotesOn October 28, 2016, we issued $500.0 million in aggregate principal amount of 4.750% senior notes due 2024, which we refer to as the 2024 seniornotes. The 2024 senior notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year,commencing on May 1, 2017 and will mature on November 1, 2024. All of our existing and future restricted subsidiaries that guarantee our revolving creditfacility or certain other debt guarantee the 2024 senior notes; provided, however, that the 2024 senior notes are not guaranteed by Viper, Viper EnergyPartners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the our future unrestricted subsidiaries.The 2024 senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, asthe trustee, as supplemented. The 2024 indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limitour ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends ormake other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to paymentrestrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactionswith affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.We may on any one or more occasions redeem some or all of the 2024 senior notes at any time on or after November 1, 2019 at the redemption prices(expressed as percentages of principal amount) of 103.563% for the 12-month period beginning61Table of Contentson November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1,2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date ofredemption. Prior to November 1, 2019, we may on any one or more occasions redeem all or a portion of the 2024 senior notes at a price equal to 100% of theprincipal amount of the 2024 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time priorto November 1, 2019, we may on any one or more occasions redeem the 2024 senior notes in an aggregate principal amount not to exceed 35% of theaggregate principal amount of the 2024 senior notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to theredemption date, with an amount equal to the net cash proceeds from certain equity offerings.2025 Senior NotesOn December 20, 2016, we issued $500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting2025 notes, under an indenture (which, as may be amended or supplemented from time to time, is referred to as the 2025 Indenture) among us, the subsidiaryguarantors party thereto and Wells Fargo, as the trustee. On July 27, 2017, we exchanged all of the existing 2025 notes for substantially identical notes in thesame aggregate principal amount that were registered under the Securities Act.On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% senior notes due 2025, which we refer to as the new 2025notes, as additional notes under the 2025 Indenture. The new 2025 notes were issued in a transaction exempt from the registration requirements under theSecurities Act. We refer to the new 2025 notes, together with the existing 2025 notes, as the 2025 senior notes. We received approximately $308.4 million innet proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of thenew 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolvingcredit facility.The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and willmature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the2025 senior notes; provided, however, that the 2025 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC orRattler Midstream LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and theability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make otherdistributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictionsaffecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates,incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.We may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices(expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month periodbeginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any timethereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, we may on any one or more occasionsredeem all or a portion of the 2025 senior notes at a price equal to 100% of the principal amount of the 2025 senior notes plus a “make-whole” premium andaccrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, we may on any one or more occasions redeem the 2025senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 senior notes issued prior to such date at aredemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equityofferings.Under a registration rights agreement executed in connection with the issuance of the new 2025 notes, we and our subsidiary guarantors agreed tofile, subject to certain conditions, a registration statement relating to the new 2025 notes with the SEC pursuant to which we will either offer to exchange thenew 2025 notes for registered notes with substantially identical terms or, in certain circumstances, register the resale of the new 2025 notes. Additionalinterest on the new 2025 notes may become payable if we do not comply with our obligations under the registration rights agreement relating to the new2025 notes.Second Amended and Restated Credit FacilityOur credit agreement dated November 1, 2013, as amended and restated, with a syndicate of banks, including Wells Fargo, as administrative agent,and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger, provides for62Table of Contentsa revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on our oil and natural gas reserves and otherfactors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st,and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, we may request up to two additionalredeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $1.8 billion, we had elected acommitment amount of $1.0 billion and we had borrowings of $397.0 million outstanding under the revolving credit facility. Of this amount, we repaid$308.5 million with the net proceeds from our issuance of the new 2025 notes on January 29, 2018. Immediately following the completion of the new 2025notes offering and the application of our net proceeds thereof, our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decreaseunder our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4million of available borrowing capacity under our revolving credit facility.Diamondback O&G LLC is the borrower under our credit agreement. As of December 31, 2017, the credit agreement is guaranteed by us,Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of our futuresubsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of our assets andthe assets of Diamondback O&G LLC and the guarantors.The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternative base rate (whichis equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus theapplicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR,each of which applicable margin rates is increased by 0.25% per annum if the total debt to EBITDAX ratio is greater than 3.0 to 1.0. The applicable margindepends on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount,the borrowing base and the elected commitment amount. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on theunused portion of the borrowing base, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment.Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid(a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in somecases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of defaultexists under the credit agreement and (c) at the maturity date of November 1, 2022.The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limitadditional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and enteringinto certain swap agreements and require the maintenance of the financial ratios described below.Financial CovenantRequired RatioRatio of total debt to EBITDAXNot greater than 3.0 to 1.0Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior orsenior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance,the borrowing base is reduced by 25% of the stated principal amount of each such issuance.As of December 31, 2017, we were in compliance with all financial covenants under our revolving credit facility. The lenders may accelerate all ofthe indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement containscustomary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change ofcontrol. With certain specified exceptions, the terms and provisions of our revolving credit facility generally may be amended with the consent of the lendersholding a majority of the outstanding loans or commitments to lend.63Table of ContentsViper’s Facility-Wells Fargo BankOn July 8, 2014, Viper entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, assole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $2.0 billionand a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million, subject to scheduled semi-annualand other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st andNovember 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31,2017, the borrowing base was set at $400.0 million, and Viper had $93.5 million of outstanding borrowings and $306.5 million available for futureborrowings under its revolving credit facility.The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by Viper that is equal to an alternate base rate(which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus theapplicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annumin the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as thelesser of the maximum credit amount and the borrowing base. Viper is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per yearon the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment.Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid(a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in somecases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of defaultexists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of Viper and its subsidiary’sassets.The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limitadditional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and enteringinto certain swap agreements and require the maintenance of the financial ratios described below.Financial CovenantRequired RatioRatio of total debt to EBITDAXNot greater than 4.0 to 1.0Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecurednotes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. Aborrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.The lenders may accelerate all of the indebtedness under Viper’s revolving credit facility upon the occurrence and during the continuance of anyevent of default. Viper’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrectrepresentations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breachesof negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.Capital Requirements and Sources of LiquidityOur board of directors approved a 2018 capital budget for drilling and infrastructure of $1.3 billion to $1.5 billion, representing an increase of 60%over our 2017 capital budget. We estimate that, of these expenditures, approximately:•$1.175 billion to $1.325 billion will be spent on drilling and completing 170 to 190 gross (146 to 163 net) horizontal wells across our operatedleasehold acreage in the Northern Midland and Southern Delaware Basins; and•$125.0 million to $175.0 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interestacquisitions.During the year ended December 31, 2017, our aggregate capital expenditures for drilling and infrastructure were $860.7 million. We do not have aspecific acquisition budget since the timing and size of acquisitions cannot be accurately64Table of Contentsforecasted. During the year ended December 31, 2017, we spent approximately $2.0 billion on acquisitions of leasehold interests, primarily related to theBrigham Resources acquisition which closed on February 28, 2017. The amount and timing of these capital expenditures are largely discretionary and within our control. We could choose to defer a portion of theseplanned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipatedprices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits andapprovals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. With recent improvement in oil prices,we are currently operating ten horizontal rigs and four completion crews. We will continue monitoring commodity prices and overall market conditions andcan adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.Based upon current oil and natural gas price and production expectations for 2018, we believe that our cash flow from operations and borrowingsunder our revolving credit facility will be sufficient to fund our operations through year-end 2018. However, future cash flows are subject to a number ofvariables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fullydevelop our properties. Further, our 2018 capital expenditure budget does not allocate any funds for leasehold and mineral interest acquisitions.We monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices,availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractualobligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capitalthrough traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities orother means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or onacceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we maynot be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. Further, if the decline incommodity prices continue, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.Contractual ObligationsThe following table summarizes our contractual obligations and commitments as of December 31, 2017: Payments Due by Period 2018 2019-2020 2021-2022 Thereafter Total (in thousands)Secured revolving credit facility(1)$— $— $397,000 $— $397,000Interest expense related to the secured revolving credit facility2,261 10,522 7,144 — $19,927Senior notes— — — 1,000,000 $1,000,000Interest expense related to the senior notes(2)50,625 101,250 101,250 108,475 $361,600Viper's secured revolving credit facility(1)— — 93,500 — $93,500Interest and commitment fees under Viper's credit agreement(3)1,149 2,299 2,107 — $5,555Asset retirement obligations (4)1,163 — — 20,122 $21,285Drilling commitments(5)21,882 10,082 — — $31,964Sand supply agreements— 18,000 18,000 9,000 $45,000Operating lease obligations(6)3,581 6,234 4,648 7,973 $22,436Fasken Center office building7)99,000 — — — $99,000 $179,661$148,387$623,649$1,145,570 $2,097,267(1)Includes the outstanding principal amount under the revolving credit facilities, the table does not include interest expense or other fees payable underthis floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.(2)Interest represents the scheduled cash payments on the senior notes.(3)Includes only the minimum amount of interest and commitment fees due which, as of December 31, 2017, includes a commitment fee equal to 0.375%per year of the unused portion of the borrowing base of Viper’s credit agreement.(4)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating thesefuture costs requires management to make estimates and judgments that are subject to65Table of Contentsfuture revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. SeeNote 6 of the notes to our consolidated financial statements set forth in Part IV, Item 15 of this Form 10-K.(5)Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a partyon December 31, 2017.(6)Operating lease obligations represent future commitments for building and vehicle leases.(7)Fasken Center office buildings represents the amount we paid on January 31, 2018 at the closing of this transaction. The Fasken building contains ourcorporate offices.Critical Accounting PoliciesThe discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which havebeen prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our moresignificant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions usedin preparation of our financial statements. See Note 2 of the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.Use of EstimatesCertain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management,requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financialstatements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets andliabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonablein the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position orresults of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future netcash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets andliabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.Method of accounting for oil and natural gas propertiesWe account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in theacquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costsand annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicingequipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and developmentactivities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costsunrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments tocapitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided toworking interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions ofcapitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method,whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of provedreserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as agroup if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaininglease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability ofdevelopment if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to datefor such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.66Table of ContentsOil and natural gas reserve quantities and standardized measure of future net revenueOur independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC hasdefined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to berecoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves iscomplex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a givenproperty may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history anda continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimatesoccur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible,the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If suchchanges are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is asubjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserveestimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing andproduction subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantitiesof oil and natural gas that are ultimately recovered.Revenue recognitionOil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. Weaccount for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when our volumes exceed our estimatedremaining recoverable reserves. No receivables are recorded for those wells where we have taken less than our ownership share of production. We did nothave any gas imbalances as of December 31, 2017, 2016 and 2015. Revenues from oil and natural gas services are recognized as services are provided.ImpairmentWe use the full cost method of accounting for our oil and natural gas properties. Under this method, all acquisition, exploration and developmentcosts, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids andnatural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration anddevelopment activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internalcosts not directly associated with exploration and development activities were charged to expense as they were incurred. Costs associated with unevaluatedproperties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. The inclusion of our unevaluatedcosts into the amortization base is expected to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortizedcurrently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter therelationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.Under this method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value ofthe proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost centerceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on thetrailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonmentcosts for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower ofcost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and taxbasis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown isrequired.Asset retirement obligationsWe measure the future cost to retire our tangible long-lived assets and recognize such cost as a liability for legal obligations associated with theretirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The fair value of a liability for anasset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost iscapitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalizedcost is67Table of Contentsdepreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil andnatural gas properties.Our asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Estimating the futurerestoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many yearsin the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relationsconsiderations. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rateand an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact thepresent value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.DerivativesFrom time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oiland natural gas. We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e.,gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type ofhedging relationship. None of our derivatives were designated as hedging instruments during the years ended December 31, 2017, 2016 and 2015. Forderivative instruments not designated as hedging instruments, changes in the fair value of these instruments are recognized in earnings during the period ofchange.Accounting for Equity-Based CompensationWe grant various types of equity-based awards including stock options and restricted stock units. These plans and related accounting policies aredefined and described more fully in Note 10–Equity-Based Compensation. Stock compensation awards are measured at fair value on the date of grant and areexpensed, net of estimated forfeitures, over the required service period.Income TaxesWe use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future taxconsequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2)operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when thosetemporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in incomein the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets willnot be realized.Recent Accounting PronouncementsRecently Issued PronouncementsIn May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”.This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transferspromised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goodsor services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers.We will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. We have reviewed variouscontracts that represent our material revenue streams and determined that there will be no impact to our financial position, results of operations or liquidity.Upon adoption of this Accounting Standards Update, we will not be required to record a cumulative effect adjustment due to the new Accounting StandardsUpdate not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, we will not be required toalter our existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenuecontracts entered into by us. We do not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how wepresent information regarding our revenue streams as compared to existing GAAP.In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. Thisupdate applies to any entity that holds financial assets or owes financial liabilities. This update68Table of Contentsrequires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured atfair value with changes in fair value recognized in net income. Viper will adopt this standard effective January 1, 2018 by means of a cumulative-effectadjustment which will decrease Viper’s Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for thatinvestment.In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classificationof Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update providesguidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debtinstruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration paymentsmade after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies,including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions andseparately identifiable cash flows and application of the predominance principle. We will adopt this update effective January 1, 2018 using the retrospectivetransition method. Adoption of this standard will change the presentation of our cash flows and will not have a material impact on our consolidated financialstatements.In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - RestrictedCash”. This update affects entities that have restricted cash or restricted cash equivalents. We adopted this update retrospectively effective January 1, 2018.Adoption of this standard will change the presentation of our cash flows and will not have a material impact on our consolidated financial statements.In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying theDefinition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen todetermine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) isconcentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. We will adopt this update prospectively effectiveJanuary 1, 2018. The adoption of this update will not have an impact on our financial position, results of operations or liquidity.Accounting Pronouncements Not Yet AdoptedIn February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to anyentity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position aliability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While therewere no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effectivefor public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. Webelieve the primary impact of adopting this standard will be the recognition of assets and liabilities on our balance sheet for current operating leases. We arestill evaluating the impact of this standard.In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”.This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendmentsaffect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financialassets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal yearsbeginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustmentto retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard willhave a material impact on our consolidated financial statements since we do not have a history of credit losses.InflationInflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the years endedDecember 31, 2017, 2016 and 2015. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economyand we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in ourareas of operations.69Table of ContentsOff-balance Sheet ArrangementsWe had no off-balance sheet arrangements as of December 31, 2017. Please read Note 15 included in Notes to the Consolidated Financial Statementsset forth in Part IV, Item 15 of this Form 10-K, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheetsunder GAAP.ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKCommodity Price RiskOur major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by theprevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has beenvolatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on manyfactors outside of our control.We use price swap derivatives, including basis swaps and costless collars, to reduce price volatility associated with certain of our oil and natural gassales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period isless than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swapprice. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEXWTI and Crude Oil Brent and with natural gas derivative settlements based on NYMEX Henry Hub. At December 31, 2017 and 2016, we had a net liability derivative position of $106.7 million and $22.6 million, respectively, related to our priceswap and price basis swap derivatives. Utilizing actual derivative contractual volumes under our fixed price swaps and fixed price basis swaps as ofDecember 31, 2017, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $180.2million, an increase of $74.1 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the netliability derivative position to $32.1 million, a decrease of $74.1 million. However, any cash derivative gain or loss would be substantially offset by adecrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.Counterparty and Customer Credit RiskOur principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $73.0 million at December 31,2017) and receivables from the sale of our oil and natural gas production (approximately $158.6 million at December 31, 2017).We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require ourcustomers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adverselyaffect our financial results. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US)Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers eachaccounted for more than 10% of our revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%).For the year ended December 31, 2015, two purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and EnterpriseCrude Oil LLC (15%). No other customer accounted for more than 10% of our revenue during these periods.Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wellsprimarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.At December 31, 2017, we had three customers that represented approximately 74% of our total joint operations receivables. At December 31, 2016, we hadthree customer that represented approximately 75% of our total joint operations receivables.Interest Rate RiskWe are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of ourrevolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate,the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin rangesfrom 0.25% to 1.25% in the case of the70Table of Contentsalternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to theborrowing base.As of December 31, 2017, we had $397.0 million borrowings outstanding under our revolving credit facility. Our weighted average interest rate onborrowings under our revolving credit facility was 2.97% on December 31, 2017. An increase or decrease of 1% in the interest rate would have acorresponding decrease or increase in our interest expense of approximately $4.0 million based on the $397.0 million outstanding in the aggregate under ourrevolving credit facility as of such date.ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this item appears beginning on page F-1 of this report.ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURENone.ITEM 9A. CONTROLS AND PROCEDURESEvaluation of Disclosure Control and ProceduresUnder the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined inRule 13a-15(e) and 15d-15(e) under the Exchange Act that are designed to ensure that information required to be disclosed by us in the reports that we file orsubmit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Thedisclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our ChiefExecutive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating thedisclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that thereare resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to theircosts.As of December 31, 2017, an evaluation was performed under the supervision and with the participation of management, including our ChiefExecutive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as ofDecember 31, 2017, our disclosure controls and procedures are effective.Changes in Internal Control over Financial ReportingThere have not been any changes in our internal control over financial reporting that occurred during the year ended December 31, 2017 that havematerially affected, or are reasonably likely to materially affect, internal controls over financial reporting.71Table of ContentsMANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTINGThe management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’sinternal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposesin accordance with generally accepted accounting principles.Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in the2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluationunder the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Company’s internalcontrol over financial reporting and determined that the Company maintained effective internal control over financial reporting as of December 31, 2017.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof compliance with the policies or procedures may deteriorate.Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company includedin this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company’s internal control over financial reporting at December 31,2017. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31,2017, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”72Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMBoard of Directors and StockholdersDiamondback Energy, Inc.Opinion on internal control over financial reportingWe have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the“Company”) as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal controlover financial reporting as of December 31, 2017, based on the 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”), theconsolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated February 14, 2018 expressed anunqualified opinion on those financial statements.Basis for opinionThe Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of theeffectiveness of internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in theaccompanying Management’s Report 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 are required to be independent withrespect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtainreasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtainingan understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design andoperating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.We believe that our 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 the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,accurately and fairly reflect the transactions 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 that receipts and expenditures of thecompany are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on thefinancial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof compliance with the policies or procedures may deteriorate./s/ GRANT THORNTON LLPOklahoma City, OklahomaFebruary 14, 201873ITEM 9B. OTHER INFORMATIONNone.PART IIIITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEInformation as to Item 10 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within120 days after the close of the year ended December 31, 2017.We have adopted a Code of Business Conduct and Ethics that applies to our Chief Executive Officer, Chief Financial Officer, principal accountingofficer and controller and persons performing similar functions. Any amendments to or waivers from the code of business conduct and ethics will be disclosedon our website. The Company also has made the Code of Business Conduct and Ethics available on our website under the “Corporate Governance” section athttp://ir.diamondbackenergy.com. We intend to satisfy the disclosure requirements under Item 5.05 of Form 8-K regarding an amendment to, or waiver from, aprovision of the Code of Business Conduct and Ethics by posting such information on our website at the address specified above.ITEM 11. EXECUTIVE COMPENSATIONInformation as to Item 11 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within120 days after the close of the year ended December 31, 2017.ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERSInformation as to Item 12 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within120 days after the close of the year ended December 31, 2017.ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCEInformation as to Item 13 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within120 days after the close of the year ended December 31, 2017.ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICESInformation as to Item 14 will be set forth in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within120 days after the close of the year ended December 31, 2017.ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(a)Documents included in this report: 1. Financial Statements Report of Independent Registered Public Accounting FirmF-1 Consolidated Balance SheetsF-2 Consolidated Statements of OperationsF-3 Consolidated Statement of Stockholders' EquityF-4 Consolidated Statements of Cash FlowsF-5 Notes to Consolidated Financial StatementsF-7 2. Financial Statement Schedules Financial statement schedules have been omitted because they are either not required, not applicable or the information required to bepresented is included in the Company’s consolidated financial statements and related notes. 743. ExhibitsExhibit Number Description2.1# Purchase and Sale Agreement dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw ProductionLP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. CraigCorbett, Bambana Resources LP, and FC Permian Properties, Inc., as Sellers, and Diamondback E&P LLC, as Buyer (incorporated byreference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).2.2# Purchase and Sale Agreement, dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw ProductionLP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. CraigCorbett, Bambana Resources LP, FC Permian Properties, Inc., Blake Braun, Richard D. Campbell, and Thomas J. Woodside, as Sellers,and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 001-35700, filed by theCompany with the SEC on February 18, 2014).2.3# Purchase and Sale Agreement by and among Rio Oil and Gas, LLC, Rio Oil and Gas (Permian) LLC, Rio Oil and Gas (OPCO), LLC,Bluestem Energy, LP, Bluestem Energy Partners, LP, Bluestem Energy Holdings, LLC, Bluestem Energy Assets, LLC, BluestemAcquisitions, LLC, BC Operating, Inc., Crown Oil Partners V, LP and Crump Energy Partners II, LLC, as sellers, and Diamondback E&PLLC, as buyer, dated July 18, 2014 (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by theCompany with the SEC on July 21, 2014).2.4# Purchase and Sale Agreement, dated as of December 13, 2016, by and among Brigham Resources Operating, LLC and BrighamResources Midstream, LLC, as sellers, and Diamondback E&P LLC and Diamondback Energy, Inc., as buyers (incorporated by referenceto Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 14, 2016).3.1 Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No.001-35700, filed by the Company with the SEC on November 16, 2012).3.2 Certificate of Amendment No. 1 of the Amended and Restated Certificate of Incorporation of the Company (incorporated by reference toExhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 12, 2016).3.3 Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filedby the Company with the SEC on November 16, 2012).4.1 Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 toAmendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20,2012).4.2 Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC(incorporated by reference to Exhibit 4.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16,2012).4.3 Indenture, dated as of October 28, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, NationalAssociation, as trustee (including the form of Diamondback Energy, Inc.’s 4.750 % Senior Notes due 2024) (incorporated by reference toExhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 2, 2016).4.4 Indenture, dated as of December 20, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank,National Association, as trustee (including the form of Diamondback Energy, Inc.’s 5.375% Senior Notes due 2025) (incorporated byreference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 21, 2016).4.5 First Supplemental Indenture, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and WellsFargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by theCompany with the SEC on January 30, 2018).4.6 Registration Rights Agreement, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and WellsFargo Securities, LLC (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with theSEC on January 30, 2018).4.7 Registration Rights Agreement, dated as of February 28, 2017, among Diamondback Energy, Inc., Brigham Resources, LLC, BrighamResources Operating, LLC and Brigham Resources Upstream Holdings, LP. (incorporated by reference to Exhibit 4.1 to the Form 8-K,File No. 001.35700, filed by the Company with the SEC on March 6, 2017).10.1 Diamondback Energy, Inc. 2016 Amended and Restated Equity Incentive Plan (incorporated by reference to Appendix A to ScheduleDEFA 14A filed by the Company with the SEC on May 25, 2016).10.2+ Form of Stock Option Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Registration Statement onForm S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).753. Exhibits10.3+ Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the RegistrationStatement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).10.4+ Form of Director and Officer Indemnification Agreement (incorporated by reference toExhibit 10.15 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with theSEC on August 20, 2012).10.5 Advisory Services Agreement, dated as of October 11, 2012, by and between Diamondback Energy, Inc. and Wexford Capital LP(incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16,2012).10.6 Merger Agreement, dated as of October 11, 2012, by and between the Company and Diamondback Energy LLC (incorporated byreference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).10.7+ Amended and Restated Employment Agreement, dated April 24, 2014, effective as of April 18, 2014, by and between Travis D. Sticeand Diamondback E&P LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-035700, filed by the Companywith the SEC on May 9, 2014 ).10.8+ Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between TeresaDick and Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 8-K, File No. 001-35700, filed by theCompany with the SEC on March 5, 2014).10.9+ Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and betweenMichael Hollis and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K, File No. 001-35700, filed bythe Company with the SEC on March 5, 2014).10.10+ Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between JeffWhite and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K, File No. 001-35700, filed by theCompany with the SEC on March 5, 2014).10.11+ Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between RussellPantermuehl and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-035700, filed bythe Company with the SEC on May 9, 2014 ).10.12+ 2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700,filed by the Company with the SEC on April 2, 2014).10.13+ Form of Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).10.14+ Form of Performance-Based Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K, FileNo. 001-35700, filed by the Company with the SEC on March 5, 2014).10.15 Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated byreference to Exhibit 10.7 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Companywith the SEC on June 11, 2012).10.16 Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor PermianLLC (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502,filed by the Company with the SEC on May 8, 2012).10.17 Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor PermianLLC (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502,filed by the Company with the SEC on May 8, 2012).10.18 Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and WindsorPermian LLC (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).10.19 Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC(incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filedby the Company with the SEC on May 8, 2012).763. Exhibits10.20 Lease Amendment No. 5 to Lease Agreement, dated as of July 25, 2012, by and between Fasken Midland, LLC and Diamondback E&PLLC (incorporated by reference to Exhibit 10.36 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502,filed by the Company with the SEC on October 2, 2012).10.21 Contribution Agreement, dated May 7, 2012, by and between the Company and Gulfport Energy Corporation (incorporated byreference to Exhibit 10.18 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Companywith the SEC on May 8, 2012).10.22 Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC(incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filedby the Company with the SEC on May 8, 2012).10.23 Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company (incorporated byreference to Exhibit 10.20 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Companywith the SEC on May 8, 2012).10.24 Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC(incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filedby the Company with the SEC on May 8, 2012).10.25 Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC(incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filedby the Company with the SEC on May 8, 2012).10.26 Crude Oil Purchase Agreement, dated May 24, 2012, by and between Windsor Permian LLC and Shell Trading (US) Company(incorporated by reference to Exhibit 10.26 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filedby the Company with the SEC on August 20, 2012).10.27 Master Drilling Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and FieldServices LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC onFebruary 1, 2013).10.28 Master Field Services Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and FieldServices LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC onFebruary 1, 2013).10.29 First Amendment to Master Field Services Agreement, dated as of February 21, 2013, by and between Diamondback E&P LLC andBison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.35 to the Form 10-K, file No. 001-35700, filed by theCompany with the SEC on March 1, 2013).10.30+ Form of Amendment to Restricted Stock Unit Certificate (incorporated by reference to Exhibit 10.38 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).10.31 Lease Amendment No. 6 effective May 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between FaskenMidland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.39 to the Form 10-K/A, file No. 001-35700, filed bythe Company with the SEC on April 10, 2013).10.32 Lease Amendment No. 7 effective September 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and betweenFasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700,filed by the Company with the SEC on August 8, 2013).10.33 Lease Amendment No. 8 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between FaskenMidland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed bythe Company with the SEC on August 8, 2013).10.34 Lease Amendment No. 9 effective August 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between FaskenMidland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-35700, filed bythe Company with the SEC on November 5, 2013).10.35 Lease Amendment No. 10 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between FaskenMidland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q, File No. 001-35700, filed bythe Company with the SEC on November 5, 2013).10.36 Second Amended and Restated Credit Agreement, dated as of November 1, 2103, among Diamondback Energy, Inc., as parentguarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lendersparty thereto (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC onNovember 5, 2013).773. Exhibits10.37 First Amendment, dated June 9, 2014, to the Second Amended and Restated Credit Agreement, originally dated November 1, 2013, byand among the Company, as parent guarantor, Diamondback O&G LLC, as borrower, each of the guarantors party thereto, each of thelenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 tothe Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 7, 2014).10.38 Second Amendment to the Second Amended and Restated Credit Agreement, dated as of November 13, 2014, among DiamondbackEnergy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, the guarantors, Wells Fargo Bank, National Association, asadministrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filedby the Company with the SEC on November 18, 2014).10.39 Third Amendment, dated as of June 21, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013,by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries ofDiamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Companywith the SEC on June 27, 2016).10.40 Fourth Amendment, dated as of December 15, 2016, to the Second Amended and Restated Credit Agreement, dated as of November 1,2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries ofDiamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto(incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by the Companywith the SEC on December 20, 2016).10.41 Fifth Amendment, dated as of November 28, 2017, to the Second Amended and Restated Credit Agreement, dated as of November 1,2013, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries ofDiamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders partythereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 001-35700, filed by theCompany with the SEC on December 4, 2017).10.42 Senior Secured Revolving Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, Wells Fargo Bank,National Association, as the administrative agent, sole book runner and lead arranger, and certain lenders from time to time partythereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-36505, filed by Viper Energy Partners LP on July 14,2014).10.43 Contribution Agreement by and among Diamondback Energy, Inc., Viper Energy Partners LLC, Viper Energy Partners GP LLC andViper Energy Partners LP, dated as of June 17, 2014 (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700,filed by Viper Energy Partners LP with the SEC on May 7, 2014).10.44 First Amendment, dated as of August 15, 2014, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, asborrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto(incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 10,2015).10.45 Second Amendment, dated as of May 22, 2015, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, asborrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto(incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 6,2015).10.46 Third Amendment, dated as of June 21, 2016, to the Credit Agreement, dated as of July 8, 2014, by and among Viper Energy PartnersLP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank, National Association, as administrative agent, and thelenders party thereto (incorporated by reference to Exhibit 10.1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed June27, 2016).10.47 Fourth Amendment, dated as of October 28, 2016, to the Credit Agreement, dated as of July 8, 2014, by and among Viper EnergyPartners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank, National Association, as administrative agent, andthe lenders party thereto (incorporated by reference to Exhibit 10.1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed onNovember 3, 2016).10.48 Fifth Amendment, dated as of November 28, 2017, to the Credit Agreement, dated as of July 8, 2014, by and among Viper EnergyPartners LP, as borrower, Viper Energy Partners LLC, as guarantor, Wells Fargo Bank National Association, as administrative agent, andthe lenders party thereto (incorporated by reference to Exhibit 10.1 of Viper’s Current Report on Form 8-K (File No. 001-36505) filed onDecember 4, 2017).10.49 Lease Amendment No. 11 effective July 31, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between FaskenMidland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed bythe Company with the SEC on November 5, 2015).783. Exhibits10.50 Lease Amendment No. 12 effective October 23, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and betweenFasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-35700,filed by the Company with the SEC on November 5, 2015).10.51 Lease Amendment No. 13 effective October 30, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and betweenFasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700,filed by the Company with the SEC on November 5, 2015).10.52 Lease Amendment No. 14 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and betweenFasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700,filed by the Company with the SEC on November 5, 2015).10.53 Lease Amendment No. 15 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and betweenFasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700,filed by the Company with the SEC on November 5, 2015).10.54 Lease Amendment No. 16 effective April 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between FaskenMidland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-35700, filed bythe Company with the SEC on November 5, 2015).10.55 Lease Amendment No. 17 effective June 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between FaskenMidland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q, File No. 001-35700, filed bythe Company with the SEC on November 5, 2015).21.1* Subsidiaries of the Registrant.23.1* Consent of Grant Thornton LLP.23.2* Consent of Ryder Scott Company, L.P. with respect to the Diamondback Energy, Inc. reserve report included as Exhibit 99.1.23.3* Consent of Ryder Scott Company, L.P. with respect to the Viper Energy Partners LP reserve report included as Exhibit 99.2.31.1* Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of1934, as amended.31.2* Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of1934, as amended.32.1** Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.32.2** Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.99.1* Report of Ryder Scott Company, L.P., dated January 18, 2018, with respect to an estimate of the proved reserves, future production andincome attributable to certain leasehold interests of Diamondback Energy, Inc. as of December 31, 2017.99.2* Report of Ryder Scott Company, L.P., dated January 18, 2018, with respect to an estimate of the proved reserves, future production andincome attributable to certain royalty interests of Viper Energy Partners LP, a subsidiary of Diamondback Energy, Inc., as of December31, 2017.101.INS* XBRL Instance Document.101.SCH* XBRL Taxonomy Extension Schema Document.101.CAL* XBRL Taxonomy Extension Calculation Linkbase.101.DEF* XBRL Taxonomy Extension Definition Linkbase Document.101.LAB* XBRL Taxonomy Extension Labels Linkbase Document.101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.79_______________*Filed herewith.**The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, asadopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 ofthe Securities Exchange Act of 1934, as amended.+Management contract, compensatory plan or arrangement.#The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copyof any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.ITEM 16. FORM 10-K SUMMARYNone80Table of ContentsSIGNATURESPursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by theundersigned thereunto duly authorized. DIAMONDBACK ENERGY, INC. Date:February 14, 2018 /s/ Travis D. Stice Travis D. Stice Chief Executive Officer (Principal Executive Officer)Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of theRegistrant and in the capacities and on the dates indicated.Signature Title Date /s/ Steven E. West Chairman of the Board and Director February 14, 2018Steven E. West /s/ Travis D. Stice Chief Executive Officer and Director February 14, 2018Travis D. Stice (Principal Executive Officer) /s/ Michael P. Cross Director February 14, 2018Michael P. Cross /s/ David L. Houston Director February 14, 2018David L. Houston /s/ Mark L. Plaumann Director February 14, 2018Mark L. Plaumann /s/ Teresa L. Dick Chief Financial Officer, Senior Vice President, and Assistant Secretary February 14, 2018Teresa L. Dick (Principal Financial and Accounting Officer) S-1Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMBoard of Directors and StockholdersDiamondback Energy, Inc.Opinion on financial statementsWe have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries(collectively the “Company”) as of December 31, 2017 and 2016, and the related consolidated statements of operations, stockholders’ equity, and cash flowsfor 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 material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of itsoperations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally acceptedin the United States of America.