Diamondback Energy
Annual Report 2015

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, 2015 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, or a smaller reporting company. See the definitions of “largeaccelerated 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 ¨Indicate 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, 2015 was approximately $4,709,835,344.As of February 16, 2016, 71,397,041 shares of the registrant’s common stock were outstanding.DOCUMENTS INCORPORATED BY REFERENCEPortions of Diamondback Energy, Inc.’s Proxy Statement for the 2016 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, INCFORM 10-KFOR THE YEAR ENDED DECEMBER 31, 2015TABLE 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 Factors20Item 1B. Unresolved Staff Comments43Item 3. Legal Proceedings43Item 4. Mine Safety Disclosures43 PART IIItem 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities44Item 6. Selected Financial Data45Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations48Item 7A. Quantitative and Qualitative Disclosures about Market Risk67Item 8. Financial Statements and Supplementary Data68Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure68Item 9A. Controls and Procedures68Item 9B. Other Information71 PART IIIItem 10. Directors, Executive Officers and Corporate Governance71Item 11. Executive Compensation71Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters71Item 13. Certain Relationships and Related Transactions, and Director Independence71Item 14. Principal Accountant Fees and Services71 PART IVItem 15. Exhibits and Financial Statement Schedules72SignaturesS-1Index to Consolidated Financial Statements Exhibit IndexE-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.Completion The 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.Condensate Liquid hydrocarbons associated with the production that is primarily natural gas.Crude oil Liquid 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 costs Capital 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 drilling A 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 per day.Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from theextracted resources.MMBtu Million British Thermal Units.MMcfMillion cubic feet of natural gas.iiNet acres or net wells The sum of the fractional working interest owned in gross acres.Net revenue interest An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overridinginterests.Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.Operator The individual or company responsible for the exploration and/or production of an oil or natural gas well orlease.Play A 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 abandonment Refers 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.Prospect A specific geographic area which, based on supporting geological, geophysical or other data and alsopreliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential 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.Spacing The 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 interest An 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.Company Diamondback 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.Indenture The indenture relating to the Senior Notes, dated as of September 18, 2013, among the Company, the subsidiary guarantorsparty thereto and Wells Fargo, as the trustee, as supplemented.MuskieMuskie Proppant LLC.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.Senior NotesThe Company’s 7.625% senior unsecured notes due 2021 in the aggregate principal amount of $450 million.ViperViper Energy Partners L.P.Viper LTIP Viper Energy Partners L.P. Long Term Incentive Plan.Viper Offering The 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 of 1933, as amended, or the Securities Act, and Section 21E of the SecuritiesExchange Act of 1934, or the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyondour 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 management are 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 statements contain such identifying words. In particular, the factors discussed in this Annual Report onForm 10–K, including under Part I, Item 1A. “Risk Factors” in this report, could affect our actual results and cause our actual results to differ materially fromexpectations, estimates or assumptions expressed, forecasted or implied 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, 2015, our total net acreageposition in the Permian Basin was approximately 84,683 net acres. In addition, we, through our subsidiary Viper Energy Partners LP, or Viper, own mineralinterests underlying approximately 46,562 gross (17,060 net) acres primarily in Midland County, Texas in the Permian Basin. Approximately 60% of thesenet acres are operated by us. On June 23, 2014, Viper completed its initial public offering of 5,750,000 common units representing limited partner interestsand, on September 19, 2014 Viper completed a follow-on underwritten public offering of 3,500,000 common units. The common units sold to the publicrepresent, in the aggregate, an approximate 12% limited partner interest in Viper. We own Viper Energy Partners GP LLC, the general partner of Viper, whichwe refer to as the general partner, and the remaining approximate 88% limited partner interest in Viper.Our activities are primarily focused on the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations, which we refer to collectively as theWolfberry play. The Wolfberry play is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensiveproduction history, long-lived reserves and high drilling success rates. The Wolfberry play is a modification and extension of the Spraberry play, the majorityof which is designated in the Spraberry Trend Area field. According to the U.S. Energy Information Administration, the Spraberry Trend Area ranked as thesecond largest oilfield in the United States, based on 2009 reserves.As of December 31, 2015, our estimated proved oil and natural gas reserves were 156,900 MBOE (which includes estimated reserves of 26,345MBOE 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 59% are classified as proved developed producing. Proved undeveloped, or PUD, reservesincluded in this estimate are from 107 gross (86 net) horizontal well locations and 3 gross (2 net) vertical well locations on 40-acre spacing in which we havea working interest and 16 horizontal wells in which we own only a mineral interest through our subsidiary, Viper. As of December 31, 2015, our estimatedproved reserves were approximately 67% oil, 17% natural gas liquids and 16% natural gas.Based on our evaluation of applicable geologic and engineering data, we currently have approximately 1,500 gross (960 net) identified economicpotential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $40.00 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 2015 has continued in 2016, with the posted price of WTI dropping to as lowas $26.68 in January 2016. Nevertheless, we believe we remain well-positioned in this environment. During 2015, we again demonstrated our operationalfocus on achieving best-in-class execution, low-cost operations and a conservative balance sheet as we continued to reduce drilling days, well costs andoperating expenses while maintaining what we believe to be a peer leading leverage ratio. We intend to continue our operational focus in 2016, emphasizingfinancial discipline over growth. We currently intend to release one of our three horizontal drilling rigs in March 2016. We will continue monitoring theongoing commodity price environment and expect to retain the financial flexibility to adjust our drilling and completion plans in response to marketconditions. We are prepared to decelerate our drilling program if commodity prices deteriorate and accelerate our drilling program if commodity pricesimprove. We have the option to release a second rig in the second quarter of 2016. See Item 7. “Management’s Discussion and Analysis of FinancialCondition 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 theWolfberry play through horizontal drilling and believe that there are opportunities to target additional intervals in the Wolfberry play withhorizontal wells. Our initial horizontal focus had been on the Wolfcamp B interval, but our recent focus has primarily been on the LowerSpraberry interval. We have also begun to derisk the Wolfcamp A and Middle Spraberry on some of our properties. Our first two horizontal wellswere completed in 2012 and had lateral lengths of less than 4,000 feet. As of December 31, 2015, we had drilled 188 horizontal wells as operatorand had participated in 25 additional horizontal wells as a non-operator, including two in which we own only a minor wellbore interest. We alsoacquired interest in 11 horizontal wells on properties we purchased. Of these 224 total horizontal wells, 184 had been completed and were onproduction. Of the 184 horizontal wells on production, 112 are in the Wolfcamp B interval, 23 are in the Clearfork zone, 58 are in the Spraberryzone, and three are in the Cline zone. These wells have lateral lengths ranging from approximately 4,000 feet to 11,000 feet. In 2016, we expectthat our average lateral lengths will be in the range of 7,000 feet to 8,000 feet, although the actual length will vary depending on the layout ofour acreage and other factors. As technology improves, we expect that our average lateral lengths will increase, resulting in higher per wellrecoveries and lower development costs per BOE. During the year ended December 31, 2015, we were able to drill our horizontal wells withapproximately 7,500 foot lateral lengths to total depth, or TD, in an average of 13.9 days and we drilled an approximately 10,000 foot lateralwell in 14.2 days. Further advances in drilling and completion technology may result in economic development of zones that are not currentlyviable.•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 96% 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 80% 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 31,2015, we acquired approximately 16,941 gross (12,672 net) leasehold acres primarily in Howard, Martin, Andrews and Midland counties. Weintend to continue to pursue acquisitions that meet our strategic and financial targets.•Maintain financial flexibility. We seek to maintain a conservative financial position. In connection with our fall 2015 redetermination, theagent lender under our revolving credit agreement recommended a borrowing base of $750.0 million. We elected a commitment amount of$500.0 million, of which $489.0 million was available for2borrowing as of December 31, 2015. As of December 31, 2015, Viper had $34.5 million in outstanding borrowings, and $165.5 millionavailable 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 Wolfberryplay. Our production for the year ended December 31, 2015 was approximately 75% oil, 14% natural gas liquids and 11% natural gas. As ofDecember 31, 2015, our estimated net proved reserves were comprised of approximately 67% oil and 17% natural gas liquids.•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 $40.00 per Bbl WTI, we currently have approximately 1,500 gross (960 net) identified economic potential horizontal drillinglocations on our acreage based on our our evaluation of applicable geologic and engineering data. These gross identified economic potentialhorizontal locations have an average lateral length of approximately 8,375 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 1,500 locations, 840 are in theWolfcamp B horizon or the Lower Spraberry horizon, with the remaining locations in either the Wolfcamp A, Middle Spraberry, Clearfork,Wolfcamp C or Cline horizons. Our current horizontal location count for the Wolfcamp B horizon is based on 660 foot spacing between wells inall counties except Andrews, Dawson, Upton, and northwest Martin counties where it is 880 foot spacing. For the Lower Spraberry horizon, thehorizontal location count is based on 500 foot spacing in the Spanish Trail property in Midland County and 660 foot spacing in other countiesexcept Upton, Dawson and central Andrews counties where it is based on 880 foot spacing. In the Wolfcamp A horizon, the horizontal locationcount in based on 660 foot spacing in Howard and Glasscock counties, 880 foot spacing in Midland and southwest Martin counties and 1,320foot spacing in other counties. Middle Spraberry counts are based on 880 foot spacing in Midland, Martin and northeast Andrews counties and1,320 foot spacing in other counties. The horizontal location counts for the Cline, Clearfork and Wolfcamp C horizons are based on 1,320spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. The ultimate inter-well spacing may vary fromthese distances due to different factors, which would result in a higher or lower location count. The two-stream gross estimated ultimaterecoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scott as of December 31, 2015, range from 392 MBOE perwell, consisting of 280 MBbls of oil and 673 MMcf of natural gas, to 1,318 MBOE per well, consisting of 1,035 MBbls of oil and 1,698 MMcfof natural gas, for wells ranging in lateral length from approximately 5,000 feet to approximately 10,000 feet, in intervals including theClearfork, Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B. Ryder Scott has estimated gross EURs of 635 MBOE for ourWolfcamp B wells in Midland County and 990 MBOE for our Lower Spraberry wells in Midland County, which constitute 54% of ourremaining PUD horizontal wells, in each case based on 7,500 foot lateral lengths. In addition, we have approximately 698 square miles ofproprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insightinto future development activity, including additional horizontal drilling opportunities and strategic leasehold 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 as well as horizontal well reservoir and geologic expertise, which is of strategic importance as we expand ourhorizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, LaredoPetroleum Holdings, Inc. and Burlington Resources.•Favorable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the oldesthydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that thegeological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with less operational risks, inthe Permian Basin as compared to emerging hydrocarbon basins.•High degree of operational control. We are the operator of approximately 96% of our Permian Basin acreage. This operating control allows usto better execute on our strategies of enhancing returns through operational and3cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completionmethodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability toincrease or decrease our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain dataneeded for efficient exploration of horizontal prospects.Our PropertiesLocation and LandOur total net acreage position in the Permian Basin was approximately 84,683 net acres at December 31, 2015. We are the operator of approximately96% of this Permian Basin acreage. In addition, we, through our subsidiary Viper, own mineral interests underlying approximately 46,562 gross (17,060 net)acres primarily in Midland County, Texas in the Permian Basin. Approximately 60% of these net acres are operated by us. Since our initial acquisition in thePermian Basin through December 31, 2015, we drilled or participated in the drilling of 490 gross (407 net) wells on our leasehold acreage in this area,primarily targeting the Wolfberry play. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered oneof 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, Wolfcamp, Cline, Strawn and Atokaformations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventuallyrecognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Developmentin the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil pricesand 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, 2015, we held working interests in 918 gross (732) net producing wells.GeologyThe Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita fold belt. It is one of thelargest sedimentary basins in the U.S., and has oil and gas production from several reservoirs from Permian through Ordovician in age. The term “Wolfberry”was coined initially to indicate commingled production from the Permian Spraberry, Dean and Wolfcamp formations. In this report, we refer to the Clearfork,Spraberry, Wolfcamp, Strawn and Atoka formations collectively as the Wolfberry play. The Wolfberry play of the Midland Basin lies in the area where thehistorically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp play.The Spraberry was deposited as turbidites in a deep water submarine fan environment, while the Wolfcamp reservoirs consist of debris-flow andgrain-flow sediments, which were also deposited in a submarine fan setting. The best carbonate reservoirs within the Wolfcamp are generally found inproximity to the Central Basin Platform, while the shale reservoirs within the Wolfcamp thicken basinward away from the Central Basin Platform. Both theSpraberry and Wolfcamp contain organic-rich mudstones and shales which, when buried to sufficient depth for maturation, became the source of thehydrocarbons found both within the shales themselves and in the more conventional clastic and carbonate reservoirs between the shales. The Wolfberry is anunconventional “basin-centered oil” resource play, in the sense that there is no regional downdip oil/water contact.4 We have successfully developed several shale intervals within the Clearfork, Spraberry and Wolfcamp formations since we began horizontal drillingin 2012. The shales exhibit micro-darcy permeabilities which result in relatively small drainage areas and recovery factors, so relatively small inter-wellspacing is necessary.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 698 square miles of 3-D data, and we are in the process of acquiring an additional 19 square miles. This data will continueto be utilized in the development of our horizontal drilling activities and to identify and avoid potential geohazards (e.g., faults and lithologies that aredifficult to drill).Production StatusDuring the year ended December 31, 2015, net production from our Permian Basin acreage was 12,080,631 BOE, or an average of 33,098 BOE/d, ofwhich approximately 75% was oil, 14% was natural gas liquids and 11% 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.Future ActivityDuring 2016, we expect to drill an estimated 30 to 70 gross (25 to 58 net) horizontal wells on our acreage. We currently estimate that our capitalexpenditures for 2016 will be between $250.0 million and $375.0 million, consisting of $210.0 million to $315.0 million for horizontal drilling andcompletions, $25.0 million to $35.0 million for infrastructure and $15.0 million to $25.0 million for non-operated activity and other expenditures, butexcluding the cost of any leasehold and mineral rights acquisitions. During the year ended December 31, 2015, we drilled 64 gross (54 net) and completed 65gross (54 net) horizontal wells. We drilled and completed four gross (three net) vertical wells and participated in the drilling of 15 gross (six net) non-operated wells in the Permian Basin. During the year ended December 31, 2015, our capital expenditures for drilling, completing and equipping wells was$358.0 million. We spent $27.0 million for oil and gas infrastructure and $34.0 million for non-operated properties. We spent an additional $481.4 millionfor leasehold and mineral rights acquisitions.We intend to release one of our three horizontal drilling rigs in March 2016. We will continue monitoring the ongoing commodity priceenvironment and expect to retain the financial flexibility to adjust our drilling and completion plans as conditions warrant. We are prepared to decelerate ourdrilling program if commodity prices deteriorate and accelerate our drilling program if commodity prices improve. We have the option to release a second rigin the second quarter of 2016 and continue to operate one rig.Oil and Natural Gas DataProved ReservesEvaluation and Review of ReservesOur historical reserve estimates as of December 31, 2015, 2014 and 2013 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.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, 2015 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 the5definitions established under SEC rules. 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-based methods, (2) volumetric-basedmethods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities ofreserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 90% ofthe proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not belimited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 10% of the provedproducing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there wereinadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimateswas considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated 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 Vice President–Reservoir Engineeringis primarily responsible for overseeing the preparation of all of our reserve estimates. Our Vice President–Reservoir Engineering is a petroleum engineer withover 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 24 years of industry experience per person. Ourtechnical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operatingand 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 Vice President–Reservoir Engineering or under his direct supervision;•review by our Vice President–Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review ofall significant reserve changes and all new proved undeveloped reserves additions;•direct reporting responsibilities by our 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, 2015, 2014 and 2013 (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, 2015 2014 2013Estimated proved developed reserves: Oil (Bbls) 60,569,398 43,885,835 19,789,965Natural gas (Mcf) 96,871,109 68,264,113 31,428,756Natural gas liquids (Bbls) 15,418,353 11,221,428 4,973,493Total (BOE) 92,132,936 66,484,615 30,001,584Estimated proved undeveloped reserves: Oil (Bbls) 45,409,313 31,803,754 22,810,887Natural gas (Mcf) 52,631,635 43,341,147 30,250,740Natural gas liquids (Bbls) 10,585,791 7,320,504 5,732,231Total (BOE) 64,767,043 46,347,783 33,584,908Estimated Net Proved Reserves: Oil (Bbls) 105,978,711 75,689,589 42,600,852Natural gas (Mcf) 149,502,744 111,605,260 61,679,496Natural gas liquids (Bbls) 26,004,144 18,541,932 10,705,724Total (BOE)(1) 156,899,979 112,832,398 63,586,492Percent proved developed 58.7% 58.9% 47.2%(1)Estimates of reserves as of December 31, 2015, 2014 and 2013 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, 2015, 2014 and2013, 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, 2015, our proved undeveloped reserves totaled 45,409 MBbls of oil, 52,632 MMcf of natural gas and 10,586 MBbls of naturalgas liquids, for a total of 64,767 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 2015: (MBOE)Beginning proved undeveloped reserves at December 31, 201446,348Undeveloped reserves transferred to developed(13,680)Revisions(12,656)Extensions and discoveries44,755Ending proved undeveloped reserves at December 31, 201564,767The increase in proved undeveloped reserves was primarily attributable to extensions of 44,755 MBOE from continued successful horizontaldevelopment of the Lower Spraberry and Wolfcamp B horizons and initial development of the Wolfcamp A and Middle Spraberry intervals on our acreage.Approximately 63% of the extensions are classified as proved undeveloped. Approximately 20% of the proved undeveloped reserve extensions areassociated with well locations that are more than one offset away from existing producing wells. All of these locations are within 1,700 feet of producingwells. Partially offsetting the increase in proved undeveloped reserves were decreases due to technical revisions. Downward revisions of approximately12,656 MBOE were a result of reclassifying 14,619 MBOE of reserves attributable to 80 vertical wells and 22 horizontal wells in which we have a workinginterest and 22 vertical wells in which we have only a mineral interest held through Viper due to lower product prices. Vertical well reclassificationsaccounted for 8,607 MBOE of the total of 14,619 MBOE. These vertical locations were also unlikely to be developed within the five-year period required bythe applicable SEC rules (even if commodity prices recover) due to our focus on horizontal well development. As of December 31, 2015, horizontal wellsrepresented approximately 99.7% of our PUD locations.Costs incurred relating to the development of PUDs were approximately $42.7 million during 2015. Estimated future development costs relating tothe development of PUDs are projected to be approximately $134.0 million in 2016, $174.0 million in 2017, $136.0 million in 2018 and $36.0 million in2019. 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.Our December 31, 2015 proved reserves were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-themonth price for the period January through December 2015 of $50.28 per Bbl and $2.58 per MMBtu. Holding production and development costs constant, ifSEC pricing had been the December 31, 2015 pricing of $37.04 per Bbl and $2.34 per MMbtu, this would have resulted in a decrease of 20,005 MBOE of ourestimated PUD reserves.As of December 31, 2015, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initiallyrecorded.As of December 31, 2015, less than 1.0% 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: Historical Year Ended December 31, 2015 2014 2013Production Data: Oil (Bbls)9,081,135 5,381,576 2,022,749Natural gas (Mcf)7,931,237 4,345,916 1,730,497Natural gas liquids (Bbls)1,677,623 1,001,991 361,079Combined volumes (BOE)12,080,631 7,107,886 2,672,244Daily combined volumes (BOE/d)33,098 19,474 7,321 Average Prices: Oil (per Bbl)$44.68 $83.48 $93.32Natural gas (per Mcf)2.47 4.15 3.61Natural gas liquids (per Bbl)12.77 28.39 36.00Combined (per BOE)36.98 69.74 77.84Oil, hedged($ per Bbl)(1)60.63 85.42 89.75Average price, hedged($ per BOE)(1)48.97 71.21 75.14 Average Costs per BOE: Lease operating expense$6.84 $7.79 $7.92Production and ad valorem taxes2.73 4.59 4.83Gathering and transportation expense0.50 0.46 0.34General and administrative - cash component1.11 1.61 3.47Total operating expense - cash11.18 14.45 16.56 General and administrative - non-cash component1.54 1.38 0.66Depreciation, depletion, and amortization18.02 23.92 24.92Interest expense3.44 4.86 3.02Total expenses23.00 30.16 28.60(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, 2015, we owned an average unweighted 80% working interest in 1,029 gross (820 net) productive wells. Through our subsidiaryViper, we own an average unweighted 19% royalty or mineral interest in 130 additional productive wells in which we do not own a working interest.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, 2015 relating to our leasehold acreage: Developed Acreage(1) Undeveloped Acreage(2) Total Acreage(3)Basin Gross(4) Net(5) Gross(4) Net(5) Gross(4) Net(5)Permian 65,119 62,763 40,150 21,920 105,269 84,683(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 22,500 gross (16,811 net) 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, 2015, 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. 2016 2017 2018 2019 2020Basin Gross Net Gross Net Gross Net Gross Net Gross NetPermian 15,305 6,007 23,312 15,142 — — — — 31 21Drilling 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, 2015 2014 2013 Gross Net Gross Net Gross NetDevelopment: Productive8 6 40 31 52 43Dry— — — — — —Exploratory: Productive71 57 53 43 31 26Dry— — — — — —Total: Productive79 63 93 74 83 69Dry— — — — — —10As of December 31, 2015, we had 44 gross (34 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, 2015, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and EnterpriseCrude Oil LLC (15%). For the year ended December 31, 2014, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company(64%); and Enterprise Crude Oil LLC (16%). For the year ended December 31, 2013, two purchasers each accounted for more than 10% of our revenue: PlainsMarketing, L.P. (37%); and Shell Trading (US) Company (37%). No other customer accounted for more than 10% of our revenue during these periods. If amajor customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could beharmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all ofour major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungibleproducts with well-established markets and numerous purchasers.On May 24, 2012, we entered into an oil purchase agreement with Shell Trading (US) Company, in which we agreed to sell specified quantities of oilto Shell Trading (US) Company upon completion of the reversal of the Magellan Longhorn pipeline and its conversion for oil shipment, which occurred onOctober 1, 2013. Our agreement with Shell Trading (US) Company has an initial term of five years from the completion date. The agreement may also beterminated by Shell Trading (US) Company by written notice to us in the event that Shell Trading (US) Company’s contract for transportation on the pipelineis terminated. Our maximum delivery obligation under this agreement is 8,000 gross barrels per day. We have a one-time right to elect to decrease thecontract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of theagreement. Shell Trading (US) Company has agreed to pay to us 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 we fail to deliver the required quantities of oil under the agreement during any three-month period following the servicecommencement date, we have agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying (i) the volume of oil thatwe failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation 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 human11resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gasproperties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energyinclude electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions,conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect 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 is transported to the purchaser by pipeline, which we anticipate will increase to approximately 90% for oil by the end of 2016.During 2015, several oil and saltwater disposal gathering systems were installed. At December 31, 2015, approximately 83% of our produced waterwas connected to saltwater disposals by pipe and approximately 67% of our oil production was sold by pipe. These initiatives reduced the cost of the waterwhich was being trucked to disposal by approximately $1.43/bbl and reduced the transportation cost of the oil being sold by truck by $0.75/bbl. We believethat these gathering systems will help us reduce our lease operating expense and improve our margins on sales in future periods. 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 from18.75% to 25.00%, resulting in a net revenue interest to us generally ranging from 81.25% to 75.00%.Seasonal Nature of BusinessGenerally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas usersutilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demandfluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in aportion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and can increase competition forequipment, supplies and personnel during the spring and summer months, which could 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 relate to our owned or operated facilities. Liability under such laws and regulations is strict (i.e., noshowing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claimsfor personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or wastehandling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and12natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and wehave 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 requirements of non-hazardous waste provisions. Moreover,the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardouswastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gasexploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effecton our capital expenditures and operating expenses.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 imposes 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. The Clean WaterAct and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands,unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriatecontainment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture orleak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. TheEPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage undergeneral permits for storm water discharges. In addition, on April 7, 2015, the EPA published a proposed rule establishing federal pre-treatment standards forwastewater discharged from onshore unconventional oil and gas extraction facilities to publicly owned treatment works, or POTW, which regulations arediscussed in more detail below under the caption “–Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater ordeveloping and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of ourfacilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwaterconditions.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 the13requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility responsecontingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OilPollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs andcertain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.Noncompliance 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.” These laws and regulations may increase the costs of compliance forsome facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance withair permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance withall applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewingpermits has the potential to delay the development of oil and natural gas projects.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. These findings by the EPA allowed the agency to proceed with the adoption andimplementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Subsequently, theEPA adopted two sets of related rules, one of which purports to regulate emissions of greenhouse gases from motor vehicles and the other of which regulatesemissions of greenhouse gases from certain large stationary sources of emissions such as power plants or industrial facilities. In response to its endangermentfinding, the EPA adopted two sets of rules regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. The motor vehicle rule,which became effective in July 2010, purports to limit emissions of greenhouse gases from motor vehicles. The EPA adopted the stationary source rule, whichwe refer to as the tailoring rule, in May 2010, and it became effective January 2011. The tailoring rule established new greenhouse gas emissions thresholdsthat determine when stationary sources must obtain permits under the PSD and Title V programs of the Clean Air Act. On June 23, 2014, in Utility AirRegulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of theirgreenhouse gas emissions. The Court ruled, however, that the EPA may require installation of best available control technology for greenhouse gas emissionsat sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memoranda providing initial guidance ongreenhouse gas permitting requirements in response to the Court’s decision in Utility Air Regulatory Group v. EPA. In its preliminary guidance, the EPAindicates it will undertake a rulemaking action to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. Inthe interim, the EPA issued a narrowly crafted “no action assurance” indicating it will exercise its enforcement discretion not to pursue enforcement of theterms and conditions relating to greenhouse gases in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. On April 30, 2015,the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued under the invalid regulations.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.The EPA has continued to adopt greenhouse gas regulations applicable to other industries, such as its August 2015 adoption of three separate, butrelated, actions to address carbon dioxide pollution from power plants, including final Carbon Pollution Standards for new, modified and reconstructedpower plants, a final Clean Power Plan to cut carbon dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean PowerPlan emission guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen States as well as industry and labor groupschallenged the14Clean Power Plan in the D.C. Circuit Court of Appeals. As a result of this continued regulatory focus, future greenhouse gas regulations of the oil and gasindustry remain a possibility. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gasesand almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development ofgreenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation atthis time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programswork by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, toacquire and surrender emission allowances corresponding with their annual emissions of greenhouse gases. The number of allowances available for purchaseis reduced each year until the overall greenhouse gas emission reduction goal is achieved. As the number of greenhouse gas emission allowances declineseach year, the cost or value of allowances is expected to escalate significantly.In December 2015, the United States joined the international community at 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, if ratified, establishes a framework for the partiesto cooperate and report actions to reduce greenhouse gas emissions.Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely affect the oil and natural gas industry. At this time, itis not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operationsconstitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulationsagainst us and could allege personal injury or property damages. While our business is not a party to this litigation, we could be named in actions makingsimilar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financialcondition.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 colder than their historicalaverages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fullyinsured. 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.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, several federal agencies have assertedregulatory authority over certain aspects of the process. For example, the EPA has recently taken the position that hydraulic fracturing with fluids containingdiesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells underthe Safe Drinking Water Act. Furthermore, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from thedefinition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to requiredisclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress.In addition, on May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulationsunder the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. The EPA plans todevelop a Notice of Proposed Rulemaking by December 2016, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both- to collect data on hydraulic fracturing chemical substances and mixtures. Also, on April 7, 2015, the EPA published a proposed rule establishing federal pre-treatment standards for wastewater discharged from onshore unconventional oil and gas extraction facilities to POTW. The EPA asserts that wastewater fromsuch facilities can be generated in large quantities and can contain constituents that may disrupt POTW operations and/or be discharged, untreated, from thePOTW to receiving waters. If adopted, the new pre-treatment rule would require unconventional oil and gas facilities to pre-treat wastewater beforetransferring it to a POTW. The public comment period ended on July 17, 2015, and the EPA is expected to publish a final rule by August 2016. The EPA isalso conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas15extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatmenttechnologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of dischargesfrom 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 rule seeks 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 will likely continue to issue, revised rules responsive to some of the requests for reconsideration. Inresponse, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. For example, inSeptember 2013 and December 2014, the EPA amended its rules to extend compliance deadlines and to clarify the NSP standards. Further, on July 31, 2015,the EPA finalized two updates to the NSP standards to address the definition of low-pressure wells and references to tanks that are connected to one another(referred to as connected in parallel). In addition, on September 18, 2015, the EPA published a suite of proposed rules to reduce methane and volatile organiccompound emissions from oil and gas industry, including new “downstream” requirements covering equipment in the natural gas transmission segment of theindustry that was not regulated by the 2012 rules. The public comment period closed on December 4, 2015. We cannot predict the final regulatoryrequirements or the cost to comply with such requirements with any certainty.Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturingpractices. The EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water resources. In June 2015, the EPA released its draftassessment report for peer review and public comment, finding that, while there are certain mechanisms by which hydraulic fracturing activities couldpotentially impact drinking water resources, there is no evidence available showing that those mechanisms have led to widespread, systemic impacts. Also,on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposalwells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmentalagencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or areevaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, andcould ultimately make it more 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 new legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose thechemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that applyto all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operatordisclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with theTexas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to thepublic and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted new rules governing well casing,cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The new rules took effect inJanuary 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, torequire applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activitysearches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square milesaround a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas RailroadCommission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismicactivity. The Texas Railroad Commission 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 allegations16that 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 legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences ofany failure to 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 estimatethe impact on 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 the regulatory burden. Also, numerous departments and agencies,both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members,some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doingbusiness and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affectother companies in the industry with similar types, quantities and locations of production.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.17Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilitiesand pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also haveregulations for plugging and abandonment, decommissioning and site restoration. 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.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.18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, comprehensive general liability, commercial automobile, workers compensation, pollutionliability (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, 2015, we had approximately 141 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 Securities and Exchange Commission. Information contained on, or connected to, our website is notincorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.19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 Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” These risksare not the only risks we face. We could also face additional risks and uncertainties not currently known to the Company or that we currently deem to beimmaterial. If any of these risks actually occurs, it could materially harm our business, financial conditional or results of operations and the trading priceof our shares could decline.Risks Related to the Oil and Natural Gas Industry and Our BusinessMarket conditions for oil and natural gas, and particularly the ongoing decline in prices for oil and natural gas have, and may continue to, adverselyaffect 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 six 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 $34.55 per barrel, or Bbl, in December 201520to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.63 per MMBtu in January 2016 to ahigh of $8.15 per MMBtu in February 2014. During 2015, WTI prices ranged from $34.55 to $61.36 per Bbl and the Henry Hub spot market price of naturalgas ranged from $1.63 to $3.32 per MMBtu. On January 20, 2016, the WTI posted price for crude oil was $26.68 per Bbl and the Henry Hub spot market priceof natural gas was $2.28 per MMBtu, representing decreases of 57% and 31%, respectively, from the high of $61.36 per Bbl of oil and $3.32 per MMBtu fornatural gas during 2015. If the prices of oil and natural gas continue at current levels or decline further, our operations, financial condition and level ofexpenditures for the development 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 contributed to increased economic uncertainty and diminished expectations for the global economy. In addition,continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect theglobal economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitatedan economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. Ifthe economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact theprice at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impactour 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 2015, our total capital expenditures,including expenditures for leasehold acquisitions, drilling and infrastructure, were approximately $900.9 million. Our 2016 capital budget for drilling,completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is currently estimated to be approximately$250.0 million to $375.0 million, representing a decrease of 26% over our 2015 capital budget. Since completing our initial public offering in October 2012,we have 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;21•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 2016 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.22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, 2015, we drilled atotal of 448 gross wells and participated in an additional 42 gross non-operated wells, of which 446 wells were completed as producing wells and 44 wellswere in various stages of completion. If future wells or the wells in the process of being completed do not produce sufficient revenues to return a profit or ifwe drill dry holes in the future, our business may be materially affected.23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 $40.00 per Bbl WTI, we currently have approximately 1,500 gross (960 net) identified economic potentialhorizontal drilling locations in multiple horizons on our acreage. As of December 31, 2015, only 107 of our gross identified potential horizontal drillinglocations and three of our identified vertical drilling locations were attributed to proved reserves. These drilling locations, including those without provedundeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number ofuncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gasprices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging fromlocations that are ready to drill to locations that will require substantial additional interpretation. In addition, we have identified approximately 690horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results fromother operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling locationwill yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the studyof producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whetheroil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage thepotentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in areduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drillinglocations, our drilling success rate may decline and materially harm our business. While through December 31, 2015, we are the operator of or haveparticipated in a total of 184 horizontal wells completed on our acreage, we cannot assure you that the analogies we draw from available data from these orother wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us orother operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if thepotential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drillinglocations. As such, our actual drilling activities may materially differ from those 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, 2015, we had leases representing 6,007 net acres expiring in 2016,15,142 net acres expiring in 2017, no net acres expiring in 2018, no net acres expiring in 2019 and 21 net acres expiring in 2020. The cost to renew suchleases 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 2016, 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 price swap derivatives and may in the future enter into forward sale contracts or additional price swap derivatives for a portion ofour production. Although we have hedged a portion of our estimated 2016 production, we may still be adversely affected by continuing and prolongeddeclines in the price of oil.We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed priceper barrel of oil and pay a floating market price per barrel of oil to the counterparty based on Inter-Continental Exchange, or ICE, pricing for Brent crude oil.The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. These contracts and any futureeconomic hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expectedor oil prices increase.24As of December 31, 2015, we had crude oil swap contracts in place covering ICE Brent crude oil priced at a weighted average price of $88.72 for91,000 aggregate Bbls for the production period of January through February 2016. As of February 17, 2016, we had not entered into any significant hedgingtransactions with respect to our anticipated 2016 production. To the extent that the price of oil remains at current levels or declines further, we will not beable to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively 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, which decreased quantity will be effective for the remainder of the term of the agreement. Ifproduction from our Permian Basin acreage decreases due to decreased developmental activities, as a result of the low commodity price environment,production related difficulties or otherwise, we may be unable to meet our obligations under the oil purchase agreement, which may result in deficiencypayments 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 $41.3 million at December 31, 2015) and receivables from purchasers of our oil and natural gasproduction (approximately $37.6 million at December 31, 2015). Joint interest receivables arise from billing entities that own partial interests in the wells weoperate. 