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), theCompany’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 14, 2018 expressedan unqualified opinion.Basis for opinionThese financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’sfinancial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to theCompany in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and thePCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performingprocedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond tothose risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits alsoincluded assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statementpresentation. We believe that our audits provide a reasonable basis for our opinion./s/ GRANT THORNTON LLPWe have served as the Company’s auditor since 2009Oklahoma City, OklahomaFebruary 14, 2018F-1Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Balance Sheets December 31, 2017 2016 (In thousands, except share amounts)Assets Current assets: Cash and cash equivalents$112,446 $1,666,574Restricted cash— 500Accounts receivable: Joint interest and other73,038 49,476Oil and natural gas sales158,575 70,349Related party— 297Inventories9,108 1,983Derivative instruments531 —Prepaid expenses and other4,903 2,987Total current assets358,601 1,792,166Property and equipment: Oil and natural gas properties, full cost method of accounting ($4,105,865 and $1,730,519 excluded fromamortization at December 31, 2017 and 2016, respectively)9,232,694 5,160,261Midstream assets191,519 8,362Other property, equipment and land80,776 58,290Accumulated depletion, depreciation, amortization and impairment(2,161,372) (1,836,056)Net property and equipment7,343,617 3,390,857Funds held in escrow6,304 121,391Derivative instruments— 709Other assets62,463 44,557Total assets$7,770,985 $5,349,680Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade$94,590 $47,648Accounts payable-related party— 1Accrued capital expenditures221,256 60,350Other accrued liabilities92,512 55,330Revenues and royalties payable68,703 23,405Derivative instruments100,367 22,608Total current liabilities577,428 209,342Long-term debt1,477,347 1,105,912Derivative instruments6,303 —Asset retirement obligations20,122 16,134Deferred income taxes108,048 —Total liabilities2,189,248 1,331,388Commitments and contingencies (Note 15) Stockholders’ equity: Common stock, $0.01 par value, 200,000,000 shares authorized, 98,167,289 issued and outstanding atDecember 31, 2017; 90,143,934 issued and outstanding at December 31, 2016982 901Additional paid-in capital5,291,011 4,215,955Accumulated deficit(37,133) (519,394)Total Diamondback Energy, Inc. stockholders’ equity5,254,860 3,697,462Non-controlling interest326,877320,830Total equity5,581,737 4,018,292Total liabilities and equity$7,770,985 $5,349,680See accompanying notes to consolidated financial statements.F-2Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statements of Operations Year Ended December 31, 2017 2016 2015 (In thousands, except per share amounts)Revenues: Oil sales$1,044,017 $470,528 $405,715Natural gas sales52,210 22,506 19,592Natural gas liquid sales90,048 34,073 21,426Lease bonus11,764 — —Midstream services7,072 — —Total revenues1,205,111 527,107 446,733Costs and expenses: Lease operating expenses126,524 82,428 82,625Production and ad valorem taxes73,505 34,456 32,990Gathering and transportation12,834 11,606 6,091Midstream services10,409 — —Depreciation, depletion and amortization326,759 178,015 217,697Impairment of oil and natural gas properties— 245,536 814,798General and administrative expenses (including non-cash equity-based compensation,net of capitalized amounts, of $25,537, $26,453 and $18,529 for the year endedDecember 31, 2017, 2016 and 2015, respectively)48,669 42,619 31,968Asset retirement obligation accretion1,391 1,064 833Total costs and expenses600,091 595,724 1,187,002Income (loss) from operations605,020 (68,617) (740,269)Other income (expense): Interest expense, net(40,554) (40,684) (41,510)Other income, net10,235 3,064 728Gain (loss) on derivative instruments, net(77,512) (25,345) 31,951Loss on extinguishment of debt— (33,134) —Total other expense, net(107,831) (96,099) (8,831)Income (loss) before income taxes497,189 (164,716) (749,100)Provision for (benefit from) income taxes(19,568) 192 (201,310)Net income (loss)516,757 (164,908) (547,790)Net income attributable to non-controlling interest34,496 126 2,838Net income (loss) attributable to Diamondback Energy, Inc.$482,261 $(165,034) $(550,628) Earnings per common share: Basic$4.95 $(2.20) $(8.74)Diluted$4.94 $(2.20) $(8.74)Weighted average common shares outstanding: Basic97,458 75,077 63,019Diluted97,688 75,077 63,019See accompanying notes to consolidated financial statements.F-3Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statement of Stockholders’ Equity Common Stock AdditionalPaid-inCapital RetainedEarnings(AccumulatedDeficit) Non-ControllingInterest SharesAmount Total (In thousands)Balance December 31, 201456,888$569 $1,554,174 $196,268 $234,202 $1,985,213Unit-based compensation — — — 3,929 3,929Distribution to non-controlling interest — — — (7,968) (7,968)Stock-based compensation — 20,645 — — 20,645Common shares issued in public offering, net of offeringcosts9,48894 649,979 — — 650,073Exercise of stock options and vesting of restricted stockunits4215 4,866 — — 4,871Net income (loss) — — (550,628) 2,838 (547,790)Balance December 31, 201566,797668 2,229,664 (354,360) 233,001 2,108,973Net proceeds from issuance of common units - ViperEnergy Partners LP — — — 93,462 93,462Unit-based compensation — — — 3,815 3,815Distribution to non-controlling interest — — — (9,574) (9,574)Stock-based compensation — 29,717 — — 29,717Common shares issued in public offering, net of offeringcosts23,0002291,956,079 — — 1,956,308Exercise of stock options and awards of restricted stock3474 495 — — 499Net income (loss) — — (165,034) 126 (164,908)Balance December 31, 201690,144901 4,215,955 (519,394) 320,830 4,018,292Net proceeds from issuance of common units - ViperEnergy Partners LP — — — 369,896 369,896Unit-based compensation — — — 2,395 2,395Common units issued for acquisition — — — 3,050 3,050Stock-based compensation — 31,783 — — 31,783Distribution to non-controlling interest — — — (41,367) (41,367)Common shares issued in public offering, net of offeringcosts —14 — — 14Common shares issued for acquisition7,68677 809,096 — — 809,173Exercise of stock options and awards of restricted stock3374 355 — — 359Change in ownership of consolidated subsidiaries, net — 233,808 — (362,423) (128,615)Net income — — 482,261 34,496 516,757Balance December 31, 201798,167$982 $5,291,011 $(37,133) $326,877 $5,581,737See accompanying notes to consolidated financial statements.F-4Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statements of Cash Flows Year Ended December 31, 2017 2016 2015 (In thousands)Cash flows from operating activities: Net income (loss)$516,757 $(164,908) $(547,790)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Provision for deferred income taxes(20,567) — (201,545)Impairment of oil and natural gas properties— 245,536 814,798Asset retirement obligation accretion1,391 1,064 833Depreciation, depletion and amortization326,759 178,015 217,697Amortization of debt issuance costs3,943 2,717 2,601Loss on early extinguishment of debt— 33,134 —Change in fair value of derivative instruments84,240 26,522 112,918Income from equity investment(657) (676) —Equity-based compensation expense25,537 26,453 18,529Gain (loss) on sale of assets, net(455) (61) 668Changes in operating assets and liabilities: Accounts receivable(97,611) (35,030) 8,998Accounts receivable-related party297 1,294 2,149Restricted cash500 — —Inventories(2,245) (255) 224Prepaid expenses and other(11,362) (709) (1,310)Accounts payable and accrued liabilities36,762 15,922 802Accounts payable and accrued liabilities-related party(2) (216) 218Income tax payable814 — —Accrued interest(20,774) (3,161) (255)Revenues and royalties payable45,298 6,439 (13,034)Net cash provided by operating activities888,625 332,080 416,501Cash flows from investing activities: Additions to oil and natural gas properties(792,599) (362,450) (419,241)Additions to oil and natural gas properties-related party— (637) (271)Additions to midstream assets(68,139) (1,188) —Purchase of other property, equipment and land(22,779) (9,891) (1,213)Acquisition of leasehold interests(1,960,591) (611,280) (437,455)Acquisition of mineral interests(407,450) (205,721) (43,907)Acquisition of midstream assets(50,279) — —Proceeds from sale of assets65,656 4,661 9,739Funds held in escrow104,087 (121,391) —Equity investments(188) (2,345) (2,702)Net cash used in investing activities(3,132,282) (1,310,242) (895,050)Cash flows from financing activities: Proceeds from borrowings under credit facility753,500 164,000 425,001Repayment under credit facility(383,500) (89,000) (603,001)Proceeds from senior notes— 1,000,000 —Repayment of senior notes— (450,000) —Premium on extinguishment of debt— (26,561) —Debt issuance costs(9,296) (15,063) (526)Public offering costs(510) (1,182) (586)F-5Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statements of Cash Flows - Continued Year Ended December 31, 2017 2016 2015 (In thousands)Proceeds from public offerings370,344 2,051,503 650,688Proceeds from exercise of stock options358 498 4,873Distributions to non-controlling interest(41,367) (9,574) (7,968)Net cash provided by financing activities689,529 2,624,621 468,481Net increase (decrease) in cash and cash equivalents(1,554,128) 1,646,459 (10,068)Cash and cash equivalents at beginning of period1,666,574 20,115 30,183Cash and cash equivalents at end of period$112,446 $1,666,574 $20,115 Supplemental disclosure of cash flow information: Interest paid, net of capitalized interest$57,668 $38,177 $38,758Cash paid for income taxes$— $192 $267Supplemental disclosure of non-cash transactions: Change in accrued capital expenditures$160,906 $413 $(69,460)Capitalized stock-based compensation$8,641 $7,079 $6,043Common stock issued for oil and natural gas properties$809,173 $— $—Asset retirement obligations acquired$2,432 $3,696 $3,159See accompanying notes to consolidated financial statements.F-6Table of ContentsDiamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATIONOrganization and Description of the BusinessDiamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and gas company focused on the acquisition, development,exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated inDelaware on December 30, 2011.On June 17, 2014, Diamondback entered into a contribution agreement with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GPLLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to the Partnership inexchange for 70,450,000 common units. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest inthe Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units, and the Company’scommon units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwrittenpublic offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of thePartnership. See Note 4–Viper Energy Partners LP for additional information regarding the Partnership.The wholly-owned subsidiaries of Diamondback, as of December 31, 2017, include Diamondback E&P LLC, a Delaware limited liability company,Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, and Rattler MidstreamLLC (formerly known as White Fang Energy LLC), a Delaware limited liability company. The consolidated subsidiaries include the wholly-ownedsubsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership, and Viper Energy Partners LLC, a Delaware limited liability company.Basis of PresentationThe consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances andtransactions have been eliminated upon consolidation.The Partnership is consolidated in the financial statements of the Company. As of December 31, 2017, the Company owned approximately 64% ofthe common units of the Partnership and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership.2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESUse of EstimatesCertain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated bymanagement, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidatedfinancial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’sdisclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Companyconsiders reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on theCompany’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts thatgive rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oiland natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, assetretirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodityderivatives and estimates of income taxes. F-7Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Cash and Cash EquivalentsThe Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cashequivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. TheCompany has not experienced any significant losses from such investments.Restricted CashIn 2014, a subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million inescrow. The subsidiary subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrowagent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matterin April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified asrestricted cash.Accounts ReceivableAccounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gasproduction delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received withinthree months after the production date.Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Companybelieves collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements torecover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. TheCompany determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’sprevious loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole.The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are creditedto the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2017 or December 31, 2016.Derivative InstrumentsThe Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with suchamounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends onthe intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposesand, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments for eachperiod in the consolidated statements of operations.Fair Value of Financial InstrumentsThe Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives and senior notes. Thecarrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fairvalue of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans withsimilar terms and maturities. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14–Fair Value Measurements).Oil and Natural Gas PropertiesThe Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration anddevelopment costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gasliquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related toexploration and development activities such as geological and other administrative costs associated with overseeing the exploration and developmentactivities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All otherinternal costs not directly associated with exploration and development activities are charged to expense as they are incurred.F-8Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or lossrecognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids andnatural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to theextent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’sinvestment in the subsidiary (see Note 7–Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units ofproduction method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rateper barrel equivalent unit of production was $11.11, $11.23 and $17.84 for the years ended December 31, 2017, 2016 and 2015, respectively. Depreciation,depletion and amortization expense for oil and natural gas properties was $321.9 million, $176.4 million and $216.1 million for the years ended December31, 2017, 2016 and 2015, respectively.Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the bookvalue of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the costcenter ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based onthe trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimatedabandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c)the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between thebook and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cashwritedown is required. During the years ended December 31, 2016 and 2015, the Company recorded impairments on proved oil and natural gas properties of$245.5 million and $814.8 million, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017.Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence ofproved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assessesproperties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors,among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves;and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulativedrilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subjectto amortization.Other Property, Equipment and LandOther property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements ordisposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any,reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, whichrange from three to fifteen years. Depreciation expense for other property and equipment was $1.4 million for each of the years ended December 31, 2017,2016 and 2015.Asset Retirement ObligationsThe Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associatedwith the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations representthe future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period inwhich it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the relatedlong-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset.If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil andnatural gas properties.F-9Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Impairment of Long-Lived AssetsOther property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset maynot be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated futureundiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairmentlosses for the years ended December 31, 2017, 2016 and 2015, respectively.Capitalized InterestThe Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to currentamortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannotexceed gross interest expense. The Company capitalized interest of $22.1 million for the year ended December 31, 2017. The Company did not have anycapitalized interest for the years ended December 31, 2016 and 2015.InventoriesInventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2017 and 2016. The Company’stubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventoryis primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation,represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which theCompany is a party. As of December 31, 2017, the Company estimated that all of its tubular goods and equipment will be utilized within one year.Debt Issuance CostsOther assets included capitalized costs related to the credit facility of $16.7 million and $8.2 million, net of accumulated amortization of $7.0million and $4.9 million, as of December 31, 2017 and 2016, respectively. Long-term debt included capitalized costs related to the senior notes of $15.2million and $14.8 million, net of accumulated amortization of $2.0 million and $0.2 million, as of December 31, 2017 and 2016, respectively. The costsassociated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using theeffective interest method. The costs associated with the Company’s credit facility that are included in other assets are being amortized over the term of thefacility.Other Accrued LiabilitiesOther accrued liabilities consist of the following: December 31, 2017 2016 (In thousands)Liability for drilling costs prepaid by joint interest partners$30,320 $21,595Interest payable6,770 5,445Lease operating expenses payable27,850 13,857Ad valorem taxes payable3,306 776Current portion of asset retirement obligations1,163 1,288Other23,103 12,369Total other accrued liabilities$92,512 $55,330Revenue and Royalties PayableFor certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser andfurther distributes such amounts to other revenue and royalty owners. Production proceeds thatF-10Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidatedbalance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.Revenue RecognitionOil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. TheCompany accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtakevolumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than itsownership share of production. The Company did not have any gas imbalances as of December 31, 2017 or December 31, 2016. Revenues from oil andnatural gas services are recognized when services are provided.InvestmentsEquity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under theequity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews itsinvestments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize animpairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2017, 2016 and 2015.For additional information on the Company’s investments, see Note 7–Equity Method Investments.Accounting for Equity-Based CompensationThe Company grants various types of stock-based awards including stock options and restricted stock units. The Partnership grants various unit-based awards including unit options and phantom units to employees, officers and directors of the General Partner and the Company who perform services forthe Partnership. These plans and related accounting policies are defined and described more fully in Note 10–Equity-Based Compensation. Equitycompensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.ConcentrationsThe Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significantpurchasers. For the year ended December 31, 2017, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US)Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers eachaccounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude OilLLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US)Company (59%); and Enterprise Crude Oil LLC (15%). The Company does not require collateral and does not believe the loss of any single purchaser wouldmaterially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.Environmental Compliance and RemediationEnvironmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accruedwhen environmental assessments and remediation are probable, and the costs can be reasonably estimated.Income TaxesDiamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized forthe future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilitiesand (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future periodwhen those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognizedinF-11Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred taxassets will not be realized.The Company is subject to margin tax in the state of Texas. During the years ended December 31, 2017, 2016 and 2015, the Company had nomargin tax expense. The Company’s 2013, 2014, 2015, 2016 and 2017 federal income tax and state margin tax returns remain open to examination by taxauthorities. As of December 31, 2017 and December 31, 2016, the Company had no unrecognized tax benefits that would have a material impact on theeffective tax rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and generaland administrative expenses, respectively. During the years ended December 31, 2017, 2016 and 2015, there was no interest or penalties associated withuncertain tax positions recognized in the Company’s consolidated financial statements.Recent Accounting PronouncementsRecently Issued PronouncementsIn May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”.This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transferspromised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goodsor services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers.The Company will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company hasreviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results ofoperations or liquidity. Upon adoption of this Accounting Standards Update, the Company will not be required to record a cumulative effect adjustment dueto the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting StandardsUpdate, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes inorder to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under theAccounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP.In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. Thisupdate applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted forunder the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income.The Partnership will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity andwill bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment.In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classificationof Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update providesguidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debtinstruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration paymentsmade after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurancepolicies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitizationtransactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1,2018 using the retrospective transition method. Adoption of this standard will change the presentation of its cash flows and did not have a material impact onits consolidated financial statements.In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - RestrictedCash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company will adopt this update retrospectively effectiveJanuary 1, 2018. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financialstatements.In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying theDefinition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen todetermine when a set is not a business. The screen requires thatF-12Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similaridentifiable assets, the set is not a business. The Company will adopt this update prospectively effective January 1, 2018. The adoption of this update will nothave an impact on its financial position, results of operations or liquidity.Accounting Pronouncements Not Yet AdoptedIn February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to anyentity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position aliability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While therewere no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effectivefor public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. TheCompany believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operatingleases. The Company is still evaluating the impact of this standard.In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”.This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendmentsaffect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financialassets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal yearsbeginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustmentto retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of thisstandard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.3. ACQUISITIONS2017 ActivityOn February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets inthe Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of the Company’s common stock, of whichapproximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. The Companyused the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sourcesto fund the cash portion of the purchase price for this acquisition.The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5billion, resulting in no goodwill or bargain purchase gain. (in thousands)Proved oil and natural gas properties$386,308Unevaluated oil and natural gas properties2,122,597Midstream assets47,432Prepaid capital costs3,460Oil inventory839Equipment163Revenues and royalties payable(9,650)Asset retirement obligations(1,550)Total fair value of net assets$2,549,599The Company has included in its consolidated statements of operations revenues of $81.4 million and direct operating expenses of $23.5 million forthe period from February 28, 2017 to December 31, 2017 due to the acquisition.F-13Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Pro Forma Financial InformationThe following unaudited summary pro forma consolidated statement of operations data of Diamondback for the year ended December 31, 2017 and2016 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarilyindicative of the financial results that would have been attained had the acquisitions occurred on January 1, 2016.The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewedas indicative of operations in future periods. Year Ended December 31, 2017 2016 (in thousands, except per shareamounts)Revenues$1,228,040 $627,301Income (loss) from operations619,369 (12,812)Net income (loss)472,649 (109,229)Basic earnings per common share4.85 (1.45)Diluted earnings per common share4.84 (1.45)2016 ActivityOn September 1, 2016, the Company acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin foran aggregate purchase price of $558.5 million. This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Wardcounties. The Company financed this acquisition with net proceeds from the July 2016 equity offering discussed in Note 9 and cash on hand.2015 ActivityDuring 2015, the Company completed acquisitions from unrelated third party sellers of an aggregate of approximately 16,940 gross (12,672 net)acres in the Midland Basin, primarily in northwest Howard County, for an aggregate purchase price of approximately $437.5 million. The acquisitions wereaccounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. Theseacquisitions were funded with the net proceeds of the May 2015 equity offering discussed in Note 9–Capital Stock and Earnings Per Share and borrowingsunder the Company’s revolving credit facility discussed in Note 8–Debt.On July 9, 2015, the Company completed the sale of an approximate average 1.5% overriding royalty interest in certain of its acreage primarilylocated in Howard County, Texas to the Partnership for $31.1 million. The Partnership primarily funded this acquisition with borrowings under its revolvingcredit facility discussed in Note 8 – Debt.4. VIPER ENERGY PARTNERS LPThe Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Market under thesymbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gasproperties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin. Viper Energy Partners GP LLC, aconsolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As ofDecember 31, 2017, the Company owned approximately 64% of the common units of the Partnership.Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in thePartnership. The Viper Offering consisted of 5,750,000 common units representing approximately 8% of the limited partner interests in the Partnership at aprice to the public of $26.00 per common unit. In connection with the Viper Offering, Diamondback contributed all of the membership interests in ViperEnergy Partners LLC to the Partnership in exchange for 70,450,000 common units. The contribution of Viper Energy Partners LLC to the Partnership wasaccounted for as aF-14Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests.During the year ended December 31, 2017, the Partnership distributed $89.5 million to Diamondback in respect of its common units.In August 2016, the Partnership completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common unitsissued pursuant to an option to purchase additional common units granted to the underwriter. In this offering, Diamondback purchased 2,000,000 commonunits from the underwriter at $15.60 per unit, which is the price per common unit paid by the underwriter to the Partnership. Following the August 2016public offering, Diamondback had an approximate 83% limited partner interest in the Partnership. The Partnership received net proceeds from this offering ofapproximately $125.0 million, after deducting underwriting discounts and commissions and estimated offering expenses, which it used to fund anacquisition and repaid outstanding borrowings under its revolving credit facility.In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common unitsissued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering ofapproximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used$120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, whichincluded additional acquisitions.In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common unitsissued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, anaffiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of the Company and the General Partner purchased anaggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, the Company had an approximate 64% limitedpartner interest in the Partnership. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwritingdiscounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowingsunder the Partnership’s revolving credit facility and the balance was used fund a portion of the purchase price for acquisitions and for general partnershippurposes.As a result of these public offerings and the Partnership’s issuance of unit-based compensation, the Company’s ownership percentage in thePartnership was reduced. During the year ended December 31, 2017, the Company recorded a $362.4 million decrease to Non-controlling interest in thePartnership with an increase to Additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value inthe Partnership before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet.Partnership AgreementIn connection with the closing of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement oflimited partnership, dated as of June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the GeneralPartner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwiseincurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount ofexpenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amountspaid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner isentitled to determine the expenses that are allocable to the Partnership.Tax SharingIn connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014,pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s resultsare included in a consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of anysuch reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondbackmay use its tax attributes to cause its consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation,the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed hadF-15Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period.Other AgreementsSee Note 11–Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner enteredinto with Wexford Capital LP (“Wexford”).The Partnership has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrativeagent sole book runner and lead arranger. See Note 8–Debt for a description of this credit facility.5. PROPERTY AND EQUIPMENTProperty and equipment includes the following: December 31, 2017 2016 (in thousands)Oil and natural gas properties: Subject to depletion$5,126,829 $3,429,742Not subject to depletion4,105,865 1,730,519Gross oil and natural gas properties9,232,694 5,160,261Accumulated depletion(1,009,893) (687,685)Accumulated impairment(1,143,498) (1,143,498)Oil and natural gas properties, net7,079,303 3,329,078Midstream assets191,519 8,362Other property, equipment and land80,776 58,290Accumulated depreciation(7,981) (4,873)Property and equipment, net of accumulated depreciation, depletion, amortization and impairment$7,343,617 $3,390,857 Balance of costs not subject to depletion: Incurred in 2017$2,746,936 Incurred in 2016727,411 Incurred in 2015301,879 Incurred in 2014316,455 Incurred in 201313,184 Total not subject to depletion$4,105,865 The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration anddevelopment costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gasliquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related toexploration and development activities such as geological and other administrative costs associated with overseeing the exploration and developmentactivities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All otherinternal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs wereapproximately $22.0 million $17.2 million and $15.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. Costs associated withunevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusionof the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Acquisition costs not currently beingamortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreageexpire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for asF-16Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costsand proved reserves of oil, natural gas liquids and natural gas.Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the bookvalue of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the costcenter ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based onthe trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimatedabandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c)the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between thebook and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cashwritedown is required.As a result of the significant decline in prices during 2016, the Company recorded non-cash ceiling test impairments for the years endedDecember 31, 2016 and 2015 of $245.5 million and $814.8 million, respectively, which are included in accumulated depletion. No impairment on proved oiland natural gas properties was recorded for the year ended December 31, 2017. For 2016 and 2015, the impairment charges affected the Company’s reportednet income but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future developmentcosts, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods.At December 31, 2017, there was $26.0 million in exploration costs and development costs and $22.1 million in capitalized interest that are notsubject to depletion. At December 31, 2016, there were no exploration costs, development costs or capitalized interest that are not subject to depletion.6. ASSET RETIREMENT OBLIGATIONSThe following table describes the changes to the Company’s asset retirement obligations liability for the following periods: Year Ended December 31, 2017 2016 2015 (in thousands)Asset retirement obligations, beginning of period$17,422 $12,711 $8,486Additional liabilities incurred1,526 637 594Liabilities acquired2,432 3,696 3,159Liabilities settled(1,555) (711) (292)Accretion expense1,391 1,064 833Revisions in estimated liabilities69 25 (69)Asset retirement obligations, end of period21,285 17,422 12,711Less current portion1,163 1,288 193Asset retirement obligations - long-term$20,122 $16,134 $12,518The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Companyestimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflationfactor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of theexisting asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.7. EQUITY METHOD INVESTMENTSIn October 2014, the Company obtained a 25% interest in HMW Fluid Management LLC, which was formed to develop, own and operate anintegrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating inMidland, Martin and Andrews Counties, Texas. The board of this entity may also authorize the entity to offer these services to other counties in the PermianBasin and to pursue other business opportunities.F-17Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)During the year ended December 31, 2017, the Company invested $0.2 million in this entity and recorded income of $0.7 million, which was the Company’sshare of HMW Fluid Management LLC’s net income, bringing the Company’s total investment to $7.2 million at December 31, 2017. During the year endedDecember 31, 2016, the Company invested $2.3 million in this entity and recorded income of $0.7 million, which was the Company’s share of HMW FluidManagement LLC’s net income, bringing its total investment to $6.3 million at December 31, 2016. The Company will retain a minority interest after allcommitments are received. The entity was formed as a limited liability company and maintains a specific ownership account for each investor, similar to apartnership capital account structure. The Company accounts for this investment under the equity method of accounting.8. DEBTLong-term debt consisted of the following as of the dates indicated: December 31, 2017 2016 (in thousands)4.750 % Senior Notes due 2024500,000 500,0005.375 % Senior Notes due 2025500,000 500,000Unamortized debt issuance costs(13,153) (14,588)Revolving credit facility397,000 —Partnership revolving credit facility93,500 120,500Total long-term debt$1,477,347 $1,105,9122024 Senior NotesOn October 28, 2016, the Company issued $500.0 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “2024 Senior Notes”).The 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing onMay 1, 2017 and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving creditfacility or certain other debt guarantee the 2024 Senior Notes, provided, however, that the 2024 Senior Notes are not guaranteed by the Partnership, theGeneral Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.See also “Note 16. Subsequent Events–New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility.”The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and WellsFargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 Indenture contains certain covenants that, subject to certain exceptions andqualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness,make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets includingcapital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwisedispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas businessand designate certain of the Company’s subsidiaries as unrestricted subsidiaries.The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at theredemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning onNovember 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019,the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes at a price equal to 100% of the principal amount of the2024 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019,the Company may on any one or more occasions redeem the 2024 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregateprincipal amount of the 2024 Senior Notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemptiondate, with an amount equal to the net cash proceeds from certain equity offerings.F-18Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)2025 Senior NotesOn December 20, 2016, the Company issued $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “2025 SeniorNotes”). The 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year,commencing on May 31, 2017 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolvingcredit facility or certain other debt guarantee the 2025 Senior Notes, provided, however, that the 2025 Senior Notes are not guaranteed by the Partnership, theGeneral Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.The 2025 Senior Notes were issued under an indenture, dated as of December 20, 2016, among the Company, the guarantors party thereto and WellsFargo Bank, as the trustee (the “2025 Indenture”). The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications,among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certaininvestments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock ofrestricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all orsubstantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designatecertain of the Company’s subsidiaries as unrestricted subsidiaries.The Company may on any one or more occasions redeem some or all of the 2025 Senior Notes at any time on or after May 31, 2020 at the redemptionprices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month periodbeginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any timethereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or moreoccasions redeem all or a portion of the 2025 Senior Notes at a price equal to 100% of the principal amount of the 2025 Senior Notes plus a “make-whole”premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or moreoccasions redeem the 2025 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notesissued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cashproceeds from certain equity offerings.As required under the terms of the registration rights agreements relating to the 2024 Senior Notes and the 2025 Senior Notes, on April 26, 2017, theCompany filed with the SEC a Registration Statement on Form S-4 (the “Registration Statement”) relating to the exchange offers of the 2024 Senior Notesand the 2025 Senior Notes for substantially identical notes registered under the Securities Act (the “Exchange Offers”). The Registration Statement wasdeclared effective by the SEC on June 21, 2017 and the Exchange Offers closed on July 27, 2017, in which all of the privately placed 2024 Senior Notes and2025 Senior Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act.The Company’s Credit FacilityThe Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013,as amended on June 9, 2014, November 13, 2014, June 21, 2016, December 15, 2016 and November 28, 2017, with a syndicate of banks, including WellsFargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for arevolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on the Company’s oil and natural gas reserves andother factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date ofMay 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company may request up to twoadditional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $1.8 billion, theCompany had elected a commitment amount of $1.0 billion and the Company had $397.0 million of outstanding borrowings under the revolving creditfacility. See “Note 16. Subsequent Events-New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving CreditFacility.”F-19Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Diamondback O&G LLC is the borrower under the credit agreement. As of December 31, 2017, the credit agreement is guaranteed by the Company,Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of the Company’sfuture subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of theassets of the Company, Diamondback O&G LLC and the guarantors.The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate baserate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plusthe applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case ofLIBOR, each of which applicable margin rates is increased by 0.25% per annum if the total debt to EBITDAX ratio is greater than 3.0 to 1.0. The applicablemargin depends on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum creditamount, the borrowing base and the elected commitment amount. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation tothe commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and isrequired to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination orotherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiencyor event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022.The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limitadditional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and enteringinto certain swap agreements and require the maintenance of the financial ratios described below.Financial CovenantRequired RatioRatio of total debt to EBITDAXNot greater than 3.0 to 1.0Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior orsenior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance,the borrowing base is reduced by 25% of the stated principal amount of each such issuance.As of December 31, 2017 and 2016, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect.The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of anyevent of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrectrepresentations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breachesof negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.The Partnership’s Credit AgreementOn July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells FargoSecurities, as sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of$2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million, subject to scheduledsemi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates ofMay 1st and November 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As ofDecember 31, 2017, the borrowing base was set at $400.0 million, and the Partnership had $93.5 million of outstanding borrowings and $306.5 millionavailable for future borrowings under its revolving credit facility.The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Partnership that is equal to an alternate baserate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plusthe applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% perannum in the case of LIBOR, in each caseF-20Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum creditamount and the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unusedportion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loanprincipal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) tothe extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some casessubject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default existsunder the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the Partnership and its subsidiary’sassets.The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limitadditional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactionswith affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.Financial CovenantRequired RatioRatio of total debt to EBITDAXNot greater than 4.0 to 1.0Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecurednotes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. Aborrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of anyevent of default. The Partnership’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrectrepresentations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breachesof negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.Interest expenseThe following amounts have been incurred and charged to interest expense for the years ended December 31, 2017, 2016 and 2015: Year Ended December 31, 2017 2016 2015 (in thousands)Interest expense$60,671 $39,642 $40,221Less capitalized interest(22,097) — —Other fees and expenses2,160 1,426 1,292Total interest expense$40,734 $41,068 $41,513F-21Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)9. CAPITAL STOCK AND EARNINGS PER SHAREDiamondback completed the following equity offerings during the years ended December 31, 2017, 2016 and 2015:DateNumber of Shares ofCommon Stock SoldNumber of Shares ofCommon Stock Issued toUnderwritersPrice per Share Sold toUnderwritersProceeds Received bythe CompanyJanuary 20152,012,500262,500$59.34$119,422May 20154,600,000600,000$72.53$333,638August 20152,875,000375,000$68.74$197,628January 20164,600,000600,000$55.33$254,518July 20166,325,000825,000$87.24$551,777December 201612,075,0001,575,000$95.3025$1,150,828Earnings Per ShareThe Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stockoutstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the dilutedearnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on theconsolidated group’s holdings of the subsidiary.A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Year Ended December 31, 2017 2016 2015 Net income (loss) attributable to common stock$482,261 $(165,034) $(550,628)Weighted average common shares outstanding Basic weighted average common units outstanding97,458 75,077 63,019Effect of dilutive securities: Potential common shares issuable230 — —Diluted weighted average common shares outstanding97,688 75,077 63,019Basic net income (loss) attributable to common stock$4.95 $(2.20) $(8.74)Diluted net income (loss) attributable to common stock$4.94 $(2.20) $(8.74)For the years ended December 31, 2017, 2016 and 2015, there were 45,690 shares, 243,654 shares and 100,924 shares, respectively, that were notincluded in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but couldpotentially dilute basic earnings per share in future periods.10. EQUITY-BASED COMPENSATIONOn October 10, 2012, the Board of Directors approved the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “2012 Plan”), which isintended to provide eligible employees with equity-based incentives. The 2012 Plan provides for the granting of incentive stock options, nonstatutory stockoptions, restricted awards (restricted stock and restricted stock units), performance awards, and stock appreciation rights, or any combination of the foregoing.A total of 2,500,000 shares of the Company’s common stock has been reserved for issuance pursuant to this plan.F-22Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table presents the effects of the equity and stock based compensation plans and related costs: 2017 2016 2015 (In thousands)General and administrative expenses$25,537 $26,453 $18,529Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gasproperties8,641 7,079 6,043On June 17, 2014, in connection with the Viper Offering, the Board of Directors of the General Partner adopted the Viper Energy Partners LP LongTerm Incentive Plan (“Viper LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates,including Diamondback, who perform services for the Partnership. The Viper LTIP provides for the grant of unit options, unit appreciation rights, restrictedunits, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of9,070,356 common units has been reserved for issuance pursuant to the Viper LTIP. Common units that are cancelled, forfeited or withheld to satisfy exerciseprices or tax withholding obligations will be available for delivery pursuant to other awards. The Viper LTIP is administered by the Board of Directors of theGeneral Partner or a committee thereof.Stock OptionsIn accordance with the 2012 Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant.The shares issued under the 2012 Plan will consist of new shares of Company stock. Unless otherwise specified in an agreement, options become exercisableratably over a five-year period. However, as described above, options associated with the modification vest in four substantially equal annual installmentsand are exercisable for five years from the date of grant.The fair value of the stock options on the date of grant is expensed over the applicable vesting period. The Company estimates the fair values ofstock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not havea long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term ofoptions granted was determined based on the contractual term of the awards and remaining vesting term at the modification date. The risk-free interest rate isbased on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. The Company does not anticipate paying cash dividends;therefore, the expected dividend yield was assumed to be zero. All such amounts represent the weighted-average amounts for each year.The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the yearended December 31, 2017. Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in thousands)Outstanding at December 31, 201615,750 $22.72 Exercised(15,750) $22.72 Outstanding at December 31, 2017— $— 0.00 $—The aggregate intrinsic value of stock options that were exercised during the years ended December 31, 2016 and 2015 was $1.3 million and $15.7million, respectively.Restricted Stock UnitsUnder the 2012 Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to eligibleemployees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant dateof the award, which is expensed over the applicable vesting period.F-23Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table presents the Company’s restricted stock units activity under the 2012 Plan during the year ended December 31, 2017. Restricted StockAwards & Units Weighted Average Grant-DateFair ValueUnvested at December 31, 2016206,004 $70.33Granted188,438 $102.77Vested(147,934) $77.44Forfeited(2,931) $89.21Unvested at December 31, 2017243,577 $90.88The aggregate fair value of restricted stock units that vested during the year ended December 31, 2017, 2016 and 2015 was $14.8 million, $12.5million and $10.1 million, respectively. As of December 31, 2017, the Company’s unrecognized compensation cost related to unvested restricted stockawards and units was $14.4 million. Such cost is expected to be recognized over a weighted-average period of 1.5 years.Performance-Based Restricted Stock UnitsTo provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has grantedperformance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is basedupon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-yearperformance period.In February 2015, eligible employees received performance restricted stock unit awards totaling 90,249 units from which a minimum of 0% and amaximum of 200% units could be awarded. The awards have a performance period of January 1, 2014 to December 31, 2016 and vested at December 31,2016.In February 2016, eligible employees received performance restricted stock unit awards totaling 174,325 units from which a minimum of 0% and amaximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2017 and vested at December 31,2017. Eligible employees received additional performance restricted stock unit awards totaling 87,163 units from which a minimum of 0% and a maximum of200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2018 and cliff vest at December 31, 2018.In February 2017, eligible employees received performance restricted stock unit awards totaling 37,440 units from which a minimum of 0% and amaximum of 200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2018 and cliff vest at December 31,2018. Eligible employees received additional performance restricted stock unit awards totaling 74,880 units from which a minimum of 0% and a maximum of200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2019 and cliff vest at December 31, 2019.The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expectedpercentage of units to be earned during the performance period. The following table presents a summary of the grant-date fair values of performance restrictedstock units granted and the related assumptions. 