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, 2015, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC(15%). For the year ended December 31, 2014, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company (64%); andEnterprise Crude Oil LLC (16%). For the year ended December 31, 2013, two purchasers each accounted for more than 10% of our revenue: Plains Marketing,L.P. (37%); and Shell Trading (US) Company (37%). No other customer accounted for more than 10% of our revenue during these periods. This concentrationof customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Currenteconomic 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 $17.84, $23.79 and $24.63 for the years ended December 31, 2015, 2014and 2013,25respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the years ended December 31, 2015, 2014 and 2013 was$216.1 million, $168.7 million and $65.8 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.An impairment on proved oil and natural gas properties of $814.8 million was recorded for the year ended December 31, 2015. No impairment onproved oil and natural gas properties was recorded for the years ended December 31, 2014 and 2013. See Item 7. “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations–Critical Accounting Policies and Estimates–Method of accounting for oil and natural gas properties” for amore detailed description of our method of accounting. If prices of oil, natural gas and natural gas liquids continue to decline, we may be required to furtherwrite down the value of our oil and natural gas properties, which could negatively affect our results of operations.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, 2015, 2014 and 2013 (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, 2015, 2014 and 2013 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, 2015, 2014 and 2013, respectively, in accordance with the SEC guidelines applicable to reserve estimates for such periods. Commodity priceshave deteriorated significantly since that time, and accordingly, using more recent prices in estimating our proved reserves, without giving effect to anyacquisition or development activities we have executed during 2016, would result in a reduction in proved reserve volumes due to economic limits.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.26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 41.3% of our total estimated proved reserves as of December 31, 2015, 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 geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may bedisproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused bygovernmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations orinterruption 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, 2015, all of our proved reserves wereattributable to the Wolfberry play. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changesin field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.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, 2015, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%).For the year ended December 31, 2014, two purchasers accounted for more than 10% of our revenue: Shell Trading27(US) Company (64%); and Enterprise Crude Oil LLC (16%). For the year ended December 31, 2013, two purchasers each accounted for more than 10% of ourrevenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). No other customer accounted for more than 10% of our revenue during theseperiods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production. The loss of one ormore of these customers, and our inability to sell our production to other customers on terms we consider acceptable, could materially and adversely affectour 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.Our business is difficult to evaluate because we have a limited operating history.Diamondback Energy, Inc. commenced business operations on October 11, 2012. Prior to that time, all of our historical oil and natural gas assets,operations and results described in this report were those of Windsor Permian LLC and Windsor UT LLC. In connection with our initial public offering,Windsor Permian LLC became our wholly-owned subsidiary and we acquired the oil and natural gas assets of Gulfport Energy Corporation located in thePermian Basin. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of ourperformance.We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.We commenced business operations in October 2012 and growth in accordance with our business plan, if achieved, could place a significant strainon our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or inwhich we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgradeour technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruitand retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on ourbusiness, financial condition 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.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.28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.Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.29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 have continually imposed increasingly strictrequirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental lawsand regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. 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, several federal agencies have assertedregulatory authority over certain aspects of the process. For example, the EPA has recently taken the position that hydraulic fracturing with fluids containingdiesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells underthe Safe Drinking Water Act. Furthermore, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from thedefinition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to requiredisclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress.In addition, on May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulationsunder the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. The EPA plans todevelop a Notice of Proposed Rulemaking by December 2016, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both- to collect data on hydraulic fracturing chemical substances and mixtures. Also, on April 7, 2015, the EPA published a proposed rule establishing federal pre-treatment standards for wastewater discharged from onshore unconventional oil and gas extraction facilities to POTW. The EPA asserts that wastewater fromsuch facilities can be generated in large quantities and can contain constituents that may disrupt POTW operations and/or be discharged, untreated, from thePOTW to receiving waters. If adopted, the new pre-treatment rule would require unconventional oil and gas facilities to pre-treat wastewater beforetransferring it to a POTW. The public comment period ended on July 17, 2015, and the EPA is expected to publish a final rule by August 2016. The EPA isalso conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gasextraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatmenttechnologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of dischargesfrom 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 rule seeks 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. The EPA is currently evaluating the potential impacts of hydraulic fracturing on drinking water resources. In June 2015, the EPA released its draftassessment report for peer review and public comment, finding that, while there are certain mechanisms by which hydraulic fracturing activities couldpotentially impact drinking water resources, there is no evidence available showing that those mechanisms have led to widespread, systemic impacts. Also,on February 6,302015, the EPA 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. 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 legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences ofany failure to 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 estimatethe impact on 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. Moreover,public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmentallegislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequentlyaffecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costlyoperating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materiallyadversely affected.31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 our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protectendangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previouslyunprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures orcould result in limitations on our exploration and 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.Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, andadditional state taxes on natural gas extraction may be imposed, as a result of future legislation.From time to time, legislative proposals are made that would, if enacted, make significant changes to U.S. tax laws. These proposed changes haveincluded, but are not limited to, (i) eliminating the immediate deduction for intangible drilling32and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration anddevelopment, (iii) the repeal of the percentage depletion allowance for oil and natural gas properties; (iv) an extension of the amortization period for certaingeological and geophysical expenditures and (v) implementing certain international tax reforms. Further, in February 2016, the President’s administrationissued a proposed budget, which includes, among other things, a proposed tax of $10.25 per barrel equivalent on petroleum products.These proposed changes in the U.S. tax law, if adopted, or other similar changes that tax our production or reduce or eliminate deductions currentlyavailable with respect to natural gas and oil exploration and development, could adversely affect our business, financial condition, results of operations andcash flows.The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas weproduce.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.”In December 2015, the United States joined the international community at 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, if ratified, establishes a framework for the partiesto cooperate and report actions to reduce greenhouse gas emissions.Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely affect the oil and natural gas industry. At this time, itis not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operationsconstitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulationsagainst us and could allege personal injury or property damages. While our business is not a party to this litigation, we could be named in actions makingsimilar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financialcondition.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 colder than their historicalaverages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fullyinsured. 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.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.33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.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 activities34are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and leaseundeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospectswill be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us orundeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we willrecover all or any portion of our investment in such unproved 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 prices 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.35A loss not fully 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 to discover reserves in the future will be dependent upon our ability toevaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financialand human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and naturalgas 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 financial36markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continuedaccess to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth andoperating results.We recorded stock-based compensation expense in 2015, 2014 and 2013, 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, 2015, 2014 and 2013 we incurred $24.6 million,$14.3 million and $2.7 million, respectively, of stock based compensation expense, of which we capitalized $6.0 million, $4.4 million and $1.0 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 adversely affect our net income. The future expense will be dependent upon the number of share-based awards issued and the fair value of the optionsor shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stockoptions generally over 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, 2015, we had total long-term debt of $495.5 million, including $450.0 million outstanding under the senior notes, and we hadunused borrowing base availability of $489.0 million under our revolving credit facility. As of37December 31, 2015, Viper, one of our subsidiaries, had $34.5 million in outstanding borrowings, and $165.5 million available for borrowing, under itsrevolving credit facility. We may in the future incur significant additional indebtedness under our revolving credit facility or otherwise in order to makeacquisitions, to develop our properties or for other purposes. Our level of indebtedness could have important consequences to you and affect our operationsin several ways, including the following:•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 indenture 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 indenture governing the senior notes contain, and the terms of any future indebtedness may contain, restrictivecovenants 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;38•designate certain of our subsidiaries as unrestricted subsidiaries;•create unrestricted subsidiaries;•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, in connection with theclosing of Viper’s initial public offering, we designated Viper, the general partner and Viper’s subsidiary as unrestricted subsidiaries under the indenturegoverning the senior notes and upon such designation, Viper Energy Partners LLC, which was a guarantor under the indenture governing the senior notesprior to such designation, was released as a guarantor under the indenture governing the 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 indenture governing the 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 indenture governing the 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 the 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 $750.0 million, of which we have elected a commitmentamount of $500.0 million. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on ouroil and natural gas reserves and other factors. As of December 31, 2015, we had outstanding borrowings of $11.0 million which bore a weighted averageinterest rate of 1.92%. We intend to continue borrowing under our revolving credit facility in the future. Any significant reduction in our borrowing base as aresult of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, mayhave a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving creditfacility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficientfunds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange newfinancing, we may have to sell significant assets. Any such sale could have a material adverse effect 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 of, to pay interest on or to refinance our indebtedness, including the senior notes, dependson our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cashflow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we maybe required to adopt one or more39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 indenture governing the senior notes restrict our ability to use theproceeds 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 proceeds thatwe 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 theindenture governing the senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2015, our borrowing baseunder our revolving credit facility was set at $750.0 million, of which we have elected a commitment amount of $500.0 million and we had outstandingborrowings of $11.0 million under this facility. As of December 31, 2015, Viper had $34.5 million in outstanding borrowings, and $165.5 million availablefor borrowing, under its revolving credit facility. In addition, the indenture governing the senior notes allows us to issue additional notes under certaincircumstances which will also be guaranteed by the guarantors. The indenture governing the senior notes also allows 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 indenture governing the senior notes does 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 0.50% to1.50% in the case of the alternative base rate and from 1.50% to 2.50% 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, 2015, we had $11.0 million in borrowings outstanding under our revolving credit facility. Ourweighted-average interest rate on borrowings from our revolving credit facility was 1.92% during the year ended December 31, 2015. Viper’s weightedaverage interest rate on borrowings from its revolving credit facility was 1.70% during the year ended December 31, 2015. As of December 31, 2015, Viper,one of our subsidiaries, had $34.5 million in outstanding borrowings, and $165.5 million available for borrowing, under its revolving credit facility. Ifinterest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.40Risks Related to Our Common StockThe corporate opportunity provisions in our certificate of incorporation could enable Wexford, our equity sponsor prior to our initial public offering, orother affiliates of ours to benefit from corporate opportunities that might otherwise 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.Wexford continues to own shares of our common stock, and its interests may conflict with those of our other stockholders.As of February 12, 2016, Wexford beneficially owned less than 1% of our common stock. In addition, an individual affiliated with Wexford serves asthe Chairman of our Board of Directors. As a result, Wexford may be able to exercise influence over matters requiring stockholder approval, including theelection of directors, changes to our organizational documents and significant corporate transactions. The interests of Wexford with respect to matterspotentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, mayconflict with the interests of our other stockholders.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.We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. These transactions include, amongothers, drilling services provided to us by Bison, real property leased by us from Fasken Midland, LLC, and hydraulic fracturing sand purchased by us fromMuskie. Each of these entities is either controlled by or affiliated with Wexford, and the resolution of any conflicts that may arise in connection with suchrelated party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because Wexfordmay have the ability to influence the outcome of these conflicts.We incur increased costs as a result of being a public company, which may significantly affect our financial condition. We completed our initial public offering in October 2012. As a public company, we incur significant legal, accounting and other expenses that wedid not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governancerequirements, including requirements under the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the Financial Industry RegulatoryAuthority. These rules and regulations increase our legal and financial compliance costs and make some activities more time-consuming and costly. Theserules and regulations make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to acceptreduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us toattract and retain qualified individuals to serve on our board of directors or as executive officers.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” for41our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stockwould be less liquid than the stock of companies with broader public ownership and, as a 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 unable to liquidate their investment in us. Furthermore, the stock market issubject to significant price and volume fluctuations, and the price of our common stock could 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 occur without regard to specific operating performance. Theprice of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materiallyreduce 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 offering 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.A change of control could limit our use of net operating losses.As of December 31, 2015, we had a net operating loss, or NOL, carry forward of approximately $82.6 million for federal income tax purposes.Transfers of our stock could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could belimited. In general, the amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the value of our stock (as ofthe ownership change date) multiplied by the long-term tax-exempt rate.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 ofspecified42events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders ofpreferred stock could affect the residual value of the common stock.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.We do not intend to pay cash dividends on our common stock in the foreseeable future and, therefore, only appreciation of the price of our common stockwill provide a return to our stockholders.We have not paid dividends since our inception and we currently anticipate that we will retain all future earnings, if any, to finance the growth anddevelopment of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and paymentof cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractualrestrictions, capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our revolving creditfacility prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may notoccur, will provide a return to our stockholders.