2017 2016 Two-YearPerformancePeriod Three-YearPerformancePeriod Two-YearPerformancePeriod Three-YearPerformancePeriod 2015Grant-date fair value$162.13 $168.73 $103.41 $102.35 $137.14Risk-free rate1.27% 1.59% 0.86% 1.10% 0.49%Company volatility39.32% 41.14% 41.91% 42.16% 43.36%F-24Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table presents the Company’s performance restricted stock unit activity under the 2012 Plan for the year ended December 31, 2017. PerformanceRestricted Stock Units Weighted AverageGrant-Date Fair ValueUnvested at December 31, 2016252,471 $103.06Granted118,169 $166.53Vested(168,314) $103.41Unvested at December 31, 2017(1)202,326 $139.83(1)A maximum of 404,652 units could be awarded based upon the Company’s final TSR ranking.As of December 31, 2017, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and unitswas $15.6 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.Partnership Unit OptionsIn accordance with the Viper LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the dateof grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the GeneralPartner granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the firstthree anniversaries of the date of grant or earlier upon a change of control (as defined in the Viper LTIP). All outstanding unit options were amended effectiveNovember 29, 2016 to provide that vested unit options will become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning onthe third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before andending on the date a change of control occurs (the earlier occurring of such events, the “Exercise Period”). At any time within the Exercise Period, if aparticipant attempts to exercise a vested unit option and the fair market value per unit as of such date is less than the exercise price per option unit, the vestedunit option will not be exercisable. At the end of the Exercise Period, any vested unit option that is not exercisable or that has not been exercised willautomatically terminate and become null and void.The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unitoptions granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant thePartnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies.The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yieldcurve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership. 2015Grant-date fair value$4.24Expected volatility36.0%Expected dividend yield5.9%Expected term (in years)3.0Risk-free rate0.99%F-25Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2017. Weighted Average Unit Options Exercise Price RemainingTerm Intrinsic Value (in years) (in thousands)Outstanding at December 31, 20162,424,266 $26.00 Forfeited(2,416,666) $26.00 Outstanding at December 31, 20177,600 $18.49 0.00 $— Vested and Expected to vest at December 31, 20177,600 $18.49 0.00 $—Phantom UnitsUnder the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnershipestimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over theapplicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of the Partnership for each phantom unit.The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2017. Phantom Units Weighted AverageGrant-DateFair ValueUnvested at December 31, 201621,048 $16.23Granted116,567 $17.09Vested(32,176) $16.49Unvested at December 31, 2017105,439 $17.10The aggregate fair value of phantom units that vested during the year ended December 31, 2017 was $0.5 million. As of December 31, 2017, theunrecognized compensation cost related to unvested phantom units was $1.3 million. Such cost is expected to be recognized over a weighted-average periodof 1.4 years.11. RELATED PARTY TRANSACTIONSImmediately upon the completion of the Company’s initial public offering on October 17, 2012, Wexford beneficially owned approximately 44% ofthe Company’s outstanding common stock. As of December 31, 2016, Wexford beneficially owned less than 1% of the Company’s outstanding commonstock. The Chairman of the Board of Directors of both the Company and the General Partner was a partner at Wexford until his retirement from Wexfordeffective December 31, 2016. Another partner at Wexford serves as a member of the Board of Directors of the General Partner. Beginning January 1, 2017,Wexford and entities affiliated with Wexford are no longer considered related parties of the Company and any expenses after December 31, 2016 are nolonger classified as related party expenses.Related Party Revenue and ExpensesDuring the year ended December 31, 2016, the Company paid $3.3 million in lease operating expenses and $2.2 million in general andadministrative expenses to related parties. During the year ended December 31, 2016, the Company received $0.2 million in other income from relatedparties. During the year ended December 31, 2015, the Company paid $0.2 million in lease operating expenses, $0.2 million in production and ad valoremtaxes, $1.0 million in gathering and transportation expenses and $2.3 million in general and administrative expenses to related parties. During the year endedDecember 31, 2015, the Company received $0.2 million in other income from related parties.Advisory Services Agreement - The CompanyThe Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, underwhich Wexford provides the Company with general financial and strategic advisory servicesF-26Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement had an initialterm of two years commencing on October 18, 2012, and continues for additional one-year periods unless terminated in writing by either party at least tendays prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event theCompany terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’srequest in connection with acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided byWexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnifyWexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting fromWexford’s or its affiliates’ gross negligence or willful misconduct. The Company paid $0.5 million during both of the years ended December 31, 2016 and2015 under the Advisory Services Agreement.Advisory Services Agreement - The PartnershipIn connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “ViperAdvisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with generalfinancial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The ViperAdvisory Services Agreement had an initial term of two years commencing on June 23, 2014, and will continue for additional one-year periods unlessterminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30days prior written notice. In the event the Partnership or the General Partner terminates such agreement, the Partnership is obligated to pay all amounts duethrough the remaining term. In addition, the Partnership and the General Partner have agreed to pay Wexford to-be-negotiated market-based fees approved bythe conflict committee of the board of directors of the General Partner for such services as may be provided by Wexford at the Partnership’s or the GeneralPartner’s request in connection with acquisitions and divestitures, financings or other transactions in which the Partnership may be involved. The servicesprovided by Wexford under the Viper Advisory Services Agreement do not extend to the Partnership or the General Partner’s day-to-day business oroperations. The Partnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connectionwith the Viper Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. ThePartnership did not pay any amounts during the years ended December 31, 2017 and 2016 under the Viper Advisory Services Agreement. The Partnershippaid $0.5 million during the year ended December 31, 2015 under the Viper Advisory Services Agreement.Coronado MidstreamThe Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC, formerly known as MidMarGas LLC, an entity that was affiliated with Wexford, that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement,Coronado Midstream LLC is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream LLC, all of the gasconforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. An entity controlled by Wexford had ownedapproximately 28% equity interest in Coronado Midstream LLC until Coronado Midstream LLC was sold in March 2015. Coronado Midstream LLC is nolonger a related party and any revenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified asthose attributable to a related party.Midland LeasesEffective May 15, 2011, the Company occupied corporate office space in the Fasken building in Midland, Texas under a lease with an initial term offive years. On November 10, 2014, the lease was amended to extend the term of the lease for an additional 10-year period and to increase the monthly baserent to $94,000 beginning in June 2016, with an increase of approximately 2% annually. The office space is owned by Fasken, which is an entity controlledby an affiliate of Wexford.F-27Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table contains amendments made to lease additional office space in the Midland corporate office during the years endedDecember 31, 2016 and 2015:Date of AmendmentsRent for Additional SpaceApprox. Annual Increaseof Monthly Base Rent2nd quarter 2014$27,000N/A4th quarter 2014$53,0004%April 2015$23,000N/AJune 2015$22,0002%Field Office LeaseThe Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011. On March 1, 2014, the building waspurchased by WT Commercial Portfolio, LLC, which is controlled by an affiliate of Wexford. The term of the lease expires on February 28, 2018. Themonthly base rent was $11,000 and increased 3% annually on March 1 of each year. During the third quarter of 2014, the Company entered into a subleasewith Bison, in which Bison leased the field office space on the same terms as the Company’s lease for the remainder of the lease term. The Company paid rentof $0.2 million during both of the years ended December 31, 2016 and 2015. The Company received payments of $0.2 million from Bison in respect of thissublease during both of the years ended December 31, 2016 and 2015. During the second quarter of 2017, the sublease between the Company and Bison aswell as the original lease between the Company and WT Commercial Portfolio, LLC were terminated.The Partnership - Lease BonusDuring the year ended December 31, 2017, the Company paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases,reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, the Company paid the Partnership $0.3 million in lease bonuspayments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.12. INCOME TAXESDeferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reportingpurposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax.For certain reporting periods prior to the quarter ended December 31, 2017, the Company’s deferred tax assets exceeded its deferred tax liabilities.The resulting net deferred tax asset was subject to a full valuation allowance. The Company continually assesses its deferred tax assets for realizability and, asa result of such reassessment, in the quarter ended December 31, 2017 the Company determined that sufficient evidence existed to indicate that it is probablethat its deferred tax assets will be realized primarily through the unfavorable reversal of deferred tax liabilities, which currently exceed the Company’sdeferred tax assets. In the quarter ended December 31, 2017, the valuation allowance historically applied against the Company’s gross deferred tax assets wasremoved. The Company’s gross deferred tax assets were recorded based upon the 35% federal income tax rate that was in effect prior to the enactment of theTax Cut and Jobs Act. Subsequently, but also in the quarter ended December 31, 2017, the Company’s deferred tax assets and deferred tax liabilities wererevalued to reflect the federal income tax rate enacted by the Tax Cut and Jobs Act. The effects of the removal of the valuation allowance and the reduction tothe federal income tax rate may both be seen in the reconciliation of our effective tax rate to the statutory rate below.The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. Among other significantfeatures, the Tax Cut and Jobs Act reduces the maximum US federal corporate income tax rate from 35% to 21%, preserves long-standing upstream oil andgas tax provisions such as immediate deduction of intangible drilling costs, allows for immediate expensing of capital expenditures for tangible personalproperty for a period of time, modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations,and enacts new limitations regarding the deductibility of interest expense.As of the completion of the Company’s financial statements for its year ended December 31, 2017, the Company has substantially completed itsaccounting for the effects of the enactment of the Tax Cut and Jobs Act. With respect to those itemsF-28Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)for which the Company’s accounting is not complete, as described below, the Company has made reasonable estimates of the effects on its existing deferredtax balances. In all cases, the Company will continue to make and refine its calculations as additional analysis is completed.To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal incomeand state income tax rates at which they are now expected to reverse, which is generally a federal income tax rate of 21%. The enacted rate change resulted ina non-cash decrease of approximately $67.9 million to the Company’s income tax provision for the period ended December 31, 2017 and a correspondingreduction to the Company’s net noncurrent deferred tax liability balance as of December 31, 2017.The Company is still analyzing certain aspects of the Tax Cuts and Jobs Act, specifically the provisions related to limitations on the deductibility ofcertain executive compensation, including equity based compensation. The Company is refining its calculations, which could potentially affect themeasurement of related deferred tax balances or potentially give rise to new deferred tax amounts. The Company does not expect that a material adjustmentto its deferred tax position will result from the completion of its computations, which the Company expects to finalize by the fourth quarter of 2018.At December 31, 2017, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The taxyears 2014 through 2017 remain subject to examination by the major tax jurisdictions.The components of the provision for income taxes for the years ended December 31, 2017, 2016 and 2015 are as follows: Year Ended December 31, 2017 2016 2015 (In thousands)Current income tax provision (benefit): Federal$— $— $(33)State999 192 268Total current income tax provision999 192 235Deferred income tax provision (benefit): Federal(21,720) (579) (198,729)State1,153 579 (2,816)Total deferred income tax provision (benefit)(20,567) — (201,545)Total provision for (benefit from) income taxes$(19,568) $192 $(201,310) A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2017 2016 2015 (In thousands)Income tax expense (benefit) at the federal statutory rate (35%)$174,016 $(57,694) $(263,179)Impact of nontaxable noncontrolling interest(12,073) — —Income tax benefit relating to change in statutory tax rate(67,938) — (1,145)State income tax expense (benefit), net of federal tax effect3,413 770 (2,548)Non-deductible compensation13,492 3,990 1,354Change in valuation allowance(127,485) 53,336 61,056Other, net(2,993) (210) 3,152Provision for (benefit from) income taxes$(19,568) $192 $(201,310)F-29Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 are as follows: December 31, 2017 2016 (In thousands)Current: Deferred tax assets Derivative instruments$— $7,771Other— 3,518Current deferred tax assets— 11,289Valuation allowance— (11,289)Current deferred tax assets, net of valuation allowance— —Deferred tax liabilities Derivative instruments— —Total current deferred tax liabilities— —Net current deferred tax assets— —Noncurrent: Deferred tax assets Net operating loss carryforwards (subject to 20 year expiration)74,997 139,065Derivative instruments22,918 —Stock based compensation942 6,234Other2,464 —Noncurrent deferred tax assets101,321 145,299Valuation allowance(104) (103,112)Noncurrent deferred tax assets, net of valuation allowance101,217 42,187Deferred tax liabilities Oil and natural gas properties and equipment202,997 42,187Midstream assets6,268 —Total noncurrent deferred tax liabilities209,265 42,187Net noncurrent deferred tax liabilities108,048 —Net deferred tax liabilities$108,048 $—The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling anddevelopment costs under current law. There is no tax refund available to the Company, nor is there any current income tax payable. At December 31, 2017,the Company had approximately $357.0 million of federal NOLs expiring in 2032 through 2037. The Company principally operates in the state of Texas andis subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company believes that Section 382 of the InternalRevenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-yearlook back period, will not have an adverse effect on future NOL usage.As of December 31, 2017, the Company has a remaining valuation allowance of $0.1 million for certain state NOL carryforwards which theCompany does not believe are realizable as it does not anticipate future operations in those states. In the fourth quarter of 2017, the Company removed itsvaluation allowance against deferred tax assets for U.S. NOL carryforwards resulting in income tax benefit of $127.5 million. As discussed above,management’s assessment included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred taxliabilities. Management believes that the balance of the Company’s NOLs are realizable to the extent of future taxable income primarily related to the excessof book carrying value of properties over their respective tax bases. As a result of management’s assessment, in the quarter ended December 31, 2017, theCompany has removed its valuation allowance against its federal NOLs and other federal deferred tax assets in order to state its deferred assets and liabilitiesat the amount more likely than not to be realized.F-30Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)13. DERIVATIVESAll derivative financial instruments are recorded at fair value in the accompanying balance sheet. The Company has not designated its derivativeinstruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes infair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”The Company has used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options toreduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap and fixed price basis contracts,the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Companyis required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company has fixed pricebasis swaps for the spread between the WTI Midland price and the WTI Cushing price. Under the Company’s costless collar contracts, the counterparty isrequired to make a payment to the Company if the settlement price for any settlement period is less than the put option price, and the Company is required tomake a payment to the counterparty if the settlement price for any settlement period is greater than the call option price. If the settlement price is between theput and the call price, there is no payment required. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges,with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and Crude Oil Brent, and with natural gasderivative settlements based on the New York Mercantile Exchange Henry Hub pricing.By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk andmarket risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract ispositive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended andrestated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post anycollateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterpartiesthat are also lenders in our credit facility and have been deemed an acceptable credit risk.As of December 31, 2017, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weightedaverage contract price is disclosed. 2018 2019 Volume (Bbls/MMBtu) Fixed Price Swap (perBbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (perBbl/MMBtu)Oil Swaps - WTI9,761,000 $51.10 1,095,000 $49.82Oil Swaps - BRENT1,830,000 $54.89 0 $—Oil Basis Swaps5,475,000 $0.88 0 $—Natural Gas Swaps7,750,000 $3.14 0 $— Floor Ceiling Volume(Bbls) Fixed Price (perBbl) Volume(Bbls) Fixed Price (perBbl)January 2018 - March 2018 Costless Collars540,000 $47.00 270,000 $56.34Balance sheet offsetting of derivative assets and liabilitiesThe fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futuresprices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject tocontractual terms which provide for net settlement.F-31Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangementswith counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2017 and 2016. December 31, 2017 2016 (in thousands)Gross amounts of assets presented in the Consolidated Balance Sheet$531 $709Net amounts of assets presented in the Consolidated Balance Sheet531 709 Gross amounts of liabilities presented in the Consolidated Balance Sheet106,670 22,608Net amounts of liabilities presented in the Consolidated Balance Sheet$106,670 $22,608The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivativeassets and liabilities and their locations on the consolidated balance sheet are as follows: December 31, 2017 2016 (in thousands)Current assets: derivative instruments$531 $—Noncurrent assets: derivative instruments— 709Total assets$531 $709Current liabilities: derivative instruments$100,367 $22,608Noncurrent liabilities: derivative instruments6,303 —Total liabilities$106,670 $22,608None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. Thefollowing table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations: Year Ended December 31, 2017 2016 2015 (in thousands)Change in fair value of open non-hedge derivative instruments$(84,240) $(26,522) $(112,918)Gain on settlement of non-hedge derivative instruments6,728 1,177 144,869Gain (loss) on derivative instruments$(77,512) $(25,345) $31,95114. FAIR VALUE MEASUREMENTSFair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between marketparticipants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use ofunobservable inputs.The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may beused to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and mayaffect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuationtechniques based on available inputs to measure the fair values of its assets and liabilities.Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.F-32Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices inactive markets included in Level 1, which are either directly or indirectly observable as of the reporting date.Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result inmanagement’s best estimate of fair value.Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.Assets and Liabilities Measured at Fair Value on a Recurring BasisCertain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of theCompany’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by areputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as ofDecember 31, 2017 and 2016. December 31, 2017 2016 (in thousands)Fixed price swaps: Quoted prices in active markets level 1$— $—Significant other observable inputs level 2(106,139) 23,317Significant unobservable inputs level 3— —Total$(106,139) $23,317Assets and Liabilities Measured at Fair Value on a Nonrecurring BasisThe following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets. December 31, 2017 December 31, 2016 Carrying Carrying Amount Fair Value Amount Fair Value (in thousands)Debt: Revolving credit facility$397,000 $397,000 $— $—4.750% Senior Notes due 2024500,000 501,855 500,000 491,2505.375% Senior Notes due 2025500,000 515,000 500,000 502,850Partnership revolving credit facility93,500 93,500 120,500 120,500The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their carrying value based on borrowingrates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of theSenior Notes was determined using the December 31, 2017 quoted market price, a Level 1 classification in the fair value hierarchy.F-33Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)15. COMMITMENTS AND CONTINGENCIESThe Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws andregulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas andcrude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters.Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.Lease CommitmentsThe following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excessof one year as of December 31, 2017:Year Ending December 31,Drilling RigCommitments Office and EquipmentLeases (in thousands)2018$21,882 $3,581201910,082 3,3072020— 2,9272021— 2,4062022— 2,242Thereafter— 7,973Total$31,964 $22,436The Company leases office space in Midland, Texas and in Oklahoma City, OK from unrelated third parties. The following table presents rentexpense for the years ended December 31, 2017, 2016 and 2015. Year ended December 31, 2017 2016 2015 (in thousands)Rent Expense$2,412 $1,961 $1,449Drilling contractsAs of December 31, 2017, the Company had entered into drilling rig contracts with various third parties in the ordinary course of business to ensurerig availability to complete the Company’s drilling projects. These commitments are not recorded in the accompanying consolidated balance sheets. Futurecommitments as of December 31, 2017 total approximately $32.0 million.Oil production purchase agreementOn May 24, 2012, the Company entered into an oil purchase agreement with Shell Trading (US) Company, in which the Company is obligated tocommence delivery of specified quantities of oil to Shell Trading (US) Company upon completion of the reversal of the Magellan Longhorn pipeline and itsconversion for oil shipment, which occurred on October 1, 2013. The Company’s agreement with Shell Trading has an initial term of five years from thecompletion date. The Company’s maximum delivery obligation under this agreement is 8,000 gross barrels per day. The Company has a one-time right toelect to decrease the contract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for theremainder of the term of the agreement. The Company will receive the price per barrel of oil based on the arithmetic average of the daily settlement price for“Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, as adjusted based on adjustment formulasspecified in the agreement. If the Company fails to deliver the required quantities of oil under the agreement during any three-month period following theservice commencement date, the Company has agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying (i) thevolume of oil that the Company failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect fortransportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiencyF-34Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)volume is calculated. The agreement may be terminated by Shell Trading (US) Company in the event that Shell Trading (US) Company’s contract fortransportation on the pipeline is terminated.Defined contribution planThe Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allowseligible employees to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Companymakes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees.Employer contributions vest immediately. For the years ended December 31, 2017, 2016 and 2015 the Company paid $1.8 million, $1.2 million and $1.4million, respectively, in contributions to the plan.16. SUBSEQUENT EVENTSCommodity ContractsSubsequent to December 31, 2017, the Company entered into new fixed price swaps and costless collars with corresponding put and call options.The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NewYork Mercantile Exchange West Texas Intermediate pricing.The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2017. When aggregating multiplecontracts, the weighted average contract price is disclosed. Volume (Bbls/MMBtu) Fixed Price Swap (perBbl/MMBtu)July 2018 - December 2018 Oil Swaps - WTI184,000 $60.70January 2019 - March 2019 Oil Swaps - WTI90,000 $58.70Fasken Building PurchaseOn January 31, 2018, the Company completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporateoffices are located.New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit FacilityOn January 29, 2018, the Company closed on the private placement issuance of $300.0 million aggregate principal amount of 5.375% Senior Notesdue 2025. In the offering, the Company received approximately $308.4 million in net proceeds, after deducting the initial purchasers’ discount and itsestimated offering expenses, but disregarding accrued interest. The Company used all of the net proceeds from the offering to repay a portion of theoutstanding borrowings under its revolving credit facility. In connection with the offering, the lenders under the Company’s revolving credit facility waivedthe borrowing base decrease that would have been triggered in connection with the offering. Immediately following the completion of the offering and theapplication of the net proceeds thereof, the Company’s borrowing base remained $1.8 billion, the Company’s elected commitment was $1.0 billion, and theCompany had $911.4 million of available borrowing capacity under its revolving credit facility.17. GUARANTOR FINANCIAL STATEMENTSAs of December 31, 2017, Diamondback E&P LLC and Diamondback O&G LLC (the “Guarantor Subsidiaries”) are guarantors under the indenturesrelating to the 2024 Senior Notes and the 2025 Senior Notes. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes, thePartnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream LLC were designated as Non-Guarantor Subsidiaries. The followingpresents condensed consolidated financial information for the Company (which for purposes of this Note 17 is referred to as the “Parent”), the GuarantorSubsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. Theinformation is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financialF-35Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated asindependent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believessuch financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the GuarantorSubsidiaries.Condensed Consolidated Balance SheetDecember 31, 2017(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedAssets Current assets: Cash and cash equivalents$54,074 $34,175 $24,197 $— $112,446Accounts receivable— 205,859 25,754 — 231,613Accounts receivable - related party— — 5,142 (5,142) —Intercompany receivable2,624,810 2,267,308 — (4,892,118) —Inventories— 9,108 — — 9,108Other current assets618 4,461 355 — 5,434Total current assets2,679,502 2,520,911 55,448 (4,897,260) 358,601Property and equipment: Oil and natural gas properties, at cost, full cost method of accounting— 8,129,211 1,103,897 (414) 9,232,694Midstream assets— 191,519 — — 191,519Other property, equipment and land— 80,776 — — 80,776Accumulated depletion, depreciation, amortization and impairment— (1,976,248) (189,466) 4,342 (2,161,372)Net property and equipment— 6,425,258 914,431 3,928 7,343,617Funds held in escrow— — 6,304 — 6,304Derivative instruments— — — — —Investment in subsidiaries3,809,557 — — (3,809,557) —Other assets— 25,609 36,854 — 62,463Total assets$6,489,059 $8,971,778 $1,013,037 $(8,702,889) $7,770,985Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade$1 $91,629 $2,960 $— $94,590Intercompany payable132,067 4,765,193 — (4,897,260) —Other current liabilities7,236 472,933 2,669 — 482,838Total current liabilities139,304 5,329,755 5,629 (4,897,260) 577,428Long-term debt986,847 397,000 93,500 — 1,477,347Derivative instruments— 6,303 — — 6,303Asset retirement obligations— 20,122 — — 20,122Deferred income taxes108,048 — — — 108,048Total liabilities1,234,199 5,753,180 99,129 (4,897,260) 2,189,248Commitments and contingencies Stockholders’ equity5,254,860 3,218,598 913,908 (4,132,506) 5,254,860Non-controlling interest— — — 326,877 326,877Total equity5,254,860 3,218,598 913,908 (3,805,629) 5,581,737Total liabilities and equity$6,489,059 $8,971,778 $1,013,037 $(8,702,889) $7,770,985F-36Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Balance SheetDecember 31, 2016(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedAssets Current assets: Cash and cash equivalents$1,643,226 $14,135 $9,213 $— $1,666,574Restricted cash— — 500 — 500Accounts receivable— 109,782 10,043 — 119,825Accounts receivable - related party— 297 3,470 (3,470) 297Intercompany receivable3,060,566 359,502 — (3,420,068) —Inventories— 1,983 — — 1,983Other current assets481 2,319 187 — 2,987Total current assets4,704,273 488,018 23,413 (3,423,538) 1,792,166Property and equipment: Oil and natural gas properties, at cost, full cost method of accounting— 4,400,002 760,818 (559) 5,160,261Midstream assets— 8,362 — — 8,362Other property, equipment and land— 58,290 — — 58,290Accumulated depletion, depreciation, amortization and impairment— (1,695,701) (148,948) 8,593 (1,836,056)Net property and equipment— 2,770,953 611,870 8,034 3,390,857Funds held in escrow— 121,391 — — 121,391Derivative instruments— 709 — — 709Investment in subsidiaries(15,500) — — 15,500 —Other assets— 9,291 35,266 — 44,557Total assets$4,688,773 $3,390,362 $670,549 $(3,400,004) $5,349,680Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade$30 $45,838 $1,780 $— $47,648Accounts payable-related party1 — — — 1Intercompany payable— 3,423,538 — (3,423,538) —Other current liabilities5,868 155,454 371 — 161,693Total current liabilities5,899 3,624,830 2,151 (3,423,538) 209,342Long-term debt985,412 — 120,500 — 1,105,912Asset retirement obligations— 16,134 — — 16,134Total liabilities991,311 3,640,964 122,651 (3,423,538) 1,331,388Commitments and contingencies Stockholders’ equity3,697,462 (250,602) 547,898 (297,296) 3,697,462Non-controlling interest— — — 320,830 320,830Total equity3,697,462 (250,602) 547,898 23,534 4,018,292Total liabilities and equity$4,688,773 $3,390,362 $670,549 $(3,400,004) $5,349,680F-37Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of OperationsYear Ended December 31, 2017(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedRevenues: Oil sales$— $903,842 $— $140,175 $1,044,017Natural gas sales— 42,899 — 9,311 52,210Natural gas liquid sales— 79,371 — 10,677 90,048Royalty income— — 160,163 (160,163) —Lease bonus income— — 11,870 (106) 11,764Midstream services— 7,072 — — 7,072Total revenues— 1,033,184 172,033 (106) 1,205,111Costs and expenses: Lease operating expenses— 126,524 — — 126,524Production and ad valorem taxes— 62,897 10,608 — 73,505Gathering and transportation— 12,045 789 — 12,834Midstream services— 10,409 — — 10,409Depreciation, depletion and amortization— 281,989 40,519 4,251 326,759General and administrative expenses26,776 18,057 6,296 (2,460) 48,669Asset retirement obligation accretion— 1,391 — — 1,391Total costs and expenses26,776 513,312 58,212 1,791 600,091Income (loss) from operations(26,776) 519,872 113,821 (1,897) 605,020Other income (expense) Interest expense, net(29,925) (7,465) (3,164) — (40,554)Other income, net1,142 10,732 821 (2,460) 10,235Loss on derivative instruments, net— (77,512) — — (77,512)Total other expense, net(28,783) (74,245) (2,343) (2,460) (107,831)Income (loss) before income taxes(55,559) 445,627 111,478 (4,357) 497,189Benefit from income taxes(19,568) — — — (19,568)Net income (loss)(35,991) 445,627 111,478 (4,357) 516,757Net income attributable to non-controlling interest— — — 34,496 34,496Net income (loss) attributable to Diamondback Energy, Inc.$(35,991) $445,627 $111,478 $(38,853) $482,261F-38Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of OperationsYear Ended December 31, 2016(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedRevenues: Oil sales$— $399,007 $— $71,521 $470,528Natural gas sales— 19,399 — 3,107 22,506Natural gas liquid sales— 29,864 — 4,209 34,073Royalty income— — 78,837 (78,837) —Lease bonus income— — 309 (309) —Total revenues— 448,270 79,146 (309) 527,107Costs and expenses: Lease operating expenses— 82,428 — — 82,428Production and ad valorem taxes— 28,912 5,544 — 34,456Gathering and transportation— 11,189 415 2 11,606Depreciation, depletion and amortization— 151,376 29,820 (3,181) 178,015Impairment of oil and natural gas properties— 198,067 47,469 — 245,536General and administrative expenses25,959 11,451 5,209 — 42,619Asset retirement obligation accretion— 1,064 — — 1,064Total costs and expenses25,959 484,487 88,457 (3,179) 595,724Income (loss) from operations(25,959) (36,217) (9,311) 2,870 (68,617)Other income (expense) Interest expense, net(35,318) (2,911) (2,455) — (40,684)Other income, net437 2,010 867 (250) 3,064Loss on derivative instruments, net— (25,345) — — (25,345)Loss on extinguishment of debt(33,134) — — — (33,134)Total other expense, net(68,015) (26,246) (1,588) (250) (96,099)Income (loss) before income taxes(93,974) (62,463) (10,899) 2,620 (164,716)Provision for income taxes192 — — — 192Net income (loss)(94,166) (62,463) (10,899) 2,620 (164,908)Net income attributable to non-controlling interest— — — 126 126Net income (loss) attributable to Diamondback Energy, Inc.$(94,166) $(62,463) $(10,899) $2,494 $(165,034)F-39Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of OperationsYear Ended December 31, 2015(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedRevenues: Oil sales$— $336,106 $— $69,609 $405,715Natural gas sales— 16,932 — 2,660 19,592Natural gas liquid sales— 18,836 — 2,590 21,426Royalty income— — 74,859 (74,859) —Total revenues— 371,874 74,859 — 446,733Costs and expenses: Lease operating expenses— 82,625 — — 82,625Production and ad valorem taxes— 27,459 5,531 — 32,990Gathering and transportation— 5,832 259 — 6,091Depreciation, depletion and amortization— 182,395 35,436 (134) 217,697Impairment of oil and natural gas properties— 814,798 3,423 (3,423) 814,798General and administrative expenses17,077 9,056 5,835 — 31,968Asset retirement obligation accretion expense— 833 — — 833Total costs and expenses17,077 1,122,998 50,484 (3,557) 1,187,002Income (loss) from operations(17,077) (751,124) 24,375 3,557 (740,269)Other income (expense) Interest expense, net(35,651) (4,749) (1,110) — (41,510)Other income, net1 (427) 1,154 — 728Gain on derivative instruments, net— 31,951 — — 31,951Total other expense, net(35,650) 26,775 44 — (8,831)Income (loss) before income taxes(52,727) (724,349) 24,419 3,557 (749,100)Benefit from income taxes(201,310) — — — (201,310)Net income (loss)$148,583 $(724,349) $24,419 $3,557 $(547,790)Net income attributable to non-controlling interest$— $— $— $2,838 $2,838Net income (loss) attributable to Diamondback Energy, Inc.$148,583 $(724,349) $24,419 $719 $(550,628)F-40Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of Cash FlowsYear Ended December 31, 2017(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedNet cash provided by (used in) operating activities$(29,470) $778,876 $139,219 $— $888,625Cash flows from investing activities: Additions to oil and natural gas properties— (792,599) — — (792,599)Additions to midstream assets— (68,139) — — (68,139)Purchase of other property, equipment and land— (22,779) — — (22,779)Acquisition of leasehold interests— (1,960,591) — — (1,960,591)Acquisition of mineral interests— (63,371) (344,079) — (407,450)Acquisition of midstream assets— (50,279) — — (50,279)Proceeds from sale of assets— 65,656 — — 65,656Funds held in escrow— 104,087 — — 104,087Equity investments— (188) — — (188)Intercompany transfers(1,631,078) 1,631,078 — — —Net cash used in investing activities(1,631,078) (1,157,125) (344,079) — (3,132,282)Cash flows from financing activities: Proceeds from borrowing on credit facility— 475,000 278,500 — 753,500Repayment on credit facility— (78,000) (305,500) — (383,500)Purchase of subsidiary units by parent(10,068) — — 10,068 —Debt issuance costs(8,326) 1,289 (2,259) — (9,296)Public offering costs(77) — (433) — (510)Proceeds from public offerings— — 380,412 (10,068) 370,344Distribution from subsidiary89,509 — — (89,509) —Exercise of stock options358 — — — 358Distribution to non-controlling interest— — (130,876) 89,509 (41,367)Net cash provided by financing activities71,396 398,289 219,844 — 689,529Net increase (decrease) in cash and cash equivalents(1,589,152) 20,040 14,984 — (1,554,128)Cash and cash equivalents at beginning of period1,643,226 14,135 9,213 — 1,666,574Cash and cash equivalents at end of period$54,074 $34,175 $24,197 $— $112,446F-41Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of Cash FlowsYear Ended December 31, 2016(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedNet cash provided by (used in) operating activities$(39,894) $303,347 $68,627 $— $332,080Cash flows from investing activities: Additions to oil and natural gas properties— (363,087) — — (363,087)Additions to midstream assets— (1,188) — — (1,188)Purchase of other property, equipment and land— (9,891) — — (9,891)Acquisition of leasehold interests— (611,280) — — (611,280)Acquisition of mineral interests— — (205,721) — (205,721)Proceeds from sale of assets— 4,661 — — 4,661Funds held in escrow— (121,391) — — (121,391)Equity investments— (2,345) — — (2,345)Intercompany transfers(796,053) 796,053 — — —Net cash used in investing activities(796,053) (308,468) (205,721) — (1,310,242)Cash flows from financing activities: Proceeds from borrowing on credit facility— — 164,000 — 164,000Repayment on credit facility— (11,000) (78,000) — (89,000)Proceeds from senior notes1,000,000 — — — 1,000,000Repayment of senior notes(450,000) — — — (450,000)Premium on extinguishment of debt(26,561) — — — (26,561)Debt issuance costs(14,449) (172) (442) — (15,063)Public offering costs(636) — (546) — (1,182)Proceeds from public offerings1,925,923 — 125,580 — 2,051,503Distribution from subsidiary55,250 — — (55,250) —Exercise of stock options498 — — — 498Distribution to non-controlling interest— — (64,824) 55,250 (9,574)Intercompany transfers(11,000) 11,000 — — —Net cash provided by (used in) financing activities2,479,025 (172) 145,768 — 2,624,621Net increase (decrease) in cash and cash equivalents1,643,078 (5,293) 8,674 — 1,646,459Cash and cash equivalents at beginning of period148 19,428 539 — 20,115Cash and cash equivalents at end of period$1,643,226 $14,135 $9,213 $— $1,666,574F-42Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of Cash FlowsYear Ended December 31, 2015(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedNet cash provided by (used in) operating activities$(37,597) $390,266 $63,832 $— $416,501Cash flows from investing activities: Additions to oil and natural gas properties— (419,512) — — (419,512)Purchase of other property, equipment and land— (1,213) — — (1,213)Acquisition of leasehold interests— (437,455) — — (437,455)Acquisition of royalty interests— — (43,907) — (43,907)Proceeds from sale of assets— 9,739 — — 9,739Equity investments— (2,702) — — (2,702)Intercompany transfers(145,023) 145,023 — — —Net cash used in investing activities(145,023) (706,120) (43,907) — (895,050)Cash flows from financing activities: Proceeds from borrowing on credit facility— 390,501 34,500 — 425,001Repayment on credit facility— (603,001) — — (603,001)Debt issuance costs— (85) (441) — (526)Public offering costs(586) — — — (586)Proceeds from public offerings650,688 — — — 650,688Distribution from subsidiary60,587 — — (60,587) —Exercise of stock options4,873 — — — 4,873Distribution to non-controlling interest— — (68,555) 60,587 (7,968)Intercompany transfers(532,800) 532,800 — — —Net cash provided by (used in) financing activities182,762 320,215 (34,496) — 468,481Net increase (decrease) in cash and cash equivalents142 4,361 (14,571) — (10,068)Cash and cash equivalents at beginning of period6 15,067 15,110 — 30,183Cash and cash equivalents at end of period$148 $19,428 $539 $— $20,115F-43Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)18. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)The Company’s oil and natural gas reserves are attributable solely to properties within the United States.Capitalized oil and natural gas costsAggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortizationand impairment are as follows: December 31, 2017 2016 (In thousands)Oil and Natural Gas Properties: Proved properties$5,126,829 $3,429,742Unproved properties4,105,865 1,730,519Total oil and natural gas properties9,232,694 5,160,261Accumulated depreciation, depletion, amortization(1,009,893) (687,685)Accumulated impairment(1,143,498) (1,143,498)Net oil and natural gas properties capitalized$7,079,303 $3,329,078Costs incurred in oil and natural gas activitiesCosts incurred in oil and natural gas property acquisition, exploration and development activities are as follows: Year Ended December 31, 2017 2016 2015 (In thousands)Acquisition costs Proved properties$452,661 $72,044 $64,340Unproved properties2,692,000 752,117 448,638Development costs145,362 47,575 42,749Exploration costs779,728 329,122 319,102Capitalized asset retirement costs2,682 4,030 3,458Total$4,072,433 $1,204,888 $878,287F-44Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Results of Operations from Oil and Natural Gas Producing ActivitiesThe following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interestcosts or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil,natural gas and natural gas liquids operations. Year Ended December 31, 2017 2016 2015 (In thousands)Oil, natural gas and natural gas liquid sales$1,186,275 $527,107 $446,733Lease operating expenses(126,524) (82,428) (82,625)Production and ad valorem taxes(73,505) (34,456) (32,990)Gathering and transportation(12,834) (11,606) (6,091)Depreciation, depletion, and amortization(321,870) (176,369) (216,056)Impairment— (245,536) (814,798)Asset retirement obligation accretion expense(1,391) (1,064) (833)Income tax benefit (expense)19,568 (192) 201,310Results of operations$669,719 $(24,544) $(505,350)Oil and Natural Gas ReservesProved oil and natural gas reserve estimates as of December 31, 2017, 2016 and 2015 were prepared by Ryder Scott Company, L.P., independentpetroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be preparedunder existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is asubjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserveestimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing andproduction subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantitiesof oil and natural gas that are ultimately recovered.F-45Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The changes in estimated proved reserves are as follows: Oil(MBbls) Natural GasLiquids(MBbls) Natural Gas(MMcf)Proved Developed and Undeveloped Reserves: As of January 1, 201575,690 18,542 111,605Extensions and discoveries48,725 12,056 53,453Revisions of previous estimates(12,130) (4,081) (14,726)Purchase of reserves in place2,775 1,165 7,102Production(9,081) (1,678) (7,931)As of December 31, 2015105,979 26,004 149,503Extensions and discoveries55,069 13,962 64,758Revisions of previous estimates(12,483) (1,888) (34,519)Purchase of reserves in place2,537 1,455 7,567Divestitures(366) — (1,985)Production(11,562) (2,399) (10,428)As of December 31, 2016139,174 37,134 174,896Extensions and discoveries99,980 20,825 109,032Revisions of previous estimates(7,715) (1,466) (10,065)Purchase of reserves in place24,322 2,633 34,640Divestitures(1,163) (461) (2,474)Production(21,417) (4,056) (20,660)As of December 31, 2017233,181 54,609 285,369 Proved Developed Reserves: January 1, 201543,886 11,221 68,264December 31, 201560,569 15,418 96,871December 31, 201679,457 22,080 105,399December 31, 2017141,246 35,412 190,740 Proved Undeveloped Reserves: January 1, 201531,804 7,321 43,341December 31, 201545,409 10,586 52,632December 31, 201659,717 15,054 69,497December 31, 201791,935 19,198 94,629Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained fromdevelopment drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.During the year ended December 31, 2017, the Company’s extensions and discoveries of 138,977 MBOE resulted primarily from the drilling of 102new wells and from 87 new proved undeveloped locations added. Partnership royalty interests accounted for 8% of the extension volumes. The Company’srevisions of previous estimates were primarily the result of 2,550 MBOE from reclassifying PUD locations due to anticipated timing, with the remaining8,308 MBOE being technical revisions. Delaware Basin working interest purchases accounted for 87% of the total purchases and Partnership royalty interestpurchases accounted for 10%, with working interest purchases contributing the remainder.During the year ended December 31, 2016, the Company’s extensions and discoveries of 69,042 MBOE resulted primarily from the drilling of 59new wells and from 51 new proved undeveloped locations added. The Company owns the mineral interests associated with 30 of the 59 new wells and 30 ofthe 51 proved undeveloped locations through the Partnership. The Company’s negative revisions of previous estimates were primarily the result of 5,978MBOE of pricing revisions and 7,253 MBOE from reclassifying 17 locations from proved undeveloped due to pricing. Purchases of reserves in place of 3,993MBOEF-46Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)were primarily the result of the purchase of producing wells included with the Reeves and Ward county acreage purchase and reserves associated withmultiple purchases made by the Partnership.During the year ended December 31, 2015, the Company made one large acquisition of oil and natural gas interests in 2015 located in westernHoward and eastern Martin counties. Several small acquisitions were also made in various counties including Andrews, Midland, Martin, and Glasscockcounties. The reserves from these acquisitions were primarily proved producing reserves from 136 vertical wells and four horizontal wells and three verticalwells where additional interest was acquired. All of the properties were acquired for horizontal exploitation. Although there were four producing horizontalwells on the properties no PUD’s were included in the acquired properties because of very limited production from the wells at the time of acquisition.Significant extensions occurred in 2015 as a result of continued horizontal development of the Lower Spraberry and Wolfcamp B horizons. There was alsoinitial development of the Wolfcamp A and Middle Spraberry horizons in some locations. The extensions resulted from two vertical wells and 119 horizontalwells in which the Company has a working interest and from 16 horizontal wells in which the Company has a mineral interest through its ownership in Viper.Of the two vertical wells and 135 horizontal wells, one of the vertical wells and 89 of the horizontal wells are in the proved undeveloped category. Therevisions are primarily the result of lower product pricing. As a result of lower pricing, 80 vertical wells and 22 horizontal wells in which the Company has aworking interest and 22 vertical wells in which the Company has a mineral interest were downgraded from the proved undeveloped category to probable orpossible reserves. Additional downward revisions resulted from shorter producing lives on existing wells as a result of the wells reaching their economic limitsooner due to lower revenues.At December 31, 2017, the Company’s estimated PUD reserves were approximately 126,904 MBOE, a 40,550 MBOE increase over the reserveestimate at December 31, 2016 of 86,354 MBOE. The following table includes the changes in PUD reserves for 2017: (MBOE)Beginning proved undeveloped reserves at December 31, 201686,354Undeveloped reserves transferred to developed(31,666)Revisions(4,710)Net purchases6,246Extensions and discoveries70,680Ending proved undeveloped reserves at December 31, 2017126,904The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676 MBOE from 87 gross (75 net) wells in which theCompany has a working interest and 3,004 MBOE from 40 gross wells in which the Partnership owns royalty interests. Of the 87 gross wells, 26 were in theDelaware Basin. Transfers of 31,666 MBOE were the result of drilling or participating in 44 gross (37 net) horizontal wells in which the Company has aworking interest and 27 gross wells in which the Company has a royalty interest or mineral interest through the Partnership. The Company owns a workinginterest in 23 of the 27 gross Partnership wells. Net purchases of 6,246 MBOE were primarily from the Company’s purchase in Pecos and Reeves counties.Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions.As of December 31, 2017, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they wereinitially recorded. During 2017, approximately $145.4 million in capital expenditures went toward the development of proved undeveloped reserves, whichincludes drilling, completion and other facility costs associated with developing proved undeveloped wells.Standardized Measure of Discounted Future Net Cash FlowsThe standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. The projectionsshould not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to theCompany. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in theperiods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.F-47Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gasreserves as of December 31, 2017, 2016 and 2015. December 31, 2017 2016 2015 (In thousands)Future cash inflows$12,921,897 $6,275,705 $5,377,783Future development costs(1,123,979) (617,636) (548,239)Future production costs(2,994,877) (1,392,852) (1,279,101)Future production taxes(928,891) (459,244) (363,129)Future income tax expenses(83,961) (75,595) (28,233)Future net cash flows7,790,189 3,730,378 3,159,08110% discount to reflect timing of cash flows(4,033,130) (2,018,965) (1,740,948)Standardized measure of discounted future net cash flows$3,757,059 $1,711,413 $1,418,133In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation offuture cash inflows. December 31, 2017 2016 2015 Unweighted Arithmetic Average First-Day-of-the-Month PricesOil (per Bbl)$48.03 $39.94 $45.07Natural gas (per Mcf)$2.06 $1.36 $1.83Natural gas liquids (per Bbl)$20.79 $12.91 $12.56Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: Year Ended December 31, 2017 2016 2015 (In thousands)Standardized measure of discounted future net cash flows at the beginning of the period$1,711,413 $1,418,133 $2,045,224Sales of oil and natural gas, net of production costs(986,246) (411,558) (331,119)Acquisition of reserves439,396 43,142 58,849Divestiture of reserves(11,072) (5,481) (1,490)Extensions and discoveries, net of future development costs1,791,686 779,359 629,149Previously estimated development costs incurred during the period190,121 85,696 129,901Net changes in prices and production costs577,781 (150,509) (1,383,698)Changes in estimated future development costs(52,908) 20,647 38,638Revisions of previous quantity estimates(98,857) (123,795) (377,160)Accretion of discount174,185 143,134 236,716Net change in income taxes(9,074) (30,530) 268,963Net changes in timing of production and other30,634 (56,825) 104,160Standardized measure of discounted future net cash flows at the end of the period$3,757,059 $1,711,413 $1,418,133F-48Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)19. QUARTERLY FINANCIAL DATA (Unaudited)The Company’s unaudited quarterly financial data for 2017 and 2016 is summarized below. 2017 FirstQuarter SecondQuarter ThirdQuarter FourthQuarterRevenues$235,230 $269,434 $301,253 $399,194Income from operations116,410 132,308 142,639 213,663Income tax expense (benefit)1,957 1,579 857 (23,961)Net income141,074 164,128 81,948 129,607Net income attributable to non-controlling interest4,801 5,723 8,924 15,048Net income attributable to Diamondback Energy, Inc.$136,273 $158,405 $73,024 $114,559Earnings per common share Basic$1.46 $1.61 $0.74 $1.17Diluted$1.46 $1.61 $0.74 $1.16 2016 FirstQuarter SecondQuarter ThirdQuarter FourthQuarterRevenues$87,481 $112,483 $142,131 $185,012Income (loss) from operations(27,603) (134,786) 6,693 87,079Income tax expense (benefit)— 368 — (176)Net income (loss)(35,627) (157,121) (600) 28,440Net income (loss) attributable to non-controlling interest(2,715) (1,631) 1,630 2,842Net income (loss) attributable to Diamondback Energy, Inc.$(32,912) $(155,490) $(2,230) $25,598Earnings per common share Basic$(0.46) $(2.17) $(0.03) $0.32Diluted$(0.46) $(2.17) $(0.03) $0.32F-49Exhibit 21.1Diamondback Energy, Inc.Subsidiaries of RegistrantName of SubsidiaryJurisdiction of IncorporationDiamondback E&P LLCDelawareDiamondback O&G LLCDelawareRattler Midstream LLCDelawareViper Energy Partners GPDelawareViper Energy Partners LPDelawareViper Energy Partners LLCDelawareExhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe have issued our reports dated February 14, 2018, with respect to the consolidated financial statements and internal control overfinancial reporting included in the Annual Report of Diamondback Energy, Inc. on Form 10-K for the year ended December 31, 2017.We consent to the incorporation by reference of said reports in the Registration Statements of Diamondback Energy, Inc. on Forms S-3ASR (File No. 333-214892, effective December 2, 2016) and (File No. 333-218346, effective May 30, 2017), Form S-4, as amended(File No. 333-217479, effective August 9, 2017) and on Forms S-8 (File No. 333-188552, effective May 13, 2013) and (File No. 333-215798, effective January 27, 2017)./s/ GRANT THORNTON LLPOklahoma City, OklahomaFebruary 14, 2018Exhibit 23.2CONSENT OF RYDER SCOTT COMPANY, L.P.We have issued our report dated January 18, 2018 on estimates of proved reserves, future production and income attributable tocertain leasehold interest of Diamondback Energy, Inc. (“Diamondback”) as of December 31, 2017. As independent oil and gasconsultants, we hereby consent to the inclusion of our report and the information contained therein and information from our priorreserve reports referenced in this Annual Report on Form 10-K of Diamondback (this “Annual Report”) and to all references to our firmin this Annual Report. We hereby also consent to the incorporation by reference of such reports and the information contained thereinin the Registration Statements of Diamondback on Forms S-3ASR (File No. 333-214892, effective December 2, 2016) and (File No.333-218346, effective May 30, 2017), Form S-4, as amended (File No. 333-217479, effective August 9, 2017) and on Forms S-8 (FileNo. 