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.43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 Low2015 1st Quarter$78.75 $55.532nd Quarter$85.82 $73.363rd Quarter$77.36 $60.284th Quarter$82.19 $61.512014 1st Quarter$70.99 $44.022nd Quarter$93.33 $64.053rd Quarter$90.48 $70.664th Quarter$76.94 $51.69Holders of RecordThere were four holders of record of our common stock on February 16, 2016.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.” We currentlyintend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends toholders of our common stock in the foreseeable future.Recent Sales of Unregistered SecuritiesNone.Repurchases of Equity SecuritiesNone.44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, 2015, 2014 and 2013 and the balance sheet data as of December 31, 2015 and 2014 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, 2012 and 2011 and thebalance sheet data as of December 31, 2013, 2012 and 2011 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)2015 2014 2013 2012(1) 2011(2)Statements of Operations Data: Total revenues$446,733 $495,718 $208,002 $74,962 $49,366Total costs and expenses1,187,002 283,048 112,808 57,655 34,219Income from operations(740,269) 212,670 95,194 17,307 15,147Other income (expense)(8,831) 92,286 (8,853) 1,075 (15,533)Income (loss) before income taxes(749,100) 304,956 86,341 18,382 (386)Provision for (benefit from) income taxes(201,310) 108,985 31,754 54,903 —Net income (loss)(547,790) 195,971 54,587 (36,521) (386)Less: Net income attributable to noncontrolling interest2,838 2,216 — — —Net income (loss) attributable to Diamondback Energy, Inc.$(550,628) $193,755 $54,587 $(36,521) $(386)Earnings per common share Basic$(8.74) $3.67 $1.30 Diluted$(8.74) $3.64 $1.29 Weighted average common shares outstanding Basic63,019 52,826 42,015 Diluted63,019 53,297 42,255 Pro forma information(3) Income (loss) before income taxes, as reported $18,382 $(386)Pro forma provision for income taxes 6,553 —Pro forma net income (loss) $11,829 $(386)Pro forma earnings per common share(4) Basic $0.60 Diluted $0.60 As of December 31,(In thousands)2015 2014 2013 2012(1) 2011(2)Balance Sheet Data: Cash and cash equivalents20,115 30,183 15,555 26,358 6,959Net property and equipment2,597,625 2,791,807 1,446,337 554,242 221,149Total assets2,758,412 3,095,481 1,521,614 606,701 263,578Current liabilities141,421 266,729 121,320 79,232 42,298Long-term debt495,500 673,500 460,000 193 85,000Total Stockholders’/ Members’ equity(5)1,875,972 1,751,011 845,541 462,068 129,037Total equity2,108,973 1,985,213 — — —45 Year Ended December 31,(In thousands)2015 2014 2013 2012(1) 2011(2)Other Financial Data: Net cash provided by operating activities$416,501 $356,389 $155,777 $49,692 $30,998Net cash used in investing activities(895,050) (1,481,997) (940,140) (183,078) (81,108)Net cash provided by financing activities468,481 1,140,236 773,560 152,785 52,950 Year Ended December 31,(In thousands)2015 2014 2013 2012(1) 2011(2)Adjusted EBITDA(6)$449,245 $398,334 $157,604 $42,783 $31,721(1)The year ended December 31, 2012 reflects (a) the combined historical financial data of Windsor Permian LLC and Windsor UT LLC, which wesometimes refer to as the Predecessors, due to the transfer of a business between entities under common control and (b) the results of operationsattributable to the acquisition of properties from Gulfport Energy Corporation beginning October 11, 2012, the closing date of the property acquisition.(2)The year ended December 31, 2011 reflects the combined historical financial data of Windsor Permian LLC and Windsor UT LLC due to the transfer of abusiness between entities under common control.(3)Diamondback was formed as a holding company on December 30, 2011, and did not conduct any material business operations until October 11, 2012when Diamondback merged with its parent entity, Diamondback Energy LLC, with Diamondback continuing as the surviving entity. Diamondback is asubchapter C corporation under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision for2012 as if the Company and the Predecessors were subject to income taxes since December 31, 2011. For 2011 comparative purposes, we have includedpro forma financial data to give effect to income taxes assuming the earnings of the Company and the Predecessors had been subject to federal incometax as a subchapter C corporation since inception. If the earnings of the Company and the Predecessors had been subject to federal income tax as asubchapter C corporation since inception, we would have incurred net operating losses for income tax purposes in each period. We would have been in anet deferred tax asset position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s deferred tax assetbalance to zero. A valuation allowance to reduce each period’s deferred tax asset would have resulted in an equal and offsetting credit for the respectiveexpenses or an equal and offsetting debit for the respected benefits for income taxes, with the resulting tax expenses for 2011 of zero. The unaudited proforma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financialposition as of any future date. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate,net of federal benefit, incorporating permanent differences. See Note 2 to our consolidated financial statements included elsewhere in this Annual Reporton Form 10-K.(4)The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stockoutstanding for the period, as if the common shares issued upon the merger of Diamondback Energy LLC into Diamondback were outstanding for theentire year. Diluted earnings per share reflects the potential dilution, using the treasury stock method, which assumes that options were exercised andrestricted stock awards and units were fully vested. During periods in which the Company realizes a net loss, options and restricted stock awards wouldnot be dilutive to net loss per share and conversion into common stock is assumed not to occur.(5)For the years ended December 31, 2015 and 2014, total stockholders’ equity excludes $233.0 million and $234.2 million, respectively, ofnoncontrolling interest related to Viper Energy Partners LP. There was no equity related to noncontrolling interest for the years ended December 31,2013, 2012 and 2011.(6)Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA tonet income (loss) see “–Non-GAAP financial measure and reconciliation” below.Non-GAAP financial measure and reconciliationAdjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such asindustry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) plus change in the fair value of open non-hedgederivative instruments, net, interest expense, depreciation, depletion and amortization expense, impairment of oil and natural gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, income tax provision (benefit)and non-controlling interest. Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. Management believes Adjusted EBITDA isuseful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period withoutregard to our financing methods or capital structure. We add the items listed above to net income (loss) in arriving at Adjusted EBITDA because theseamounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capitalstructures and the method46by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determinedin accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significantcomponents in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historiccosts of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to othersimilarly titled measure of other companies or to such measure in our revolving credit facility or any of our other contracts.The following presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income(loss). Year Ended December 31,(In thousands)2015 2014 2013 2012 2011Net income (loss):$(547,790) $195,971 $54,587 $(36,521) $(386)Change in the fair value of open non-hedge derivativeinstruments, net112,918 (117,109) (5,346) (8,057) 12,972Interest expense (income)41,510 34,515 8,059 3,610 2,528Depreciation, depletion and amortization expense217,697 170,005 66,597 26,273 16,104Impairment of oil and natural gas properties814,798 — — — —Non-cash equity-based compensation expense24,572 14,253 2,724 3,482 544Capitalized equity-based compensation expense(6,043) (4,437) (972) (1,005) (106)Asset retirement obligation accretion expense833 467 201 98 65Income tax provision (benefit)(201,310) 108,985 31,754 54,903 —Non-controlling interest(7,940) (4,316) — — —Adjusted EBITDA$449,245 $398,334 $157,604 $42,783 $31,72147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 Clearfork, Spraberry, Wolfcamp, Cline,Strawn and Atoka formations which we refer to as the Wolfberry play. We intend to continue to develop our reserves and increase production throughdevelopment drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and throughacquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the saleof oil, natural gas liquids and natural gas production. Our production was approximately 75% oil, 14% natural gas liquids and 11% natural gas for the yearended December 31, 2015, approximately 76% oil, 14% natural gas liquids and 10% natural gas for the year ended December 31, 2014 and approximately76% oil, 13% natural gas liquids and 11% natural gas for the year ended December 31, 2013. On December 31, 2015, our net acreage position in the PermianBasin was approximately 84,683 net acres.2015 Transactions and Recent DevelopmentsCommon stock transactionsIn January 2015, we completed an underwritten public offering of 2,012,500 shares of common stock, which included 262,500 shares of commonstock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $59.34 per share and wereceived proceeds of approximately $119.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts andcommissions.In May 2015, we completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stockissued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $72.53 per share and wereceived proceeds of approximately $333.6 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts andcommissions.In August 2015, we completed an underwritten public offering of 2,875,000 shares of common stock, which included 375,000 shares of commonstock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $68.74 per share and wereceived proceeds of approximately $197.6 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts andcommissions.In January 2016, we completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of commonstock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $55.33 per share and wereceived proceeds of approximately $254.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts andcommissions.Leasehold and Mineral Interest TransactionsSince January 1, 2015, we have acquired from unrelated third party sellers an aggregate of approximately 16,940 gross (12,672 net) acres in theMidland Basin, primarily in northwest Howard County, for an aggregate purchase price of approximately $437.5 million, subject to certain adjustments.Approximately 83% of this acreage is held by production. We believe the acreage is prospective for horizontal drilling in the Lower Spraberry, Wolfcamp Aand Wolfcamp B horizons, and have identified an aggregate of approximately 232 net potential horizontal drilling locations in these horizons based on 660foot spacing between wells. We currently estimate that approximately 42% of the potential horizontal locations will have approximately 10,000 foot laterals,which can provide higher rates of return and capital efficiency than shorter laterals. The average lateral length for these potential horizontal locations isestimated to be approximately 8,357 feet. We also believe that additional development potential may exist in the Middle Spraberry horizon. Salt waterdisposal infrastructure is already in place on the acreage in Northwest Howard County, and the acquisitions included 3-D seismic data that can be used togeosteer the drilling of horizontal wells. On48Table of ContentsJuly 9, 2015, we completed the sale of an approximate average 1.5% overriding royalty interest in certain of its acreage primarily located in Howard County,Texas to the Partnership for $31.1 million.Operational UpdateIn January 2016, we completed our first three well pad in Glasscock County targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B with anaverage lateral length of 7,400 feet. The wells are in various stages of flowback and artificial lift but produced in excess of 3,600 BOE/d (81% oil) on acombined basis over seven days. Our second pad in Glasscock County, with two wells targeting the Wolfcamp A and Wolfcamp B, was still cleaning up as ofFebruary 15, 2016.We have drilled our first three-well pad in Howard County targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B. One of the wells on this padhas a 9,600 foot lateral that was drilled in less than 12 days from spud to total depth. As of February 15, 2106, we were drilling our second three-well pad inHoward County. We intend to begin completion of these wells in mid-2016.We intend to release one of our three horizontal drilling rigs in March 2016. We will continue monitoring the commodity price environment andexpect to retain the financial flexibility to adjust our drilling and completion plans in response to market conditions.2016 Capital BudgetWe expect a 2016 total capital spend of $250.0 million to $375.0 million, consisting of $210.0 million to $315.0 million for horizontal drilling andcompletions, $25.0 million to $35.0 million for infrastructure and $15.0 million to $25.0 million for non-operated activity and other expenditures. We expectto drill and complete 30 to 70 gross horizontal wells in 2016.We intend to release one of our three horizontal drilling rigs in March 2016. We will continue monitoring the ongoing commodity priceenvironment and expect to retain the financial flexibility to adjust our drilling and completion plans as conditions warrant. We are prepared to decelerate ourdrilling program if commodity prices deteriorate and accelerate our drilling program if commodity prices improve. If necessary, we can release a second rig inthe second quarter of 2016 and continue to operate one rig to hold acreage.Basis of PresentationTransfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prioryears are retrospectively adjusted to furnish comparative information. The Windsor UT LLC contribution was accounted for as a transaction between entitiesunder common control. Accordingly, the financial information and production data contained in this report have been retrospectively adjusted to include thehistorical results of Windsor UT LLC at historical carrying values and its operations prior to October 11, 2012, the effective date of the Windsor UT LLCcontribution.Operating Results OverviewDuring the year ended December 31, 2015, our average daily production was approximately 33,098 BOE/d, consisting of 24,880 Bbls/d of oil,21,729 Mcf/d of natural gas and 4,596 Bbls/d of natural gas liquids, an increase of 13,624 BOE/d, or 70%, from average daily production of 19,474 BOE/dfor the year ended December 31, 2014, consisting of 14,744 Bbls/d of oil, 11,907 Mcf/d of natural gas and 2,745 Bbls/d of natural gas liquids.During the year ended December 31, 2015, we drilled 64 gross (54.4 net) horizontal wells and four gross (three net) vertical wells and participated inthe drilling of 15 gross (six net) non-operated wells in the Permian Basin.49Table of ContentsReserves and pricingRyder Scott prepared estimates of our proved reserves at December 31, 2015, 2014 and 2013 (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. 2015 2014 2013Estimated Net Proved Reserves: Oil (Bbls)105,978,711 75,689,589 42,600,852Natural gas (Mcf)149,502,744 111,605,260 61,679,496Natural gas liquids (Bbls)26,004,144 18,541,932 10,705,724Total (BOE)156,899,979 112,832,398 63,586,492 2015 2014 2013 Unweighted Arithmetic Average First-Day-of-the-Month PricesOil (per Bbl)$45.07 $87.15 $92.59Natural gas (per Mcf)$1.83 $4.85 $4.13Natural gas liquids (per Bbl)$12.56 $30.09 $37.82Sources 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. For the year ended December 31, 2015, our revenues werederived 91% from oil sales, 5% from natural gas liquids sales and 4% from natural gas sales. For the year ended December 31, 2014, our revenues werederived 91% from oil sales, 6% from natural gas liquids sales and 3% from natural gas sales. For the year ended December 31, 2013, our revenues werederived 91% from oil sales, 6% from natural gas liquids sales and 3% from natural gas sales. Our revenues may vary significantly from period to period as aresult of changes in volumes of production sold, production mix or commodity prices.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 2015, West Texas Intermediate postedprices ranged from $34.55 to $61.36 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.63 to $3.32 per MMBtu. On December 31,2015, the West Texas Intermediate posted price for crude oil was $37.13 per Bbl and the Henry Hub spot market price of natural gas was $2.28 per MMBtu.Over the past several months, oil prices have declined from over $61.00 per Bbl in June 2015 to below $27.00 per Bbl in January 2016 due in largepart to increasing supplies and weakening demand growth. Lower prices may not only decrease our revenues, but also potentially the amount of oil andnatural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our creditagreement, which may be determined at the discretion of our lenders.Principal components of our cost structureLease operating and natural gas transportation and treating expenses. These are daily costs incurred to bring oil and natural gas out of the groundand to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workoverexpenses related to our oil and natural gas properties.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.50Table of ContentsGeneral and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining ourheadquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legalcompliance.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 expense. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.Other income (expense)Interest income. This represents the interest received on our cash and cash equivalents.Interest expense. We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under ourrevolving credit facility and our net proceeds from the issuance of the senior notes. We incur interest expense that is affected by both fluctuations in interestrates and our financing decisions. We reflect interest paid to our lender in interest expense. In addition, we include the amortization of deferred financingcosts (including origination and amendment fees), commitment fees and annual agency fees in interest expense.Gain/Loss on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price ofcrude oil. This amount represents (i) the recognition of the change in the fair value of open non-hedge derivative contracts as commodity prices change andcommodity derivative contracts expire or new ones are entered into, and (ii) our gains and losses on the settlement of these commodity derivativeinstruments.Loss from equity investment. This line item represents our proportionate share of the earnings and losses from our investment in the membershipinterests of Muskie, an equity method investment.We 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.51Table of ContentsResults of OperationsThe following table sets forth selected historical operating data for the periods indicated. Year Ended December 31, 2015 2014 2013 (in thousands, except Bbl, Mcf and BOE amounts)Revenues Oil, natural gas liquids and natural gas $446,733 $495,718 $208,002Operating Expenses Lease operating expense 82,625 55,384 21,157Production and ad valorem taxes 32,990 32,638 12,899Gathering and transportation expense 6,091 3,288 918Depreciation, depletion and amortization 217,697 170,005 66,597Impairment of oil and natural gas properties 814,798 — —General and administrative 31,968 21,266 11,036Asset retirement obligation accretion expense 833 467 201Total expenses 1,187,002 283,048 112,808Income (loss) from operations (740,269) 212,670 95,194Net interest expense (41,510) (34,514) (8,058)Other income 728 677 1,077Other expense — (1,416) —Gain (loss) on derivative instruments, net 31,951 127,539 (1,872)Total other income (expense), net (8,831) 92,286 (8,853)Income (loss) before income taxes (749,100) 304,956 86,341Income tax provision (benefit) (201,310) 108,985 31,754Net income (loss) (547,790) 195,971 54,587Less: Net income attributable to noncontrolling interest 2,838 2,216 —Net income (loss) attributable to Diamondback Energy, Inc. $(550,628) $193,755 $54,58752Table of Contents Year Ended December 31, 2015 2014 2013 (in thousands, except Bbl, Mcf and BOE amounts)Production Data: Oil (Bbls) 9,081,135 5,381,576 2,022,749Natural gas (Mcf) 7,931,237 4,345,916 1,730,497Natural gas liquids (Bbls) 1,677,623 1,001,991 361,079Combined volumes (BOE) 12,080,631 7,107,886 2,672,244Daily combined volumes (BOE/d) 33,098 19,474 7,321 Average Prices: Oil (per Bbl) $44.68 $83.48 $93.32Natural gas (per Mcf) 2.47 4.15 3.61Natural gas liquids (per Bbl) 12.77 28.39 36.00Combined (per BOE) 36.98 69.74 77.84Oil, hedged($ per Bbl)(1) 60.63 85.42 89.75Average price, hedged($ per BOE)(1) 48.97 71.21 75.14 Average Costs per BOE: Lease operating expense $6.84 $7.79 $7.92Production and ad valorem taxes 2.73 4.59 4.83Gathering and transportation expense 0.50 0.46 0.34General and administrative - cash component 1.11 1.61 3.47Total operating expense - cash 11.18 14.45 16.56 General and administrative - non-cash component 1.54 1.38 0.66Depreciation, depletion, and amortization 18.02 23.92 24.92Interest expense 3.44 4.86 3.02Total expenses 23.00 30.16 28.60(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.Comparison of the Years Ended December 31, 2015 and 2014Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues decreased by approximately $49.0million, or 10%, to $446.7 million for the year ended December 31, 2015 from $495.7 million for the year ended December 31, 2014. 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 13,624 BOE/d to 33,098 BOE/d during the year ended December 31, 2015 from 19,474 BOE/d during the year ended December 31, 2014.The total decrease in revenue of approximately $49.0 million is largely attributable to lower average sales prices partially offset by higher oil, natural gasliquids and natural gas production volumes for the year ended December 31, 2015 as compared to the year ended December 31, 2014. The increases inproduction volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 3,699,559 Bblsof oil, 675,632 Bbls of natural gas liquids and 3,585,321 Mcf of natural gas for the year ended December 31, 2015 as compared to the year endedDecember 31, 2014.53Table of ContentsThe net dollar effect of the decreases in prices of approximately $391.9 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 $342.9 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the periodaverage prices) are shown below. Change in prices Productionvolumes(1) Total net dollareffect of change (in thousands)Effect of changes in price: Oil$(38.80) 9,081,135 $(352,356)Natural gas liquids$(15.62) 1,677,623 $(26,204)Natural gas$(1.68) 7,931,237 $(13,324)Total revenues due to change in price $(391,884) Change inproductionvolumes(1) Prior periodaverage prices Total net dollareffect of change (in thousands)Effect of changes in production volumes: Oil3,699,559 $83.48 $308,839Natural gas liquids675,632 $28.39 $19,181Natural gas3,585,321 $4.15 $14,879Total revenues due to change in production volumes $342,899Total change in revenues $(48,985)(1)Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas.Lease Operating Expense. Lease operating expense was $82.6 million ($6.84 per BOE) for the year ended December 31, 2015, an increase of $27.2million, or 49%, from $55.4 million ($7.79 per BOE) for the year ended December 31, 2014. The increase is due to increased drilling activity andacquisitions, which resulted in 169 additional producing wells for the year ended December 31, 2015 as compared to the year ended December 31, 2014.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 Tax Expense. Production and ad valorem taxes increased to $33.0 million for the year ended December 31, 2015 from$32.6 million for the year ended December 31, 2014. 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.During the year ended December 31, 2015, our production taxes per BOE decreased by $1.86 as compared to the year ended December 31, 2014, primarilyreflecting the impact of lower oil and natural gas prices on production taxes in 2015, offset by an increased production as a result of our acquisitions anddrilling.Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased $47.7 million, or 28%, from$170.0 million for the year ended December 31, 2014 to $217.7 million for the year ended December 31, 2015.54Table of ContentsThe following table provides components of our depreciation, depletion and amortization expense for the periods presented: Year Ended December 31, 2015 2014 (in thousands, except BOE amounts)Depletion of proved oil and natural gas properties$216,056 $168,674Depreciation of other property and equipment1,641 1,331Depreciation, depletion and amortization expense$217,697 $170,005Oil and natural gas properties depreciation, depletion and amortization expense per BOE$17.84 $23.79Total depreciation, depletion and amortization expense per BOE$18.02 $23.92The increases in depletion of proved oil and natural gas properties of $47.4 million for the year ended December 31, 2015 as compared to the yearended December 31, 2014 resulted primarily from higher total production levels and an increase in net book value on new reserves. On a per BOE basis,depreciation, depletion and amortization decreased primarily due to the impairment of oil and gas properties recorded in 2015.Impairment of Oil and Natural Gas Properties. During the year ended December 31, 2015, we recorded an impairment of oil and natural gasproperties of $814.8 million as a result of the significant decline in prices in 2015. No impairment was recorded in 2014. General and Administrative Expense. General and administrative expense increased $10.7 million from $21.3 million for the year ended December31, 2014 to $32.0 million for the year ended December 31, 2015. The increase was due to increases in salaries and benefits expense as a result of an increasein workforce and equity-based compensation.Net Interest Expense. Net interest expense for the year ended December 31, 2015 was $41.5 million as compared to $34.5 million for the year endedDecember 31, 2014, an increase of $7.0 million. This increase was due primarily to the higher average level of outstanding borrowings under our creditfacility during 2015.Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We havenot designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize thecash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) onderivative instruments, net.” For the years ended December 31, 2015 and 2014, we had a cash gain on settlement of derivative instruments of $144.9 millionand $10.4 million, respectively. For the year ended December 31, 2015, we had a negative change in the fair value of open derivative instruments of $112.9million as compared to a positive change in the fair value of open derivative instruments of $117.1 million during the year ended December 31, 2014.Income Tax Benefit (Expense). We recorded an income tax benefit of $201.3 million for the year ended December 31, 2015 as compared to anincome tax expense of $109.0 million for the year ended December 31, 2014. Our effective tax rate was 26.9% for the year ended December 31, 2015 ascompared to 35.7% for the year ended December 31, 2014.Comparison of the Years Ended December 31, 2014 and 2013Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $287.7million, or 138%, to $495.7 million for the year ended December 31, 2014 from $208.0 million for the year ended December 31, 2013. 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 12,153 BOE/d to 19,474 BOE/d during the year ended December 31, 2014 from 7,321 BOE/d during the year ended December 31, 2013.The total increase in revenue of approximately $287.7 million was largely attributable to higher oil, natural gas liquids and natural gas production volumesfor the year ended December 31, 2014 as compared to the year ended December 31, 2013, partially offset by lower average sales prices. The increases inproduction volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 3,358,827 Bblsof oil, 640,912 Bbls of natural gas liquids and 2,615,419 Mcf of natural gas for the year ended December 31, 2014 as compared to the year endedDecember 31, 2013.55Table of ContentsThe net dollar effect of the decreases in prices of approximately $58.2 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 $346.0 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the periodaverage prices) are shown below. Change in prices Productionvolumes(1) Total net dollareffect of change (in thousands)Effect of changes in price: Oil$(9.84) 5,381,576 $(52,959)Natural gas liquids$(7.61) 1,001,991 $(7,625)Natural gas$0.54 4,345,916 $2,345Total revenues due to change in price $(58,239) Change inproductionvolumes(1) Prior periodaverage prices Total net dollareffect of change (in thousands)Effect of changes in production volumes: Oil3,358,827 $93.32 $313,444Natural gas liquids640,912 $36.00 $23,071Natural gas2,615,419 $3.61 $9,440Total revenues due to change in production volumes $345,955Total change in revenues $287,716(1)Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas.Lease Operating Expense. Lease operating expense was $55.4 million ($7.79 per BOE) for the year ended December 31, 2014, an increase of $34.2million, or 162%, from $21.2 million ($7.92 per BOE) for the year ended December 31, 2013. The increase was due to increased drilling activity andacquisitions, which resulted in 389 additional producing wells for the year ended December 31, 2014 as compared to the year ended December 31, 2013.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. On a per BOE basis, lease operating expense remained stable as new volumes came on line and expenses were held in line or werereduced.Production and Ad Valorem Tax Expense. Production and ad valorem taxes increased to $32.6 million for the year ended December 31, 2014 from$12.9 million for the year ended December 31, 2013. 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.During the year ended December 31, 2014, our production taxes per BOE decreased by $0.24 as compared to the year ended December 31, 2013, primarilyreflecting the impact of lower oil and natural gas prices on production taxes. Our ad valorem taxes have increased primarily as a result of increased valuationson our properties.Depreciation, Depletion and Amortization Expense. Depreciation, depletion and amortization expense increased $103.4 million, or 155%, from$66.6 million for the year ended December 31, 2013 to $170.0 million for the year ended December 31, 2014.56Table of ContentsThe following table provides components of our depreciation, depletion and amortization expense for the periods presented: Year Ended December 31, 2014 2013 (in thousands, except BOE amounts)Depletion of proved oil and natural gas properties$168,674 $65,821Depreciation of other property and equipment1,331 776Depreciation, depletion and amortization expense$170,005 $66,597Oil and natural gas properties depreciation, depletion and amortization expense per BOE$23.79 $24.63Total depreciation, depletion and amortization expense per BOE$23.92 $24.92The increases in depletion of proved oil and natural gas properties of $102.9 million for the year ended December 31, 2014 as compared to the yearended December 31, 2013 resulted primarily from higher total production levels, increased net book value on new reserves added and an increase incapitalized interest to the full cost pool. On a per BOE basis, depreciation, depletion and amortization expense decreased primarily due to the increased netbook value on new reserves and acquisitions.General and Administrative Expense. General and administrative expense increased $10.2 million from $11.0 million for the year endedDecember 31, 2013 to $21.3 million for the year ended December 31, 2014. The increase was due to increases in equity-based compensation, salary, legal,professional service and advisory service expenses. These increases were partially offset by increases in general and administrative costs related toexploration and development activity capitalized to the full cost pool and increases in COPAS overhead reimbursements due to increased drilling activity.Net Interest Expense. Net interest expense for the year ended December 31, 2014 was $34.5 million as compared to $8.1 million for the year endedDecember 31, 2013, an increase of $26.5 million. This increase was due primarily to the issuance of $450.0 million in aggregate principal amount of our7.625% senior notes in September 2013.Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We havenot designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize thecash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) onderivative instruments, net.” For the years ended December 31, 2014 and 2013, we had a cash gain on settlement of derivative instruments of $10.4 millionand a cash loss on settlement of derivative instruments of $7.2 million, respectively. For the years ended December 31, 2014 and 2013, we had a positivechange in the fair value of open derivative instruments of $117.1 million and $5.3 million, respectively.Income Tax Expense. We recorded income tax expense of $109.0 million for the year ended December 31, 2014 as compared to $31.8 million forthe year ended December 31, 2013. Our effective tax rate was 35.7% for the year ended December 31, 2014 as compared to 36.8% for the year endedDecember 31, 2013.Liquidity 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.57Table of ContentsLiquidity and Cash FlowOur cash flows for the years ended December 31, 2015, 2014 and 2013 are presented below: Year Ended December 31, 2015 2014 2013 (in thousands)Net cash provided by operating activities$416,501 $356,389 $155,777Net cash used in investing activities(895,050) (1,481,997) (940,140)Net cash provided by financing activities$468,481 $1,140,236 $773,560Net change in cash$(10,068) $14,628 $(10,803)Operating ActivitiesNet cash provided by operating activities was $416.5 million for the year ended December 31, 2015 as compared to $356.4 million for the yearended December 31, 2014. The increase in operating cash flows is primarily the result of the increase in our oil and natural gas revenues due to a 70.0%increase in our net BOE production partially offset by a 47.0% decrease in our net realized sales prices.Net cash provided by operating activities was $356.4 million for the year ended December 31, 2014 as compared to $155.8 million for the yearended December 31, 2013. The increase in operating cash flows is primarily a result of the increase in our oil and natural gas revenues due to a 166.0%increase in our net BOE production partially offset by a 10.4% decrease in our net realized sales prices.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 $895.1 million, $1,482.0 million and $940.1 million during the years ended December 31, 2015, 2014 and 2013 respectively.During the year ended December 31, 2015, we spent $419.5 million on capital expenditures in conjunction with our drilling program, in which wedrilled 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,$437.5 million on leasehold acquisitions, $43.9 million on royalty interest acquisitions and $1.2 million for the purchase of other property and equipment.During the year ended December 31, 2014, we spent $499.8 million on capital expenditures in conjunction with our drilling program and relatedinfrastructure projects, in which we drilled 82 gross (67 net) horizontal wells and 27 gross (22 net) vertical wells and participated in the drilling of four gross(two net) non-operated wells. We spent an additional $845.8 million on leasehold costs, $44.2 million for the purchase of other property and equipment,$57.7 million on the acquisitions of mineral interests underlying approximately 10,364 gross (3,261 net) acres in the Midland and Delaware basins andapproximately $33.9 million for a minor equity interest in an entity that owns mineral, overriding royalty, net profits, leasehold and other similar interests.During the year ended December 31, 2013, we spent $297.7 million on capital expenditures in conjunction with our drilling program in whichdrilled 77 gross (70 net) wells and participated in the drilling of four gross (two net) non-operated wells. We spent an additional $444.1 million on theacquisition of mineral interests, $177.3 million on leasehold costs, $2.2 million for the purchase of other property and equipment and $0.3 million, net, onthe settlement of non-hedge derivative instruments and $18.6 million for the post-closing adjustment associated with our acquisition of Gulfport EnergyCorporation’s oil and natural gas assets in the Permian Basin in connection with our initial public offering in October 2012.58Table of ContentsOur investing activities for the years ended December 31, 2015, 2014 and 2013 are summarized in the following table: Year Ended December 31, 2015 2014 2013 (in thousands)Drilling, completion and infrastructure$(419,512) $(499,848) $(297,713)Acquisition of leasehold interests(437,455) (845,826) (177,343)Acquisition of Gulfport properties— — (18,550)Acquisition of royalty interests(43,907) (57,689) (444,083)Purchase of other property and equipment(1,213) (44,213) (2,234)Proceeds from sale of assets9,739 56 72Equity investments(2,702) (34,477) —Settlement of non-hedge derivative instruments— — (289)Net cash used in investing activities$(895,050) $(1,481,997) $(940,140)Financing Activities Net cash provided by financing activities for the years ended December 31, 2015, 2014 and 2013 was $468.5 million, $1,140.2 million and $773.6million, respectively. The 2015 amount provided by financing activities was primarily attributable to the aggregate proceeds from our January, May andAugust 2015 equity offerings of $650.7 million partially offset by repayments of net borrowings of $184.5 million, under our credit facility. During the yearended December 31, 2014, the amount provided by financing activities was primarily attributable to the net proceeds of $208.4 million from our February2014 equity offering, net proceeds of $137.2 million from the Viper Offering, net proceeds of $485.0 million from our July 2014 equity offering, net proceedsof $94.8 million from the Viper September 2014 equity offering and borrowings, net of repayment, of $213.5 million under our credit facility. For the yearended December 31, 2013, the amount provided by financing activities was primarily attributable to (a) the net proceeds of $144.4 million from our May2013 equity offering, $177.5 million from our August 2013 equity offering, $450.0 million from our September 2013 senior note offering and (b) netborrowings of $10.0 million under our revolving credit facility. In both 2014 and 2013, these proceeds were used primarily to acquire property and fund ourdrilling costs.Senior NotesOn September 18, 2013, we completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due 2021,which we refer to as the senior notes. The senior notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October1 of each year and will mature on October 1, 2021. On June 23, 2014, in connection with the Viper Offering, we designated Viper, the general partner andViper Energy Partners LLC, as unrestricted subsidiaries and, upon such designation, Viper Energy LLC, which was a guarantor under the indenture governingof the senior notes, was released as a guarantor under the indenture. As of December 31, 2015, the senior notes were fully and unconditionally guaranteed byDiamondback O&G LLC, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any of our future restricted subsidiaries. Thenet proceeds from the senior notes were used to fund the acquisition of mineral interests underlying approximately 14,804 gross (12,687 net) acres inMidland County, Texas in the Permian Basin.The senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo Bank,N.A., as the trustee, as amended and supplemented, or the Indenture. We may issue additional senior notes under the Indenture, and all senior notes issuedunder the Indenture will constitute part of a single class of securities for all purposes of the Indenture. The Indenture contains certain covenants that, subjectto certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additionalindebtedness, make certain investments, declare or pay dividends or make other distributions on, or redeem or repurchase, capital stock, prepay subordinatedindebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell orotherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gasbusiness and designate certain of our subsidiaries as unrestricted subsidiaries. If we experience certain kinds of changes of control or if we sell certain of ourassets, holders of the senior notes may have the right to require us to repurchase their senior notes.We have the option to redeem the senior notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed aspercentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning onOctober 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafterwith any accrued and unpaid interest59Table of Contentsto, but not including, the date of redemption. In addition, prior to October 1, 2016, we may redeem all or a part of the senior notes at a price equal to 100% ofthe principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date.Furthermore, before October 1, 2016, we may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the senior notes withthe net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the senior notes being redeemed plus anyaccrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes originally issued under theIndenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. In connection with the issuance of the senior notes, we and the subsidiary guarantors entered into a registration rights agreement with the initialpurchasers on September 18, 2013, pursuant to which we and the subsidiary guarantors agreed to offer to exchange the senior notes for a new issue ofsubstantially identical debt securities registered under the Securities Act. The exchange offer was completed on October 23, 2014.Second Amended and Restated Credit FacilityOur second amended and restated credit agreement, dated November 1, 2013, as amended on June 9, 2014 and November 13, 2014, with a syndicateof banks, including Wells Fargo, as administrative agent, sole book runner and lead arranger, provides for a revolving credit facility in the maximum amountof $2.0 billion, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves andother factors. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, we mayrequest up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2015, the borrowing base was set at$750.0 million, although we elected a commitment amount of $500.0 million. As of December 31, 2015, we had outstanding borrowings of $11.0 million,which bore a weighted-average interest rate of 1.92%, and $489.0 million available for future borrowings under this facility.The June 9, 2014 amendment modified certain provisions of the credit agreement to, among other things, allow us to designate one or more of oursubsidiaries as “Unrestricted Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with the Viper Offering,we designated Viper, the general partner and Viper Energy Partners LLC as unrestricted subsidiaries under the credit agreement. As of December 31, 2015, theloan was guaranteed by us, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any of our future restricted subsidiaries. Thecredit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors. The outstanding borrowings under the credit agreement bear interest at a rate elected by us that is equal to an alternative base rate (which is equal tothe 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 the applicable margin.The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each casedepending on the amount of the loan outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to theborrowing base. 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 that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (insome 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 deficiency or event ofdefault exists under the credit agreement and (c) at the maturity date of November 1, 2018.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 $750.0 million in the form of senior or seniorsubordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each suchissuance. A borrowing base reduction in connection with such issuance may60Table of Contentsrequire a portion of the outstanding principal of the loan to be repaid. As of December 31, 2015, we had $450.0 million of senior notes outstanding.As of December 31, 2015, 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.Viper’s Facility-Wells Fargo BankOn July 8, 2014, Viper entered into a secured revolving credit agreement with Wells Fargo Bank, as the administrative agent, sole book runner andlead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, provides for a revolving creditfacility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based onViper’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st andOctober 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. The credit agreementwas further amended on May 22, 2015 to, among other things, increase the borrowing base from $110.0 million to $175.0 million and to provide for certainrestrictions on purchasing margin stock. On November 13, 2015, the borrowing base was increased from $175.0 million to $200.0 million. As ofDecember 31, 2015, the borrowing base was set at $200.0 million. Viper had $34.5 million outstanding under its credit agreement.The outstanding borrowings under Viper’s credit agreement bear interest at a rate elected by Viper that is equal to an alternative base rate (which isequal 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 applicablemargin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in eachcase depending on the amount of the loan outstanding in relation to the borrowing base. Viper is obligated to pay a quarterly commitment fee ranging from0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to theborrowing base. 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 that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (insome cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of Viper and itssubsidiaries.The Viper 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 $250.0 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. The 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.61Table of ContentsCapital Requirements and Sources of LiquidityOur board of directors approved a 2016 capital budget for drilling and infrastructure of $250.0 million to $375.0 million, representing a decrease of26% over our 2015 capital budget. We estimate that, of these expenditures, approximately:•$210.0 million to $315.0 million will be spent on drilling and completing 30 to 70 gross (25 to 58 net) operated horizontal wells focused inMidland, Andrews, Upton, Martin and Dawson Counties;•$25.0 million to $35.0 million will be spent on infrastructure; and•$15.0 million to $25.0 million will be spent on non-operated activity and other expenditures.During the year ended December 31, 2015, our aggregate capital expenditures for drilling and infrastructure were $419.5 million. We do not have aspecific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. During the year ended December 31, 2015, we spentapproximately $437.5 million on acquisitions of leasehold interests. The amount and timing of these capital expenditures is 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. We currently intend to release one of ourthree horizontal drilling rigs in March 2016 and we have the option to release a second rig in the second quarter of 2016.Based upon current oil and natural gas price and production expectations for 2016, we believe that our cash flow from operations and borrowingsunder our revolving credit facility will be sufficient to fund our operations through year-end 2016. 