333-188552, effective May 13, 2013) and (File No. 333-215798, effective January 27, 2017). /s/ Ryder Scott Company, L.P. RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580Houston, TexasFebruary 14, 2018Exhibit 23.3CONSENT OF RYDER SCOTT COMPANY, L.P.We have issued our report dated January 18, 2018 on estimates of proved reserves, future production and income attributable to certainroyalty interests of Viper Energy Partners LP, a subsidiary of Diamondback Energy, Inc. (“Diamondback”), as of December 31, 2017.As independent oil and gas consultants, we hereby consent to the inclusion of our report and the information contained therein andinformation from our prior reserve reports referenced in this Annual Report on Form 10-K of Diamondback (this “Annual Report”) andto all references to our firm in this Annual Report. We hereby also consent to the incorporation by reference of such reports and theinformation contained therein in the Registration Statements of Diamondback on Forms S-3ASR (File No. 333-214892, effectiveDecember 2, 2016) and (File No. 333-218346, effective May 30, 2017), Form S-4, as amended (File No. 333-217479, effective August9, 2017) and on Forms S-8 (File No. 333-188552, effective May 13, 2013) and (File No. 333-215798, effective January 27, 2017). /s/ Ryder Scott Company, L.P. RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580Houston, TexasFebruary 14, 2018EXHIBIT 31.1CERTIFICATIONI, Travis D. Stice, certify that:1.I have reviewed this Annual Report on Form 10-K of Diamondback Energy, Inc.2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f))for the registrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. Date:February 14, 2018 /s/ Travis D. Stice Travis D. Stice Chief Executive OfficerEXHIBIT 31.2CERTIFICATIONI, Teresa L. Dick, certify that:1.I have reviewed this Annual Report on Form 10-K of Diamondback Energy, Inc.2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f))for the registrant and have:(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared;(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles;(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materiallyaffect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. Date:February 14, 2018 /s/ Teresa L. Dick Teresa L. Dick Chief Financial OfficerEXHIBIT 32.1CERTIFICATION OF PERIOD REPORTI, Travis D. Stice, Chief Executive Officer of Diamondback Energy, Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:(1) the Annual Report on Form 10-K of the Company for the year ended December 31, 2017 (the “Report”) fully complies with the requirements ofSection 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date:February 14, 2018 /s/ Travis D. Stice Travis D. Stice Chief Executive OfficerEXHIBIT 32.2CERTIFICATION OF PERIOD REPORTI, Teresa L. Dick, Chief Financial Officer of Diamondback Energy, Inc. (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:(1) the Annual Report on Form 10-K of the Company for the year ended December 31, 2017 (the “Report”) fully complies with the requirements ofSection 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date:February 14, 2018 /s/ Teresa L. Dick Teresa L. Dick Chief Financial OfficerExhibit 99.1DIAMONDBACK ENERGY, INC.EstimatedFuture Reserves and IncomeAttributable to CertainLeasehold InterestsSEC ParametersAs ofDecember 31, 2017\s\ Val Rick RobinsonVal Rick Robinson, P.E.TBPE License No. 105137Managing Senior Vice President[SEAL]RYDER SCOTT COMPANY, L.P.TBPE Firm License No. F-1580RYDER SCOTT COMPANY PETROLEUM CONSULTANTSJanuary 18, 2018Diamondback Energy, Inc.500 West Texas, Suite 1210Midland, Texas 79701Gentlemen:At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, futureproduction, and income attributable to certain leasehold interests of Diamondback Energy, Inc. (Diamondback) as of December 31,2017. The subject properties are located in the state of Texas. The reserves and income data were estimated based on thedefinitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Codeof Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register(SEC regulations). Our third party study, completed on January 16, 2018 and presented herein, was prepared for public disclosurein Diamondback’s filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100percent of the total net proved gas reserves of Diamondback as of December 31, 2017.The estimated reserves and future net income amounts presented in this report, as of December 31, 2017 are related tohydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the un-weighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required bythe SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes ofreserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantitiespresented in this report. The results of this study are summarized as follows.SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258SEC PARAMETERSEstimated Net Reserves and Income DataCertain Leasehold Interests ofDiamondback Energy, Inc.As of December 31, 2017 Proved Developed Total Producing Non-Producing ProvedNet Remaining Reserves Oil/Condensate – MBbl 122,458 84,838 207,296Plant Products – MBbl 30,875 17,439 48,314Gas – MMCF 161,484 87,490 248,974MBOE 180,247 116,859 297,106 Income Data ($M) Future Gross Revenue $6,520,998 $4,382,901 $10,903,899Deductions 2,230,752 2,119,316 4,350,068Future Net Income (FNI) $4,290,246 $2,263,585 $6,553,831 Discounted FNI @ 10% $2,329,892 $838,029 $3,167,921Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an“as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which thegas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas isconverted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousandsbarrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars($M).The estimates of the reserves, future production, and income attributable to properties in this report were prepared using theeconomic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. Theprogram was used solely at the request of Diamondback. Ryder Scott has found this program to be generally acceptable, but notesthat certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties beingsummarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of thesame properties, also due to rounding. The rounding differences are not material.The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs ofoperating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage.Other costs shown in the cash flow are variable production costs. The future net income is before the deduction of state and federalincome taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does itinclude any adjustment for cash on hand or undistributed income.Liquid hydrocarbon reserves account for approximately 96 percent and gas reserves account for the remaining 4 percent oftotal future gross revenue from proved reserves.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSThe discounted future net income shown above was calculated using a discount rate of 10 percent per annum compoundedmonthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results areshown in summary form as follows. Discounted Future Net Income (M$) As of December 31, 2017Discount Rate Total Percent Proved 5 $4,262,105 15 $2,536,634 20 $2,125,329 30 $1,618,661 The results shown above are presented for your information and should not be construed as our estimate of fair marketvalue.Reserves Included in This ReportThe proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’sRegulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum ReservesDefinitions” is included as an attachment to this report.The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves StatusDefinitions and Guidelines” in this report.No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. Theproved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. At Diamondback’s request, this report addressesonly the proved reserves attributable to the properties evaluated herein.Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, canbe estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves includedherein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when basedon deterministic methods, as a “high degree of confidence that the quantities will be recovered.”RYDER SCOTT COMPANY PETROLEUM CONSULTANTSProved reserve estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR)with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates ofproved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical oreconomic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as beingexact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than theestimated amounts.Diamondback’s operations may be subject to various levels of governmental controls and regulations. These controls andregulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to producehydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxesand levies including income tax and are subject to change from time to time. Such changes in governmental regulations andpolicies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differsignificantly from the estimated quantities.The estimates of proved reserves presented herein were based upon a detailed study of the properties in whichDiamondback owns an interest; however, we have not made any field examination of the properties. No consideration was given inthis report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and cleanup damages, if any, caused by past operating practices.Estimates of ReservesThe estimation of reserves involves two distinct determinations. The first determination results in the estimation of thequantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with thoseestimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generallyaccepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-basedmethods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by thereserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method orcombination of methods which in their professional judgment is most appropriate given the nature and amount of reliablegeoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics ofthe reservoir being evaluated and the stage of development or producing maturity of the property.In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this datamay indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range inthe quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of thereserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discreteincremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is thecategorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimatedquantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actuallyrecovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reservesthat are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to berecovered.” The SEC states that “possible reserves are those additional reserves that are lessRYDER SCOTT COMPANY PETROLEUM CONSULTANTScertain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability ofexceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet theSEC definitions as noted above.Estimates of reserves quantities and their associated reserve categories may be revised in the future as additionalgeoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reservecategories may also be revised due to other factors such as changes in economic conditions, results of future operations, effectsof regulation by governmental agencies or geopolitical or economic risks as previously noted herein.The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combinationof both methods. Approximately 83 percent of the proved producing reserves attributable to producing wells were estimated byperformance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilizedextrapolations of historical production and pressure data available through December 2017 in those cases where such data wereconsidered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Diamondback and were consideredsufficient for the purpose thereof. The remaining 17 percent of the proved producing reserves were estimated by analogy, or acombination of performance and analogy methods. The analogy method was used where there were inadequate historicalperformance data to establish a definitive trend and where the use of production performance data as a basis for the reserveestimates was considered to be inappropriate.All proved undeveloped reserves included herein were estimated by the analogy method.To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider manyfactors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical andengineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, andforecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipatedto be economically producible from a given date forward based on existing economic conditions including the prices and costs atwhich economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future pricesreceived for the sale of production and the operating costs and other costs relating to such production may increase or decreasefrom those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted fromconsideration in making this evaluation.Diamondback has informed us that they have furnished us all of the material accounts, records, geological and engineeringdata, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, wehave relied upon data furnished by Diamondback with respect to property interests owned, production and well tests fromexamined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, advalorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage,product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochoremaps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness;however, we have not conducted an independent verification of the data furnished by Diamondback. We consider the factual dataused in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for thepurpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare theestimates of reserves herein. The proved reservesRYDER SCOTT COMPANY PETROLEUM CONSULTANTSincluded herein were determined in conformance with the United States Securities and Exchange Commission (SEC)Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred toherein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with thedefinitions, guidelines and disclosure requirements as required by the SEC regulations.Future Production RatesFor wells currently on production, our forecasts of future production rates are based on historical performance data. If noproduction decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailmentwhere appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion ofthe reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.Test data and other related information were used to estimate the anticipated initial production rates for those wells orlocations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipateddate furnished by Diamondback. Wells or locations that are not currently producing may start producing earlier or later thananticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors mayinclude delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/orconstraints set by regulatory bodies.The future production rates from wells currently on production or wells or locations that are not currently producing may bemore or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related tosurface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/orallowables or other constraints set by regulatory bodies.Hydrocarbon PricesThe hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-monthperiod prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbonproducts sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments,were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month un-weightedarithmetic average as previously described.As noted above, Diamondback furnished us with the average prices in effect on December 31, 2017. These initial SEChydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to thegeographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials asdescribed herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area includedin the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.The product prices which were actually used to determine the future gross revenue for each property reflect adjustments tothe benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referredto herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Diamondback and wereaccepted as factual dataRYDER SCOTT COMPANY PETROLEUM CONSULTANTSand reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used byDiamondback to determine these differentials.In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred toherein as the “average realized prices.” The average realized prices shown in the table below were determined from the total futuregross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SECdisclosure requirements for each of the geographic areas included in the report.GeographicAreaProductPriceReferenceAverage BenchmarkPricesAverage ProvedRealizedPricesNorth America United StatesOil/CondensateWTI Cushing$51.34/Bbl$48.00/BblNGLsPropane, Mt. Belvieu$31.82/Bbl$21.01/BblGasHenry Hub$2.98/MMBTU$2.05/MCFThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual propertyevaluations.CostsOperating costs for the leases and wells in this report were furnished by Diamondback and are based on the operatingexpense reports of Diamondback and include only those costs directly applicable to the leases or wells. The operating costsinclude a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to uswere accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independentverification of the operating cost data used by Diamondback. No deduction was made for loan repayments, interest expenses, orexploration and development prepayments that were not charged directly to the leases or wells.Development costs were furnished to us by Diamondback and are based on authorizations for expenditure for the proposedwork or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by usfor their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost ofabandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates ofthe net abandonment costs furnished by Diamondback were accepted without independent verification. Ryder Scott has notperformed a detailed study of the abandonment costs or the salvage value and makes no warranty for Diamondback’s estimate.The undeveloped reserves in this report have been incorporated herein in accordance with Diamondback’s plans to developthese reserves as of December 31, 2017. The implementation of Diamondback’s development plans as presented to us andincorporated herein is subject to the approval process adopted by Diamondback’s management. As the result of our inquiriesduring the course of preparing this report, Diamondback has informed us that the development activities included herein have beensubjected to and received the internal approvals required by Diamondback’s management at the appropriate local, regional and/orcorporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partnerAFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Diamondback.Additionally,RYDER SCOTT COMPANY PETROLEUM CONSULTANTSDiamondback has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly altertheir plans. While these plans could change from those under existing economic conditions as of December 31, 2017, suchchanges were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.Current costs used by Diamondback were held constant throughout the life of the properties.Standards of Independence and Professional QualificationRyder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting servicesthroughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; andCalgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firmand the large number of clients for which we provide services, no single client or job represents a material portion of our annualrevenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separateand independent from the operating and investment decision-making process of our clients. This allows us to bring the highest levelof independence and objectivity to each engagement for our services.Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused onthe subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on thesubject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participatingin ongoing continuing education.Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have receivedprofessional accreditation in the form of a registered or certified professional engineer’s license or a registered or certifiedprofessional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.We are independent petroleum engineers with respect to Diamondback. Neither we nor any of our employees have anyfinancial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on ourestimates of reserves for the properties which were reviewed.The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists andengineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for theevaluation of the reserves information discussed in this report, are included as an attachment to this letter.Terms of UsageThe results of our third party study, presented in report form herein, were prepared in accordance with the disclosurerequirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC byDiamondback.Diamondback makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore,Diamondback has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequentlyfiled Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements onForm S-3 of Diamondback of the referencesRYDER SCOTT COMPANY PETROLEUM CONSULTANTSto our name as well as to the references to our third party report for Diamondback, which appears in the December 31, 2017annual report on Form 10-K of Diamondback. Our written consent for such use is included as a separate exhibit to the filings madewith the SEC by Diamondback.We have provided Diamondback with a digital version of the original signed copy of this report letter. In the event there areany differences between the digital version included in filings made by Diamondback and the original signed report letter, theoriginal signed report letter shall control and supersede the digital version.The data and work papers used in the preparation of this report are available for examination by authorized parties in ouroffices. Please contact us if we can be of further service.Very truly yours,RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580\s\ Val Rick RobinsonVal Rick Robinson, P.E.TBPE License No. 105137Managing Senior Vice President[SEAL]VRR (DPR)/plRYDER SCOTT COMPANY PETROLEUM CONSULTANTSProfessional Qualifications of Primary Technical EngineerThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineersfrom Ryder Scott Company, L.P. Mr. Val Rick Robinson was the primary technical person responsible for the estimate of thereserves, future production and income presented herein.Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice Presidentresponsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studiesworldwide. Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil Corporation. Formore information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder Scott Companywebsite at www.ryderscott.com.Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is alicensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineersrequires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics,which Mr. Robinson fulfills. As part of his 2017 continuing education hours, Mr. Robinson attended 28 hours of formalized trainingincluding the 2017 RSC Reserves Conference and various professional society presentations covering such topics as thedefinitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of FederalRegulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, theSPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productivebasins of North America, computer software, and professional ethics.Based on his educational background, professional training and more than 14 years of practical experience in the estimation andevaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth inArticle III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by theSociety of Petroleum Engineers as of February 19, 2007.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES DEFINITIONSPage 3RYDER SCOTT COMPANY PETROLEUM CONSULTANTSRYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES DEFINITIONSAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)PREAMBLEOn January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oiland Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 ofRegulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifiesIndustry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to RegulationS-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for allfilings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for thecomplete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italicsherein).Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31,2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gasreserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gasresources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unlesssuch information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.Reserves estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change.Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include allmethods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples ofsuch methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use ofmiscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleumtechnology continues to evolve.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSReserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulationsare considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction methodapplied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseammethane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventionalaccumulations may require specialized extraction technology and/or significant processing prior to sale.Reserves do not include quantities of petroleum being held in inventory.Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum fromdifferent reserves categories.RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, orthere must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production,installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement theproject.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults untilthose reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that areclearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, ornegative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscoveredaccumulations).PROVED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscienceand engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, fromknown reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time atwhich contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless ofwhether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced or the operator must be reasonably certain that it will commence the project within a reasonable time.(i) The area of the reservoir considered as proved includes:(A) The area identified by drilling and limited by fluid contacts, if any, and(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with itand to contain economically producible oil or gas on the basis of available geoscience and engineering data.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPROVED RESERVES (SEC DEFINITIONS) CONTINUED(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technologyestablishes a lower contact with reasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential existsfor an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only ifgeoscience, engineering, or performance data and reliable technology establish the higher contact with reasonablecertainty.(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but notlimited to, fluid injection) are included in the proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in thereservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or otherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on which theproject or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmentalentities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to bedetermined. The price shall be the average price during the 12-month period prior to the ending date of the period coveredby the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month withinsuch period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)andPETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)Sponsored and Approved by:SOCIETY OF PETROLEUM ENGINEERS (SPE)WORLD PETROLEUM COUNCIL (WPC)AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)Reserves status categories define the development and producing status of wells and reservoirs. Reference should bemade to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the followingreserves status definitions are based on excerpts from the original documents (direct passages excerpted from theaforementioned SEC and SPE-PRMS documents are denoted in italics herein).DEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:Developed oil and gas reserves are reserves of any category that can be expected to be recovered:(i) Through existing wells with existing equipment and operating methods or in which the cost of the 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 if theextraction is by means not involving a well.Developed Producing (SPE-PRMS Definitions)While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.Developed Producing ReservesDeveloped Producing Reserves are expected to be recovered from completion intervals that are open and producing at thetime of the estimate.Improved recovery reserves are considered producing only after the improved recovery project is in operation.Developed Non-ProducingDeveloped Non-Producing Reserves include shut-in and behind-pipe reserves.