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 2016 capital expenditure budget does not allocate any funds for leasehold interest and property 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 continues, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.62Table of ContentsContractual ObligationsThe following table summarizes our contractual obligations and commitments as of December 31, 2015: Payments Due by Period 2016 2017-2018 2019-2020 Thereafter Total (in thousands)Secured revolving credit facility(1)$— $11,000 $— $— $11,000Interest expense related to the secured revolving credit facility2,813 4,454 — — $7,267Senior notes— — — 450,000 $450,000Interest expense the senior notes(2)34,313 68,626 68,626 34,313 $205,878Viper's secured revolving credit facility(1)— — — 34,500 $34,500Interest and commitment fees under Viper's credit agreement(3)2,636 750 1,500 386 $5,272Asset retirement obligations (4)193 — — 12,518 $12,711Drilling commitments(5)29,536 36,759 589 — $66,884Operating lease obligations1,935 4,026 3,498 9,583 $19,042 $71,426$125,615$74,213$541,300 $812,554(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, 2015, 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 to future revisions based upon numerous factors, including the rateof inflation, changing technology and the political and regulatory environment. See Note 6 of the notes to our consolidated financial statements setforth 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, 2015.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.63Table of ContentsMethod 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.Oil 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 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, 2015, 2014 and 2013. Revenues from oil and natural gas services are recognized as services are provided.64Table of ContentsImpairmentWe 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 gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center 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 on the trailing12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs forproperties 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 ormarket value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis ofthe 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 is depreciated 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 inoil and natural 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 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 oil.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 aderivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedgingrelationship. None of our derivatives were designated as hedging instruments during the years ended December 31, 2015, 2014 and 2013. For derivativeinstruments not designated as hedging instruments, changes in the fair value of these instruments are recognized in earnings during the period of change.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.65Table of ContentsIncome 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 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 withcustomers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted.The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modifiedretrospective adoption, meaning the standard is applied only to the most current period presented. We are currently evaluating the impact, if any, that theadoption of this update will have on our financial position, results of operations and liquidity.In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. Thisupdate requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in thebalance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount to simplify the presentation of debt issuancecosts. The standard will be effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal yearsbeginning after December 15, 2016. Early application will be permitted for financial statements that have not previously been issued. Adoption of the newguidance will only affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements.In July 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-11, “Inventory”. This update applies to allinventory that is not measured using last-in, first-out or the retail inventory method. Under this update, an entity should measure inventory at the lower ofcost and net realizable value. This standard will be effective for financial statements issued for fiscal years beginning after December 15, 2016, includinginterim periods within those fiscal years. This standard should be applied prospectively with early adoption permitted as of the beginning of an interim orannual reporting period. We are currently evaluating the impact that the adoption of this update will have on our financial position, results of operations andliquidity.In November 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-17, “Income Taxes”. This update requiresthat deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard will be effective for financialstatements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application will be permittedas of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax liabilities and assets orretrospectively to all periods presented. Adoption of the new guidance will only affect the presentation of our consolidated balance sheets and will not have amaterial impact on our consolidated financial statements.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, 2015, 2014 and 2013. 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.66Table of ContentsOff-balance Sheet ArrangementsWe had no off-balance sheet arrangements as of December 31, 2015. 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 to reduce price volatility associated with certain of our oil sales. With respect to these fixed price swap contracts, thecounterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make apayment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reportedsettlement prices on commodity exchanges, with crude oil derivative settlements based on Argus Louisiana light sweet pricing. At December 31, 2015, we had a net asset derivative position of $4.6 million, related to our price swap derivatives, as compared to a net assetderivative position of $117.5 million as of December 31, 2014 related to our price swap derivatives. Utilizing actual derivative contractual volumes underour fixed price swaps as of December 31, 2015, a 10% increase in forward curves associated with the underlying commodity would have decreased the netasset position to $4.3 million, a decrease of $0.3 million, while a 10% decrease in forward curves associated with the underlying commodity would haveincreased the net asset derivative position to $5.0 million, an increase of $0.3 million. However, any cash derivative gain or loss would be substantially offsetby a decrease 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 $41.3 million at December 31,2015) and receivables from the sale of our oil and natural gas production (approximately $37.6 million at December 31, 2015).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, 2015, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company(59%); and Enterprise Crude Oil LLC (15%). For the year ended December 31, 2014, two purchasers accounted for more than 10% of our revenue: ShellTrading (US) Company (64%); and Enterprise Crude Oil LLC (16%). For the year ended December 31, 2013, two purchasers each accounted for more than10% of our revenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). No other customer accounted for more than 10% of our revenueduring 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, 2015, we had five customers that represented approximately 73% of our total joint operations receivables. At December 31, 2014, we hadtwo customer that represented approximately 61% 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 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of theloan outstanding67Table of Contentsin relation to the borrowing base. Our weighted-average interest rate on borrowings under our credit facility was 1.92% at December 31, 2015. An increase ordecrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $0.1 million based on the $11.0million outstanding in the aggregate under our revolving credit facility on December 31, 2015.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, 2015, 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, 2015, 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, 2015 that havematerially affected, or are reasonably likely to materially affect, internal controls over financial reporting.68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, 2015.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 31,2015. The report, which expresses an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting at December 31,2015, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm.”69Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMBoard of Directors and StockholdersDiamondback Energy, Inc.We have audited the internal control over financial reporting of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the“Company”) as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’sReport on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reportingbased on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained inall material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weaknessexists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures aswe considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of 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.In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, basedon 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), the consolidatedfinancial statements of the Company as of and for the year ended December 31, 2015, and our report dated February 19, 2016 expressed an unqualifiedopinion on those financial statements./s/ GRANT THORNTON LLPOklahoma City, OklahomaFebruary 19, 201670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, 2015.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, 2015.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, 2015.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, 2015.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, 2015.71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. 3. Exhibits The Exhibit Index beginning on page E–1 of this report is incorporated herein by reference. 72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 19, 2016 /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 19, 2016Steven E. West /s/ Travis D. Stice Chief Executive Officer and Director February 19, 2016Travis D. Stice (Principal Executive Officer) /s/ Michael P. Cross Director February 19, 2016Michael P. Cross /s/ David L. Houston Director February 19, 2016David L. Houston /s/ Mark L. Plaumann Director February 19, 2016Mark L. Plaumann /s/ Teresa L. Dick Chief Financial Officer, Senior Vice President, and Assistant Secretary February 19, 2016Teresa L. Dick (Principal Financial and Accounting Officer) S-1Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMBoard of Directors and StockholdersDiamondback Energy, Inc.We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (the“Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of thethree years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is toexpress an opinion on these financial statements based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditincludes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing theaccounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe thatour audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of DiamondbackEnergy, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in theperiod ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internalcontrol over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2016 expressed an unqualified opinion./s/ GRANT THORNTON LLPOklahoma City, OklahomaFebruary 19, 2016F-1Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Balance Sheets December 31, 2015 2014 (In thousands)Assets Current assets: Cash and cash equivalents$20,115 $30,183Restricted cash500 500Accounts receivable: Joint interest and other41,309 50,943Oil and natural gas sales36,004 43,050Related party1,591 4,001Inventories1,728 2,827Derivative instruments4,623 115,607Prepaid expenses and other2,875 4,600Total current assets108,745 251,711Property and equipment Oil and natural gas properties, based on the full cost method of accounting ($1,106,816 and $773,520excluded from amortization at December 31, 2015 and December 31, 2014, respectively)3,955,373 3,118,597Pipeline and gas gathering assets7,174 7,174Other property and equipment48,621 48,180Accumulated depletion, depreciation, amortization and impairment(1,413,543) (382,144)Net property and equipment2,597,625 2,791,807Derivative instruments— 1,934Other assets52,042 50,029Total assets$2,758,412 $3,095,481Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade$20,008 $26,230Accounts payable-related party217 —Accrued capital expenditures59,937 129,397Other accrued liabilities44,293 41,149Revenues and royalties payable16,966 30,000Deferred income taxes— 39,953Total current liabilities141,421 266,729Long-term debt495,500 673,500Asset retirement obligations12,518 8,447Deferred income taxes— 161,592Total liabilities649,439 1,110,268Commitments and contingencies (Note 15) Stockholders’ equity: Common stock, $0.01 par value, 100,000,000 shares authorized, 66,797,041 issued and outstanding atDecember 31, 2015; 56,887,583 issued and outstanding at December 31, 2014668 569Additional paid-in capital2,229,664 1,554,174Retained earnings(354,360) 196,268Total Diamondback Energy, Inc. stockholders’ equity1,875,972 1,751,011Noncontrolling interest233,001234,202Total equity2,108,973 1,985,213Total liabilities and equity$2,758,412 $3,095,481See accompanying notes to consolidated financial statements.F-2Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statements of Operations Year Ended December 31, 2015 2014 2013 (In thousands, except per share amounts)Revenues: Oil sales$405,715 $449,244 $188,753Natural gas sales16,952 8,662 3,715Natural gas sales - related party2,640 9,366 2,534Natural gas liquid sales18,882 13,408 8,304Natural gas liquid sales - related party2,544 15,038 4,696Total revenues446,733 495,718 208,002Costs and expenses: Lease operating expenses82,404 55,166 19,991Lease operating expenses - related party221 218 1,166Production and ad valorem taxes32,837 31,160 12,399Production and ad valorem taxes - related party153 1,478 500Gathering and transportation5,122 618 237Gathering and transportation - related party969 2,670 681Depreciation, depletion and amortization217,697 170,005 66,597Impairment of oil and natural gas properties814,798 — —General and administrative expenses (including non-cash equity-based compensation,net of capitalized amounts, of $18,529, $9,816 and $1,752 for the year endedDecember 31, 2015, 2014 and 2013, respectively)29,640 19,921 9,870General and administrative expenses - related party2,328 1,345 1,166Asset retirement obligation accretion expense833 467 201Total costs and expenses1,187,002 283,048 112,808Income (loss) from operations(740,269) 212,670 95,194Other income (expense) Interest income (expense)(41,510) (34,514) (8,058)Other income567 556 —Other income - related party161 121 1,077Other expense— (1,416) —Gain (loss) on derivative instruments, net31,951 127,539 (1,872)Total other income (expense), net(8,831) 92,286 (8,853)Income (loss) before income taxes(749,100) 304,956 86,341Provision for (benefit from) income taxes(201,310) 108,985 31,754Net income (loss)(547,790) 195,971 54,587Less: Net income attributable to noncontrolling interest2,838 2,216 —Net income (loss) attributable to Diamondback Energy, Inc.$(550,628) $193,755 $54,587 Earnings per common share Basic$(8.74) $3.67 $1.30Diluted$(8.74) $3.64 $1.29Weighted average common shares outstanding Basic63,019 52,826 42,015Diluted63,019 53,297 42,255See accompanying notes to consolidated financial statements.F-3Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statement of Stockholders’ Equity Common Stock AdditionalPaid-inCapital RetainedEarnings Non-ControllingInterest SharesAmount Total (In thousands)Balance December 31, 201236,986$370 $513,772 $(52,074) $— $462,068Stock-based compensation—— 2,724 — — 2,724Tax benefits related to stock-based compensation—— 749 — — 749Common shares issued in public offering, net of offeringcosts9,77598 321,814 — — 321,912Exercise of stock options and vesting of restricted stockunits3453 3,498 — — 3,501Net income—— — 54,587 — 54,587Balance December 31, 201347,106471 842,557 2,513 — 845,541Net proceeds from issuance of common units - ViperEnergy Partners LP—— — — 232,198 232,198Unit-based compensation—— — — 2,102 2,102Distribution to noncontrolling interest—— — — (2,314) (2,314)Stock-based compensation—— 12,152 — — 12,152Tax benefits related to stock-based compensation—— (749) — — (749)Common shares issued in public offering, net of offeringcosts9,20092689,390 — — 689,482Exercise of stock options and awards of restricted stock5185 7,075 — — 7,080Equity payment- Wexford Advisory Services (See Note11)641 3,749 — — 3,750Net income—— — 193,755 2,216 195,971Balance December 31, 201456,888569 1,554,174 196,268 234,202 1,985,213Unit-based compensation—— — — 3,929 3,929Stock-based compensation—— 20,645 — — 20,645Distribution to noncontrolling interest—— — — (7,968) (7,968)Common shares issued in public offering, net of offeringcosts9,48894649,979 — — 650,073Exercise of stock options and awards of restricted stock4215 4,866 — — 4,871Net income (loss)—— — (550,628) 2,838 (547,790)Balance December 31, 201566,797$668 $2,229,664 $(354,360) $233,001 $2,108,973See accompanying notes to consolidated financial statements.F-4Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statements of Cash Flows Year Ended December 31, 2015 2014 2013 (In thousands)Cash flows from operating activities: Net income (loss)$(547,790) $195,971 $54,587Adjustments to reconcile net income (loss) to net cash provided by operating activities: Provision for (benefit from) deferred income taxes(201,545) 108,985 31,563Excess tax benefit from stock-based compensation— — (749)Impairment of oil and natural gas properties814,798 — —Asset retirement obligation accretion expense833 467 201Depreciation, depletion, and amortization217,697 170,005 66,597Amortization of debt issuance costs2,601 2,125 1,018Change in fair value of derivative instruments112,918 (117,109) (5,346)Equity-based compensation expense18,529 9,816 1,752(Gain) loss on sale of assets, net668 1,396 (39)Changes in operating assets and liabilities: Accounts receivable8,998 (39,442) (19,973)Accounts receivable-related party2,149 (2,699) (532)Restricted cash— (500) —Inventories224 915 554Prepaid expenses and other(1,310) (4,601) (271)Accounts payable and accrued liabilities802 6,829 20,588Accounts payable and accrued liabilities-related party218 (17) (128)Accrued interest(255) 3,473 —Revenues and royalties payable(13,034) 20,775 5,955Net cash provided by operating activities416,501 356,389 155,777Cash flows from investing activities: Additions to oil and natural gas properties(419,241) (494,708) (278,809)Additions to oil and natural gas properties-related party(271) (3,631) (13,777)Acquisition of Gulfport properties— — (18,550)Acquisition of royalty interests(43,907) (57,689) (444,083)Acquisition of leasehold interests(437,455) (845,826) (177,343)Pipeline and gas gathering assets— (1,509) (5,127)Purchase of other property and equipment(1,213) (44,213) (2,234)Proceeds from sale of assets9,739 56 72Equity investments(2,702) (34,477) —Settlement of non-hedge derivative instruments— — (289)Net cash used in investing activities(895,050) (1,481,997) (940,140)Cash flows from financing activities: Proceeds from borrowings on credit facility425,001 509,400 59,000Repayment on credit facility(603,001) (295,900) (49,000)Proceeds from senior notes— — 450,000Debt issuance costs(526) (3,469) (12,361)Public offering costs(586) (2,994) (1,009)Proceeds from public offerings650,688 928,432 322,680Exercise of stock options4,873 7,081 3,501Excess tax benefits of stock-based compensation— — 749Distribution to non-controlling interest(7,968) (2,314) —F-5Table of ContentsDiamondback Energy, Inc. and SubsidiariesConsolidated Statements of Cash Flows - Continued Year Ended December 31, 2015 2014 2013 (In thousands)Net cash provided by financing activities468,481 1,140,236 773,560Net increase (decrease) in cash and cash equivalents(10,068) 14,628 (10,803)Cash and cash equivalents at beginning of period30,183 15,555 26,358Cash and cash equivalents at end of period$20,115 $30,183 $15,555 Year Ended December 31, 2015 2014 2013 (In thousands)Supplemental disclosure of cash flow information: Interest paid, net of capitalized interest$38,758 $31,621 $404Cash paid for income taxes$267 $— $—Supplemental disclosure of non-cash transactions: Asset retirement obligation incurred$594 $703 $226Asset retirement obligation revisions in estimated liability$(69) $588 $—Asset retirement obligation acquired$3,159 $3,726 $471Change in accrued capital expenditures$(69,460) $54,748 $45,252Capitalized stock-based compensation$6,043 $4,437 $972See 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, 2015, 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 White FangEnergy LLC, a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries 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, 2015, the Company owned approximately 88% 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 estimates of proved oil and natural gas reservesand related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fairvalue determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of incometaxes. 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 CashA subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. Theagreement provided that the subsidiary would have the right to terminate the agreement and receive a return of the deposit if the subsidiary in good faithasserted title defects in excess of a certain amount. The subsidiary asserted title defects in excess of the amount and requested that the escrow agent return thedeposit. The seller provided the escrow agent with notice alleging the subsidiary did not timely assert the defects in good faith. The escrow agent tenderedthe deposit to the court subject to a judicial determination of the proper payment of the funds.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 are received within three monthsafter 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, 2015 or December 31, 2014.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 in theconsolidated statements of operations.Fair Value of Financial InstrumentsThe Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives, notes payable andsenior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of theinstruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Companyfor bank loans with similar terms and maturities. The note payable is carried at cost, which approximates fair value due to the nature of the instrument andrelatively short maturity. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14–FairValue 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. All internalF-8Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gasproperties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless suchadjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any incomefrom services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed relatedcosts incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in thesubsidiary (see Note 7–Equity Method Investments). 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. The average depletion rate per barrel equivalentunit of production was $17.84, $23.79 and $24.63 for the years ended December 31, 2015, 2014 and 2013, respectively. Depreciation, depletion andamortization expense for oil and natural gas properties was $216.1 million, $168.7 million and $65.8 million for the years ended December 31, 2015, 2014and 2013, 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 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. During the year ended December 31, 2015, the Company recorded an impairment on proved oil and natural gas properties of $814.8 million. Noimpairment on proved oil and natural gas properties was recorded for the years ended December 31, 2014 and 2013, respectively.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 and EquipmentOther 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 $1.6 million, $1.3 million and $0.8 million for the years endedDecember 31, 2015, 2014 and 2013, respectively.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, the difference is recorded in oil and natural 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, 2015, 2014 and 2013, 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 $5.3 million and $4.0 million amounts for the years ended December 31, 2014 and 2013,respectively. The Company did not have any capitalized interest for the year ended December 31, 2015.InventoriesInventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2015 and 2014. 