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSShut-InShut-in Reserves are expected to be recovered from:(1)completion intervals which are open at the time of the estimate, but which have not started producing;(2)wells which were shut-in for market conditions or pipeline connections; or(3)wells not capable of production for mechanical reasons.Behind-PipeBehind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completionwork or future re-completion prior to start of production.In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a newwell.UNDEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves asfollows:Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that arereasonably 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 alonger time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which anapplication of fluid injection or other improved recovery technique is contemplated, unless such techniques havebeen 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 establishing reasonable certainty.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSExhibit 99.1VIPER ENERGY PARTNERS, LPEstimatedFuture Reserves and IncomeAttributable to CertainRoyalty InterestsSEC ParametersAs ofDecember 31, 2017\s\ Val Rick RobinsonVal Rick Robinson, P.E.TBPE License No. 105137Managing Senior Vice President[SEAL]RYDER SCOTT COMPANY, L.P.TBPE Firm License No. F-1580RYDER SCOTT COMPANY PETROLEUM CONSULTANTSJanuary 18, 2018Viper Energy Partners, LP500 West Texas, Suite 1210Midland, Texas 79701Gentlemen:At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, futureproduction, and income attributable to certain royalty interests of Viper Energy Partners, LP (Viper), a subsidiary of DiamondbackEnergy, Inc. (Diamondback), as of December 31, 2017. The subject properties are located in the state of Texas. The reserves andincome data were estimated based on the definitions and disclosure guidelines of the United States Securities and ExchangeCommission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rulereleased January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 16, 2018 andpresented herein, was prepared for public disclosure in Viper’s filings made with the SEC in accordance with the disclosurerequirements set forth in the SEC regulations.The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100percent of the total net proved gas reserves of Viper as of December 31, 2017.The estimated reserves and future net income amounts presented in this report, as of December 31, 2017 are related tohydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the un-weighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required bythe SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes ofreserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantitiespresented in this report. The results of this study are summarized as follows.SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258SEC PARAMETERSEstimated Net Reserves and Income DataCertain Royalty Interests ofViper Energy Partners, LPAs of December 31, 2017 Proved Developed Total Producing Undeveloped ProvedNet Remaining Reserves Oil/Condensate – MBbl 18,788 7,097 25,885Plant Products – MBbl 4,536 1,759 6,295Gas – MMCF 29,256 7,139 36,395MBOE 28,200 10,046 38,246 Income Data ($M) Future Gross Revenue $1,004,913 $368,717 $1,373,630Deductions 38,220 15,091 53,311Future Net Income (FNI) $966,693 $353,626 $1,320,319 Discounted FNI @ 10% $456,837 $171,829 $628,666Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an“as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which thegas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas isconverted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousandsbarrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars($M).The estimates of the reserves, future production, and income attributable to properties in this report were prepared using theeconomic software package ARIESTM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. Theprogram was used solely at the request of Diamondback. Ryder Scott has found this program to be generally acceptable, but notesthat certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties beingsummarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of thesame properties, also due to rounding. The rounding differences are not material.The future gross revenue is after the deduction of production taxes. The deductions incorporate ad valorem taxes only. Thefuture net income is before the deduction of state and federal income taxes and general administrative overhead, and has not beenadjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.Liquid hydrocarbon reserves account for approximately 95 percent and gas reserves account for the remaining 5 percent oftotal future gross revenue from proved reserves.The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compoundedmonthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results areshown in summary form as follows.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS Discounted Future Net Income ($M) As of December 31, 2017Discount Rate Total Percent Proved 5 $834,824 15 $515,654 20 $443,507 30 $355,098 The results shown above are presented for your information and should not be construed as our estimate of fair marketvalue.Reserves Included in This ReportThe proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’sRegulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum ReservesDefinitions” is included as an attachment to this report.The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves StatusDefinitions and Guidelines” in this report.No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. Theproved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. At Viper’s request, this report addresses only theproved reserves attributable to the properties evaluated herein.Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, canbe estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves includedherein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when basedon deterministic methods, as a “high degree of confidence that the quantities will be recovered.”Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR)with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates ofproved reservesRYDER SCOTT COMPANY PETROLEUM CONSULTANTSmay be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities,and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.Diamondback’s operations may be subject to various levels of governmental controls and regulations. These controls andregulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to producehydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxesand levies including income tax and are subject to change from time to time. Such changes in governmental regulations andpolicies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differsignificantly from the estimated quantities.The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Viper ownsan interest; however, we have not made any field examination of the properties. No consideration was given in this report topotential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages,if any, caused by past operating practices.Estimates of ReservesThe estimation of reserves involves two distinct determinations. The first determination results in the estimation of thequantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with thoseestimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generallyaccepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-basedmethods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by thereserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method orcombination of methods which in their professional judgment is most appropriate given the nature and amount of reliablegeoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics ofthe reservoir being evaluated and the stage of development or producing maturity of the property.In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this datamay indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range inthe quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of thereserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discreteincremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is thecategorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimatedquantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actuallyrecovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reservesthat are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to berecovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered thanprobable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plusprobable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions asnoted above.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSEstimates of reserves quantities and their associated reserve categories may be revised in the future as additionalgeoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reservecategories may also be revised due to other factors such as changes in economic conditions, results of future operations, effectsof regulation by governmental agencies or geopolitical or economic risks as previously noted herein.The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combinationof both methods. Approximately 90 percent of the proved producing reserves attributable to producing wells were estimated byperformance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilizedextrapolations of historical production and pressure data available through December 2017 in those cases where such data wereconsidered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Diamondback and were consideredsufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves were estimated by analogy, or acombination of performance and analogy methods. The analogy method was used where there were inadequate historicalperformance data to establish a definitive trend and where the use of production performance data as a basis for the reserveestimates was considered to be inappropriate.All proved undeveloped reserves included herein were estimated by the analogy method.To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider manyfactors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical andengineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, andforecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipatedto be economically producible from a given date forward based on existing economic conditions including the prices and costs atwhich economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future pricesreceived for the sale of production and the operating costs and other costs relating to such production may increase or decreasefrom those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted fromconsideration in making this evaluation.Diamondback has informed us that they have furnished us all of the material accounts, records, geological and engineeringdata, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, wehave relied upon data furnished by Diamondback with respect to property interests owned, production and well tests fromexamined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, advalorem and production taxes, recompletion and development costs, development plans, product prices based on the SECregulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, andpressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted anindependent verification of the data furnished by Diamondback. We consider the factual data used in this report appropriate andsufficient for the purpose of preparing the estimates of reserves and future net revenues herein.In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for thepurpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare theestimates of reserves herein. The proved reserves included herein were determined in conformance with the United StatesSecurities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references toRegulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reservespresented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSFuture Production RatesFor wells currently on production, our forecasts of future production rates are based on historical performance data. If noproduction decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailmentwhere appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion ofthe reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.Test data and other related information were used to estimate the anticipated initial production rates for those wells orlocations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipateddate furnished by Diamondback. Wells or locations that are not currently producing may start producing earlier or later thananticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors mayinclude delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/orconstraints set by regulatory bodies.The future production rates from wells currently on production or wells or locations that are not currently producing may bemore or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related tosurface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/orallowables or other constraints set by regulatory bodies.Hydrocarbon PricesThe hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-monthperiod prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbonproducts sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments,were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month un-weightedarithmetic average as previously described.As noted above, Diamondback furnished us with the average prices in effect on December 31, 2017. These initial SEChydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to thegeographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials asdescribed herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area includedin the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.The product prices which were actually used to determine the future gross revenue for each property reflect adjustments tothe benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referredto herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Diamondback and wereaccepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independentverification of the data used by Diamondback to determine these differentials.In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred toherein as the “average realized prices.” The average realized prices shown in the table below were determined from the total futuregross revenue before production taxes and theRYDER SCOTT COMPANY PETROLEUM CONSULTANTStotal net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of thegeographic areas included in the report.GeographicAreaProductPriceReferenceAverageBenchmarkPricesAverage ProvedRealizedPricesNorth America United StatesOil/CondensateWTI Cushing$51.34/Bbl$48.21/BblNGLsPropane, Mt. Belvieu$31.82/Bbl$19.15/BblGasHenry Hub$2.98/MMBTU$2.13/MCFThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual propertyevaluations.CostsAs a holder of royalty interests only, Viper bears none of the operating or development costs associated with the underlyingproperties of this report. Nevertheless, the undeveloped reserves in this report have been incorporated herein in accordance withDiamondback's plans to develop these reserves as of December 31, 2017. The implementation of Diamondback's developmentplans as presented to us and incorporated herein is subject to the approval process adopted by Diamondback's management. Asthe result of our inquiries during the course of preparing this report, Diamondback has informed us that the development activitiesincluded herein have been subjected to and received the internal approvals required by Diamondback’s management at theappropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities maystill be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrativeapprovals external to Diamondback. Additionally, Diamondback has informed us that they are not aware of any legal, regulatory, orpolitical obstacles that would significantly alter their plans. While these plans could change from those under existing economicconditions as of December 31, 2017, such changes were, in accordance with rules adopted by the SEC, omitted fromconsideration in making this evaluation.Standards of Independence and Professional QualificationRyder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting servicesthroughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; andCalgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firmand the large number of clients for which we provide services, no single client or job represents a material portion of our annualrevenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separateand independent from the operating and investment decision-making process of our clients. This allows us to bring the highest levelof independence and objectivity to each engagement for our services.Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused onthe subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on thesubject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participatingin ongoing continuing education.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPrior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have receivedprofessional accreditation in the form of a registered or certified professional engineer’s license or a registered or certifiedprofessional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.We are independent petroleum engineers with respect to Viper and Diamondback. Neither we nor any of our employeeshave any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingenton our estimates of reserves for the properties which were reviewed.The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists andengineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for theevaluation of the reserves information discussed in this report, are included as an attachment to this letter.Terms of UsageThe results of our third party study, presented in report form herein, were prepared in accordance with the disclosurerequirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Viper.Viper makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Viper has certainregistration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K isincorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 ofViper of the references to our name as well as to the references to our third party report for Viper, which appears in the December31, 2017 annual report on Form 10-K of Viper. Our written consent for such use is included as a separate exhibit to the filings madewith the SEC by Viper.We have provided Viper with a digital version of the original signed copy of this report letter. In the event there are anydifferences between the digital version included in filings made by Viper and the original signed report letter, the original signedreport letter shall control and supersede the digital version.The data and work papers used in the preparation of this report are available for examination by authorized parties in ouroffices. Please contact us if we can be of further service.Very truly yours,RYDER SCOTT COMPANY, L.P.TBPE Firm Registration No. F-1580\s\ Val Rick RobinsonVal Rick Robinson, P.E.TBPE License No. 105137Managing Senior Vice President[SEAL]VRR (DPR)/plRYDER SCOTT COMPANY PETROLEUM CONSULTANTSProfessional Qualifications of Primary Technical EngineerThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineersfrom Ryder Scott Company, L.P. Mr. Val Rick Robinson was the primary technical person responsible for the estimate of thereserves, future production and income presented herein.Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice Presidentresponsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studiesworldwide. Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil Corporation. Formore information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder Scott Companywebsite at www.ryderscott.com.Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is alicensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineersrequires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics,which Mr. Robinson fulfills. As part of his 2017 continuing education hours, Mr. Robinson attended 28 hours of formalized trainingincluding the 2017 RSC Reserves Conference and various professional society presentations covering such topics as thedefinitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of FederalRegulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, theSPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productivebasins of North America, computer software, and professional ethics.Based on his educational background, professional training and more than 14 years of practical experience in the estimation andevaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth inArticle III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by theSociety of Petroleum Engineers as of February 19, 2007.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES DEFINITIONSAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)PREAMBLEOn January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oiland Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 ofRegulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifiesIndustry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to RegulationS-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for allfilings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for thecomplete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italicsherein).Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve anassessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than theestimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliablegeologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree ofuncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unprovedreserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possiblereserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31,2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gasreserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gasresources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unlesssuch information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.Reserves estimates will generally be revised only as additional geologic or engineering data become available or aseconomic conditions change.Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include allmethods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples ofsuch methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use ofmiscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleumtechnology continues to evolve.Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulationsare considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction methodapplied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseammethane (CBM/CSM), basin-RYDER SCOTT COMPANY PETROLEUM CONSULTANTScentered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may requirespecialized extraction technology and/or significant processing prior to sale.Reserves do not include quantities of petroleum being held in inventory.Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum fromdifferent reserves categories.RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economicallyproducible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, orthere must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production,installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement theproject.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults untilthose reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that areclearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, ornegative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscoveredaccumulations).PROVED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscienceand engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, fromknown reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time atwhich contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless ofwhether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must havecommenced or the operator must be reasonably certain that it will commence the project within a reasonable time.(i) The area of the reservoir considered as proved includes:(A) The area identified by drilling and limited by fluid contacts, if any, and(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with itand to contain economically producible oil or gas on the basis of available geoscience and engineering data.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPROVED RESERVES (SEC DEFINITIONS) CONTINUED(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technologyestablishes a lower contact with reasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential existsfor an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only ifgeoscience, engineering, or performance data and reliable technology establish the higher contact with reasonablecertainty.(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but notlimited to, fluid injection) are included in the proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in thereservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or otherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on which theproject or program was based; and(B) The project has been approved for development by all necessary parties and entities, including governmentalentities.(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to bedetermined. The price shall be the average price during the 12-month period prior to the ending date of the period coveredby the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month withinsuch period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSPETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESAs Adapted From:RULE 4-10(a) of REGULATION S-X PART 210UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)andPETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)Sponsored and Approved by:SOCIETY OF PETROLEUM ENGINEERS (SPE)WORLD PETROLEUM COUNCIL (WPC)AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINESPage 2Reserves status categories define the development and producing status of wells and reservoirs. Reference should bemade to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the followingreserves status definitions are based on excerpts from the original documents (direct passages excerpted from theaforementioned SEC and SPE-PRMS documents are denoted in italics herein).DEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:Developed oil and gas reserves are reserves of any category that can be expected to be recovered:(i) Through existing wells with existing equipment and operating methods or in which the cost of the 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 if theextraction is by means not involving a well.Developed Producing (SPE-PRMS Definitions)While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.Developed Producing ReservesDeveloped Producing Reserves are expected to be recovered from completion intervals that are open and producing at thetime of the estimate.Improved recovery reserves are considered producing only after the improved recovery project is in operation.RYDER SCOTT COMPANY PETROLEUM CONSULTANTSDeveloped Non-ProducingDeveloped Non-Producing Reserves include shut-in and behind-pipe reserves.Shut-InShut-in Reserves are expected to be recovered from:(1)completion intervals which are open at the time of the estimate, but which have not started producing;(2)wells which were shut-in for market conditions or pipeline connections; or(3)wells not capable of production for mechanical reasons.Behind-PipeBehind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completionwork or future re-completion prior to start of production.In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a newwell.UNDEVELOPED RESERVES (SEC DEFINITIONS)Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves asfollows:Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that arereasonably 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 alonger time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which anapplication of fluid injection or other improved recovery technique is contemplated, unless such techniques havebeen 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 establishing reasonable certainty.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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