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, 2015, the Company estimated that all of its tubular goods and equipment will be utilized within one year.Debt Issuance CostsOther assets included capitalized costs of $18.2 million and $13.8 million, net of accumulated amortization of $6.5 million and $3.9 million, as ofDecember 31, 2015 and 2014, respectively. The costs associated with the Senior Notes are being amortized over the term of the Senior Notes using theeffective interest method. The costs associated with the Company’s credit facility are being amortized over the term of the facility.Other Accrued LiabilitiesOther accrued liabilities consist of the following: December 31, 2015 2014 (In thousands)Prepaid drilling liability$12,683 $3,758Interest payable8,606 8,861Lease operating expense payable14,100 11,851Taxes payable518 9,952Current portion of asset retirement obligations193 39Other8,193 6,688Total other accrued liabilities$44,293 $41,149Revenue 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 applicable to other revenue and royalty owners are reflected asrevenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil andnatural gas properties.F-10Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)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, 2015 or December 31, 2014. Revenues from oil andnatural gas services are recognized as 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, 2015, 2014 and 2013.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. These plans and related accountingpolicies are defined and described more fully in Note 10–Equity-Based Compensation. Stock compensation awards are measured at fair value on the date ofgrant 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, 2015, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company (59%); andEnterprise Crude Oil LLC (15%). For the year ended December 31, 2014, two purchasers accounted for more than 10% of our revenue: Shell Trading (US)Company (64%); and Enterprise Crude Oil LLC (16%). For the year ended December 31, 2013, two purchasers each accounted for more than 10% of ourrevenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). The Company does not require collateral and does not believe the loss ofany single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets andnumerous 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 (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilitiesand (2) 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 recognizedin 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, 2015, 2014 and 2013, there was no margin taxexpense. The Company’s 2011, 2012, 2013, 2014 and 2015 federal income tax and state margin tax returns remain open to examination by tax authorities.As of December 31, 2015 and December 31, 2014, the Company had no unrecognized tax benefits that would have a material impact on the effective rate.The Company is continuing its practice ofF-11Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the yearsended December 31, 2015, 2014 and 2013, there was no interest or penalties associated with uncertain tax positions recognized in the Company’sconsolidated financial statements.Recent Accounting 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 withcustomers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted.The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modifiedretrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact, if any,that the adoption of this update will have on the Company’s financial position, results of operations and liquidity.In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. Thisupdate requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in thebalance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount to simplify the presentation of debt issuancecosts. The standard will be effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal yearsbeginning after December 15, 2016. Early application will be permitted for financial statements that have not previously been issued. Adoption of the newguidance will only affect the presentation of the Company’s consolidated balance sheets and will not have a material impact on its consolidated financialstatements.In July 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-11, “Inventory”. This update applies to allinventory that is not measured using last-in, first-out or the retail inventory method. Under this update, an entity should measure inventory at the lower ofcost and net realizable value. This standard will be effective for financial statements issued for fiscal years beginning after December 15, 2016, includinginterim periods within those fiscal years. This standard should be applied prospectively with early adoption permitted as of the beginning of an interim orannual reporting period. The Company is currently evaluating the impact that the adoption of this update will have on the Company’s financial position,results of operations and liquidity.In November 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-17, “Income Taxes”. This update requiresthat deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard will be effective for financialstatements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application will be permittedas of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax liabilities and assets orretrospectively to all periods presented. Adoption of the new guidance will only affect the presentation of the Company’s consolidated balance sheets andwill not have a material impact on its consolidated financial statements.3. ACQUISITIONS2015 ActivitySince January 1, 2015, the Company has 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, subject tocertain adjustments. The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired andconsideration transferred at fair value. These acquisitions were funded with the net proceeds of the May 2015 equity offering discussed in Note 9–CapitalStock and Earnings Per Share and borrowings under 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.F-12Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)2014 ActivityOn September 9, 2014, the Company completed the acquisition of oil and natural gas interests in the Permian Basin from unrelated third partysellers. The Company acquired approximately 17,617 gross (12,967 net) acres with an approximate 74% working interest (approximately 75% net revenueinterest). The acquisition was accounted for according to the acquisition method, which requires the recording of net assets acquired and considerationtransferred at fair value. This acquisition was funded with the net proceeds of the July 2014 equity offering and borrowings under the Company’s revolvingcredit facility discussed in Note 8–Debt.The following represents the estimated fair values of the assets and liabilities assumed on the acquisition date. The aggregate considerationtransferred was $523.3 million in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain. (in thousands)Joint interest receivables$42Proved oil and natural gas properties128,589Unevaluated oil and natural gas properties400,527Total assets acquired529,158Accrued production and ad valorem taxes358Revenues payable3,174Asset retirement obligations2,366Total liabilities assumed5,898Total fair value of net assets$523,260The Company has included in its consolidated statements of operations revenues of $12.3 million and direct operating expenses of $4.6 million forthe period from September 9, 2014 to December 31, 2014 due to the acquisition. The disclosure of net earnings is impracticable to calculate due to the fullcost method of depletion.On August 25, 2014, the Company completed an acquisition of surface rights in the Permian Basin from an unrelated third party seller. TheCompany acquired surface rights to approximately 4,200 acres for approximately $41.9 million.On February 27 and 28, 2014, the Company completed acquisitions of oil and natural gas interests in the Permian Basin from unrelated third partysellers. The Company acquired approximately 6,450 gross (4,785 net) acres with a 74% working interest (56% net revenue interest). 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 February 2014 equity offering and borrowings under the Company’s revolving credit facility discussedin Note 8–Debt.The following represents the estimated fair values of the assets and liabilities assumed on the acquisition dates. The aggregate considerationtransferred was $292.2 million in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain. (in thousands)Proved oil and natural gas properties$170,174Unevaluated oil and natural gas properties123,243Total assets acquired293,417Asset retirement obligations1,258Total liabilities assumed1,258Total fair value of net assets$292,159The Company has included in its consolidated statements of operations revenues of $40.5 million and direct operating expenses of $7.8 million forthe period from February 28, 2014 to December 31, 2014 due to the acquisitions. The disclosure of net earnings is impracticable to calculate due to the fullcost method of depletion.F-13Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)During the year ended December 31, 2014, the Partnership acquired (i) mineral interests underlying an aggregate of approximately 10,364 gross(3,261 net) acres in the Midland and Delaware basins for approximately $57.7 million and (ii) a minor equity interest in an entity that owns mineral,overriding royalty, net profits, leasehold and other similar interests for approximately $33.9 million. The equity interest is so minor that we have no influenceover partnership operating and financial policies and is accounted for under the cost method.Pro Forma Financial InformationThe following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2014 and2013 have been prepared to give effect to the February 27 and 28, 2014 acquisitions and the September 9, 2014 acquisition as if they had occurred onJanuary 1, 2013. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred onJanuary 1, 2013. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not beviewed as indicative of operations in future periods. Pro Forma (Unaudited) Year Ended December 31, 2014 2013 (in thousands)Revenues$541,103 $315,736Income from operations224,382 146,429Net income201,257 86,2772013 ActivityIn September 2013, the Company completed two separate acquisitions of additional leasehold interests in the Permian Basin from unrelated thirdparty sellers for an aggregate purchase price of $165.0 million, subject to certain adjustments. The first of these acquisitions closed on September 4, 2013when the Company acquired certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest (80% net revenue interest)in 4,506 gross and net acres. The second of these acquisitions closed on September 26, 2013, when the Company acquired certain assets located primarily insouthwestern Dawson County, Texas, consisting of a 71% working interest (55% net revenue interest) in 9,390 gross (6,638 net) acres. These acquisitionswere funded with a portion of the net proceeds from the August 2013 equity offering discussed in Note 9–Capital Stock and Earnings Per Share.On September 19, 2013, the Company completed the acquisition of the mineral interests underlying approximately 14,804 gross (12,687 net) acresin Midland County, Texas in the Permian Basin. As part of the closing of the acquisition, the mineral interests were conveyed from the previous owners toViper Energy Partners LLC and, subsequently, were contributed to the Partnership on June 17, 2014. See Note 4 – Viper Energy Partners LP for additionalinformation regarding the Partnership. The mineral interests entitle the holder of such interests to receive a 21.4% royalty interest on all production on anacreage weighted basis from this acreage with no additional future capital or operating expense required. The $440.0 million purchase price was funded withthe net proceeds of the Company’s offering of Senior Notes 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, afully-consolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As ofDecember 31, 2015, the Company owned approximately 88% 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%F-14Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)of the limited partner interests in the Partnership at a price to the public of $26.00 per common unit, which included 750,000 common units issued pursuantto an option to purchase additional common units granted to the underwriters on the same terms. The Partnership received proceeds of approximately $137.2million from the sale of these common units, net of offering expenses and underwriting discounts and commissions.In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership inexchange for 70,450,000 common units. In addition, in connection with the closing of the Viper Offering, the Partnership agreed to distribute toDiamondback all cash and cash equivalents and the royalty income receivable on hand in the aggregate amount of approximately $11.3 million and the netproceeds from the Viper Offering. As of December 31, 2014, the Partnership had distributed $148.8 million to Diamondback and the Partnership recorded apayable balance of approximately $11.3 million. The contribution of Viper Energy Partners LLC to the Partnership was accounted for as a combination ofentities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. During the yearended December 31, 2015, the Partnership distributed $60.6 million to Diamondback in respect of its common units.On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. The common units were sold to thepublic at $28.50 per unit and the Partnership received proceeds of approximately $94.8 million from the sale of these common units, net of offering expensesand underwriting discounts and commissions.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 had the tax attributes not been available or used for thePartnership’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.F-15Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)5. PROPERTY AND EQUIPMENTProperty and equipment includes the following: December 31, 2015 2014 (in thousands)Oil and natural gas properties: Subject to depletion$2,848,557 $2,345,077Not subject to depletion-acquisition costs Incurred in 2015433,769 —Incurred in 2014543,399 576,802Incurred in 201368,351 130,474Incurred in 201261,297 65,480Incurred in 2011— 764Total not subject to depletion1,106,816 773,520Gross oil and natural gas properties3,955,373 3,118,597Accumulated depletion(512,144) (296,317)Accumulated impairment(897,962) (83,164)Oil and natural gas properties, net2,545,267 2,739,116Pipeline and gas gathering assets, net7,174 7,174Other property and equipment, net48,621 48,180Accumulated depreciation(3,437) (2,663)Property and equipment, net of accumulated depreciation, depletion, amortization and impairment$2,597,625 $2,791,807The 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. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalizedinternal costs were approximately $15.2 million $11.4 million and $5.3 million for the years ended December 31, 2015, 2014 and 2013, respectively. Costsassociated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of provedreserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Sales of oil andnatural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unlesssuch adjustments would significantly alter the relationship between capitalized costs and 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 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.As a result of the significant decline in prices during 2015, the Company recorded non-cash ceiling test impairments for the year endedDecember 31, 2015 of $814.8 million, which is included in accumulated depletion. The Company did not have any impairment of its proved oil and naturalgas properties during 2014. The impairment charge affected the Company’s reported net income but did not reduce its cash flow. In addition to commodityprices, the Company’s production rates, levelsF-16Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation andimpairment analysis in future periods.6. ASSET RETIREMENT OBLIGATIONSThe following table describes the changes to the Company’s asset retirement obligation liability for the following periods: Year Ended December 31, 2015 2014 2013 (in thousands)Asset retirement obligation, beginning of period$8,486 $3,029 $2,145Additional liability incurred594 703 226Liabilities acquired3,159 3,726 471Liabilities settled(292) (27) (14)Accretion expense833 467 201Revisions in estimated liabilities(69) 588 —Asset retirement obligation, end of period12,711 8,486 3,029Less current portion193 39 40Asset retirement obligations - long-term$12,518 $8,447 $2,989The 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 paid $0.6 million for a 25% 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. The Company has committed to invest an aggregate amount of $5.0 million in this entity, and several otherthird parties have committed to invest an aggregate of $15.0 million. For the year ended December 31, 2015, the Company invested an additional $2.7million in this entity. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability companyand maintains a specific ownership account for each investor, similar to a partnership capital account structure. Therefore, the Company accounts for thisinvestment under the equity method of accounting.8. DEBTLong-term debt consisted of the following as of the dates indicated: December 31, 2015 2014 (in thousands)7.625 % Senior Notes due 2021$450,000 $450,000Revolving credit facility$11,000 $223,500Partnership revolving credit facility34,500 —Total long-term debt$495,500 $673,500F-17Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Senior NotesOn September 18, 2013, the Company completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due2021 (the “Senior Notes”). The Senior Notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of eachyear, commencing on April 1, 2014 and will mature on October 1, 2021. On June 23, 2014, in connection with the Viper Offering, the Company designatedthe Partnership, the General Partner and Viper Energy Partners LLC as unrestricted subsidiaries and, upon such designation, Viper Energy Partners LLC,which was a guarantor under the indenture governing of the Senior Notes, was released as a guarantor under the indenture. As of December 31, 2015, theSenior Notes were fully and unconditionally guaranteed by Diamondback O&G LLC, Diamondback E&P LLC and White Fang Energy LLC and will also beguaranteed by any future restricted subsidiaries of Diamondback. The net proceeds from the Senior Notes were used to fund the acquisition of mineralinterests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin.The 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 “Indenture”). The 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, or redeem or repurchase, capital stock, prepay subordinated indebtedness, sell assetsincluding capital stock of 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 gas business anddesignate certain of the Company’s subsidiaries as unrestricted subsidiaries. If the Company experiences certain kinds of changes of control or if it sellscertain of its assets, holders of the Senior Notes may have the right to require the Company to repurchase their Senior Notes.The Company will have the option to redeem the Senior Notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices(expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month periodbeginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at anytime thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, the Company mayredeem all or a part of the Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemptiondate, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, the Company may, at any time or from time to time, redeemup to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% ofthe principal amount of the Senior Notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregateprincipal amount of the Senior Notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemptionoccurs within 120 days of the closing date of such equity offering.In connection with the issuance of the Senior Notes, the Company and the subsidiary guarantors entered into a Registration Rights Agreement (the“Registration Rights Agreement”) with the initial purchasers on September 18, 2013, pursuant to which the Company and the subsidiary guarantors agreed tofile a registration statement with respect to an offer to exchange the Senior Notes for a new issue of substantially identical debt securities registered under theSecurities Act, which exchange offer completed on October 23, 2014.The Company’s Credit FacilityOn June 9, 2014, Diamondback O&G LLC, as borrower, entered into a first amendment and on November 13, 2014, Diamondback O&G LLC enteredinto a second amendment to the second amended and restated credit agreement, dated November 1, 2013 (the “credit agreement”). The first amendmentmodified certain provisions of the credit agreement to, among other things, allow one or more of the Company’s subsidiaries to be designated as“Unrestricted Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with the Viper Offering, thePartnership, the General Partner and Viper Energy Partners LLC were designated as unrestricted subsidiaries under the credit agreement. As of December 31,2015, the credit agreement was guaranteed by Diamondback, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any futurerestricted subsidiaries of Diamondback. The credit agreement is also secured by substantially all of the assets of Diamondback O&G LLC, the Company andthe other guarantors.The second amendment increased the maximum amount of the credit facility to $2.0 billion, modified the dates and deadlines of the creditagreement relating to the scheduled borrowing base redeterminations based on the Company’s oil andF-18Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)natural gas reserves and other factors and added new provisions that allow the Company to elect a commitment amount that is less than its borrowing base asdetermined by the lenders. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition,the Company may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2015, theborrowing base was set at $750.0 million, of which the Company had elected a commitment amount of $500.0 million, and the Company had outstandingborrowings of $11.0 million.The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is equal to an alternative base rate (whichis 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 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR,in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitmentfee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstandingin relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBORbreakage), and is required to be repaid (a) to the extent that the loan amount exceeds 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, 2018.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 $750.0 million in the form of senior or seniorsubordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each suchissuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As ofDecember 31, 2015, the Company had $450.0 million of senior unsecured notes outstanding.As of December 31, 2015 and December 31, 2014, the Company was in compliance with all financial covenants under its revolving credit facility, asthen in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during thecontinuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materiallyincorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principaland breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cureperiods.The Partnership’s Credit AgreementOn July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runnerand lead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, provides for a revolving creditfacility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based onthe Partnership’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be re-determined semi-annually with effective dates ofApril 1st and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period.The credit agreement was further amended on May 22, 2015 to, among other things, increase the borrowing base from $110.0 million to $175.0 million andto provide for certain restrictions on purchasing margin stock. On November 13, 2015, the borrowing base was increased from $175.0 million to $200.0million. As of December 31, 2015, the borrowing base was set at $200.0 million. The Partnership had $34.5 million outstanding under its credit agreement.The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is 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-F-19Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternativebase rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, whichfee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to timewithout premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds theborrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8,2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiaries.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 $250.0 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, 2015, 2014 and 2013: Year Ended December 31, 2015 2014 2013 (in thousands)Interest expense$40,221 $36,669 $10,322Less capitalized interest— (5,275) (3,951)Other fees and expenses1,292 3,121 1,688Total interest expense41,513 34,515 8,0599. CAPITAL STOCK AND EARNINGS PER SHAREAs of December 31, 2015, Diamondback had completed the following equity offerings since the closing of its initial public offering on October 17,2012:In May 2013, the Company completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 pershare and the Company received proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.F-20Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)In August 2013, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares ofcommon stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $40.25 per shareand the Company received proceeds of approximately $177.5 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.In February 2014, the Company completed an underwritten public offering of 3,450,000 shares of common stock, which included 450,000 shares ofcommon stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $62.67 per shareand the Company received proceeds of approximately $208.4 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.In July 2014, the Company completed an underwritten public offering of 5,750,000 shares of common stock, which included 750,000 shares ofcommon stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $87.00 per shareand the Company received proceeds of approximately $485.0 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.In January 2015, the Company completed an underwritten public offering of 2,012,500 shares of common stock, which included 262,500 shares ofcommon stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $59.34 per shareand the Company received proceeds of approximately $119.4 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.In May 2015, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares ofcommon stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $72.53 per shareand the Company received proceeds of approximately $333.6 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.In August 2015, the Company completed an underwritten public offering of 2,875,000 shares of common stock, which included 375,000 shares ofcommon stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $68.74 per shareand the Company received proceeds of approximately $197.6 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.Earnings Per ShareThe Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stockoutstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the dilutedearnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on theconsolidated group’s holdings of the subsidiary.A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: 2015 Income Shares Per Share (in thousands, except per share amounts)Basic: Net income attributable to common stock$(550,628) 63,019 $(8.74)Effect of Dilutive Securities: Dilutive effect of potential common shares issuable$— — Diluted: Net income attributable to common stock$(550,628) 63,019 $(8.74)F-21Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued) 2014 Income Shares Per Share (in thousands, except per share amounts)Basic: Net income attributable to common stock$193,755 52,826 $3.67Effect of Dilutive Securities: Dilutive effect of potential common shares issuable$— 471 Diluted: Net income attributable to common stock$193,755 53,297 $3.64 2013 Income Shares Per Share (in thousands, except per share amounts)Basic: Net income attributable to common stock$54,587 42,015 $1.30Effect of Dilutive Securities: Dilutive effect of potential common shares issuable$— 240 Diluted: Net income attributable to common stock$54,587 42,255 $1.29For the year ended December 31, 2015, there were 100,924 shares that were not included in the computation of diluted earnings per share becausetheir inclusion would have been anti-dilutive for the periods presented but could potentially 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.The following table presents the effects of the equity and stock based compensation plans and related costs: 2015 2014 2013 (In thousands)General and administrative expenses$18,529 $9,816 $1,752Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gasproperties6,043 4,437 972Related income tax benefit— — 704On 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 of9,144,000 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.F-22Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)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 a summary of the weighted average grant-date fair values and related assumptions for 2013. No stock options weregranted during the years ended December 31, 2015 and 2014. 2013Grant-date fair value$6.51Expected volatility36.9%Expected dividend yield0.0%Expected term (in years)3.8Risk-free rate0.57%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, 2015. Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in thousands)Outstanding at December 31, 2014313,105 $18.29 Exercised(273,605) $17.80 Outstanding at December 31, 201539,500 $21.66 1.83 $1,787Vested and Expected to vest at December 31, 201539,500 $21.66 1.83 $1,787Exercisable at December 31, 20158,000 $17.50 0.78 $395The aggregate intrinsic value of stock options that were exercised during the year ended December 31, 2015, 2014 and 2013 was $15.7 million,$22.0 million and $5.7 million, respectively. As of December 31, 2015, the unrecognized compensation cost related to unvested stock options was $0.1million. Such cost is expected to be recognized over a weighted-average period of 1.1 years.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, 2015. Restricted StockAwards & Units Weighted Average Grant-DateFair ValueUnvested at December 31, 2014167,291 $49.99Granted138,534 $68.54Vested(143,956) $42.58Forfeited(2,110) $74.14Unvested at December 31, 2015159,759 $64.66The aggregate fair value of restricted stock units that vested during the year ended December 31, 2015, 2014 and 2013 was $10.1 million, $8.2million and $3.3 million, respectively. As of December 31, 2015, the Company’s unrecognized compensation cost related to unvested restricted stock awardsand units was $6.0 million. Such cost is expected to be recognized over a weighted-average period of 1.6 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 2014, eligible employees received initial performance restricted stock unit awards totaling 79,150 units from which a minimum of 0%and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2013 to December 31, 2015 and vested at December31, 2015, subject to certification by the compensation committee that the performance standards were satisfied.In February 2015, eligible employees received additional performance restricted stock unit awards totaling 90,249 units from which a minimum of0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2014 to December 31, 2016 and cliff vest atDecember 31, 2016.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. 2015 2014Grant-date fair value$137.14 $125.63Risk-free rate0.49% 0.30%Company volatility43.36% 39.60%The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the year ended December 31, 2015. PerformanceRestricted Stock Units Weighted AverageGrant-Date Fair ValueUnvested at December 31, 201479,150 $125.63Granted90,249 $137.14Vested(79,150) $125.63Unvested at December 31, 2015 (1)90,249 $137.14(1)A maximum of 180,498 units could be awarded based upon the Company’s final TSR ranking.F-24Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)As of December 31, 2015, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and unitswas $6.5 million. Such cost is expected to be recognized over a weighted-average period of 1.0 year.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). Vested unit options will be automatically exercisedupon the earlier of a change of control or the third anniversary of the grant date unless extended in accordance with the terms of the Viper LTIP (the “ExerciseDate”). In the event the fair market value per unit as of the exercise date is less than the exercise price per option unit then the vested options willautomatically terminate and become null and void as of the exercise date.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. 2014Grant-date fair value$4.24Expected volatility36.0%Expected dividend yield5.9%Expected term (in years)3.0Risk-free rate0.99%The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2015. Weighted Average Unit Options Exercise Price RemainingTerm Intrinsic Value (in years) (in thousands)Outstanding at December 31, 20142,500,000 $26.00 Granted— $— Outstanding at December 31, 20152,500,000 $— 1.50 $— Vested and Expected to vest at December 31, 20152,500,000 $— 1.50 $—Exercisable at December 31, 2015— $— 0.00 $—As of December 31, 2015, the unrecognized compensation cost related to unvested unit options was $5.2 million. Such cost is expected to berecognized over a weighted-average period of 1.5 years. 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.F-25Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2015. Phantom Units Weighted AverageGrant-DateFair ValueUnvested at December 31, 201417,776 $19.51Granted24,690 $15.48Vested(17,118) $17.57Unvested at December 31, 201525,348 $16.89The aggregate fair value of phantom units that vested during the year ended December 31, 2015 was $0.3 million. As of December 31, 2015, theunrecognized compensation cost related to unvested phantom units was $0.3 million. Such cost is expected to be recognized over a weighted-average periodof 1.2 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, 2015, Wexford beneficially owned less than 1% of the Company’s outstanding commonstock. A partner at Wexford serves as Chairman of the Board of Directors of each of the Company and the General Partner. Another partner at Wexford serves amember of the Board of Directors of the General Partner.Administrative ServicesAn entity then under common management with the Company provided technical, administrative and payroll services to the Company under ashared services agreement which began March 1, 2008. The initial term of this shared service agreement was two years. Since the expiration of such two-yearperiod on March 1, 2010, the agreement, by its terms continued on a month-to-month basis. Effective August 31, 2014, this agreement was mutuallyterminated. For the years ended December 31, 2014 and 2013, the Company incurred total costs of less than $0.1 million and $0.2 million, respectively.Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration and development of proved oil and natural gasproperties have been capitalized. The Company had no outstanding amount payable at December 31, 2014 and owed the administrative services affiliate lessthan $0.1 million at December 31, 2013.Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Companyprovided this entity and, at its request, certain affiliates, with consulting, technical and administrative services. The initial term of the additional sharedservices agreement was two years. Thereafter, the agreement continued on a month-to-month basis subject to the right of either party to terminate theagreement upon 30 days, prior written notice. Effective August 31, 2014, this agreement was mutually terminated. Costs that are attributable to and billed toother affiliates are reported as other income-related party. For the years ended December 31, 2014 and 2013, the affiliate reimbursed the Company $0.1million and $1.1 million, respectively, for services under the shared services agreement. As of December 31, 2014, the affiliate owed the company less than$0.1 million. As of December 31, 2013, the affiliate had no outstanding amounts payable to the Company.Drilling ServicesBison Drilling and Field Services LLC (“Bison”), an entity controlled by Wexford, has performed drilling and field services for the Company undermaster drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bisoncommitted to accept orders from the Company for the use of at least two of its rigs. As of December 31, 2015 and December 31, 2014, the Company was notutilizing any Bison rigs. This master drilling agreement is terminable by either party on 30 days’ prior written notice, although neither party will be relievedof its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the year endedDecember 31, 2015, the Company did not incur any costs for services performed by Bison. For the years ended December 31, 2014 and 2013, the Companyincurred total costs for services performed by Bison of $3.5 million and $13.9 million, respectively. Bison is an affiliate of Wexford.Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC, under which Panther DrillingSystems LLC provides directional drilling and other services. This master service agreementF-26Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)is terminable by either party on 30 days’ prior written notice, although neither party will be relieved of its respective obligations arising from work performedprior to the termination of the master service agreement. In the third quarter 2013, the Company began using Panther Drilling Systems LLC’s directionaldrilling services. For the year ended December 31, 2015, Panther Drilling Systems LLC did not perform any services for the Company. The Company incurred$0.3 million and $0.2 million for services performed for the years ended December 31, 2014 and 2013, respectively. Panther Drilling Systems LLC is anaffiliate of Wexford.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 affiliated with Wexford, that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, CoronadoMidstream LLC is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream LLC, all of the gas conforming tocertain quality specifications produced from certain of the Company’s Permian Basin acreage. Following the expiration of the initial ten year term, theagreement will continue on a year-to-year basis until terminated by either party on 30 days’ written notice. Under the gas purchase agreement, CoronadoMidstream LLC is obligated to pay the Company 87% of the net revenue received by Coronado Midstream LLC for all components of the Company’sdedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at CoronadoMidstream LLC’s gas processing plant, and 94.56% of the net revenue received by Coronado Midstream LLC from the sale of such gas components andresidue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. An entity controlled by Wexford had owned approximately 28% equityinterest in Coronado Midstream LLC until Coronado Midstream LLC was sold in March 2015. Coronado Midstream LLC is no longer a related party and anyrevenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified as those attributable to a relatedparty. The Company recognized revenues from Coronado Midstream LLC of $5.2 million for the three months ended March 31, 2015. The Companyrecognized revenues from Coronado Midstream LLC of $24.4 million and $7.2 million for the years ended December 31, 2014 and 2013, respectively. TheCompany recognized production and ad valorem taxes and gathering and transportation expenses from Coronado Midstream LLC of $1.1 million for thethree months ended March 31, 2015. The Company recognized production and ad valorem taxes and gathering and transportation expenses from CoronadoMidstream LLC of $4.1 million and $1.2 million for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, CoronadoMidstream owed the Company $4.0 million for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas.Sand SupplyMuskie Proppant LLC (“Muskie”), an entity affiliated with Wexford, processes and sells fracing grade sand for oil and natural gas operations. TheCompany began purchasing sand from Muskie in March 2013. On May 16, 2013, the Company entered into a master services agreement with Muskie,pursuant to which Muskie agreed to sell custom natural sand proppant to the Company based on the Company’s requirements. The Company is not obligatedto place any orders with, or accept any offers from, Muskie for sand proppant. The agreement may be terminated at the option of either party on 30 days’notice. The Company did not incur any costs for sand purchased from Muskie for the years ended December 31, 2015 and 2014, respectively. The Companyincurred costs of $0.7 million for sand purchased from Muskie for the year ended December 31, 2013. The Company had no outstanding amounts payable toMuskie as of December 31, 2015 or December 31, 2014.Midland LeasesEffective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space isowned by an entity controlled by an affiliate of Wexford. The Company paid $1.0 million, $0.4 million and $0.2 million for the years ended December 31,2015, 2014 and 2013, respectively, under this lease.F-27Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table contains information regarding recent amendments to the Midland corporate lease:Date of AmendmentReason for AmendmentCurrent MonthlyBase RentNew Monthly Base Rent orRent for Additional SpaceApprox. Annual Increaseof Monthly Base Rent2nd and 3rd quarters 2013(1)Lease additional space$13,000$15,000N/A2nd quarter 2014Lease additional space$25,000$27,000N/A4th quarter 2014(2)Lease additional space$27,000$53,0004%November 2014(3)(4)Extend the termN/AN/AN/AApril 2015Lease additional spaceN/A$23,000N/AJune 2015Lease additional spaceN/A$22,0002%(1)The monthly rent will increase further to $25,000 beginning on October 1, 2013.(2)The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term.(3)The lease was amended to extend the term of the lease for an additional 10-year period.(4)Upon commencement of the extension in June 2016, the monthly base rent will increase to $94,000, with an increase of approximately 2% annually.Field Office LeaseThe Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011 to March 1, 2014. Effective March 1,2014, the building was purchased by an entity controlled by an affiliate of Wexford. The remaining term of the lease as of March 1, 2014 is four years. TheCompany paid rent of $0.2 million and $0.1 million to the related party for the years ended December 31, 2015 and 2014, respectively. The monthly baserent is $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease term. During the third quarter of 2014, theCompany negotiated a sublease with Bison, in which Bison will lease the field office space for the same term as the initial lease and will pay the monthly rentof $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease term.Oklahoma City LeaseEffective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. Theoffice space is owned by an entity controlled by an affiliate of Wexford. The Company paid $0.2 million and $0.2 million for the years ended December 31,2014 and 2013, respectively, under this lease. Effective April 1, 2013, the Company amended this lease to increase the size of the leased premises, at whichtime the monthly base rent increased to $19,000 for the remainder of the lease term. The Company was also responsible for paying a portion of specifiedcosts, fees and expenses associated with the operation of the premises. Effective September 23, 2014, this lease agreement was mutually terminated.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 services 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 initial term of two years commencing on October 18, 2012, and continuesfor additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may beterminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay allamounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’sindependent directors for such services as may be provided by Wexford at the Company’s request in connection with acquisitions and divestitures,financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do notextend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arisingout of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willfulmisconduct. The Company incurred total costs of $1.2 million, $8.3 million and $0.5 million for the years ended December 31, 2015, 2014 and 2013,respectively, under the Advisory Services Agreement. For the year ended December 31, 2014, the total amount of $8.3 million was paid by cash payments of$4.3 million and the issuance to Wexford of 63,786 shares of the Company’s common stock.F-28Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)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 we may be involved. The services provided byWexford under the Viper Advisory Services Agreement do not extend to the Partnership or the General Partners day-to-day business or operations. ThePartnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the ViperAdvisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. For the years endedDecember 31, 2015 and 2014, the Partnership incurred costs of $0.6 million and $0.3 million, respectively, under the Viper Advisory Services Agreement.Secondary Offering CostsOn November 17, 2014, Gulfport Energy Corporation (“Gulfport”) and certain entities controlled by Wexford completed an underwritten secondarypublic offering of 2,000,000 shares of the Company’s common stock and, on November 13, 2014, the underwriters purchased an additional 300,000 shares ofthe Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. Theshares were sold to the underwriters at $64.54 per share and the selling stockholders received all proceeds from this offering after deducting the underwritingdiscount. The Company incurred costs of less than $0.1 million related to this secondary public offering.On September 23, 2014, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 2,500,000shares of the Company’s common stock. The shares were sold to the underwriters at $75.44 per share and the selling stockholders received all proceeds fromthis offering after deducting the underwriting discount. The Company incurred costs of $0.1 million related to this secondary public offering.On June 27, 2014, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 2,000,000 shares ofthe Company’s common stock. The shares were sold to the public at $90.04 per share and the selling stockholders received all proceeds from this offeringafter deducting the underwriting discount. The Company incurred costs of approximately $0.1 million related to this secondary public offering.On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000,000 shares ofthe Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of the Company’s common stock from theseselling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 pershare and the selling stockholders received all proceeds from this offering after deducting the underwriting discount. The Company incurred costs ofapproximately $0.2 million related to this secondary public offering.12. INCOME TAXESDeferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reportingpurposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax.F-29Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The components of the provision for income taxes for the years ended December 31, 2015, 2014 and 2013 are as follows: Year Ended December 31, 2015 2014 2013 (In thousands)Current income tax provision (benefit): Federal$(33) $— $191State268 — —Total current income tax provision235 — 191Deferred income tax provision (benefit): Federal(198,729) 106,107 30,768State(2,816) 2,878 795Total deferred income tax provision (benefit)(201,545) 108,985 31,563Total provision for (benefit from) income taxes$(201,310) $108,985 $31,754 A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2015 2014 2013 (In thousands)Income tax expense (benefit) at the federal statutory rate (35%)$(263,179) $105,959 $30,231Income tax expense (benefit) relating to change in tax rate(1,145) — —State income tax expense (benefit), net of federal tax effect(2,548) 2,878 517Non-deductible expenses and other4,506 148 1,006Change in valuation allowance61,056 — —Provision for (benefit from) income taxes$(201,310) $108,985 $31,754F-30Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The components of the Company’s deferred tax assets and liabilities as of December 31, 2015 and 2014 are as follows: December 31, 2015 2014 (In thousands)Current: Deferred tax assets Derivative instruments$— $—Other2,658 1,950Current deferred tax assets2,658 1,950Valuation allowance(1,018) —Current deferred tax assets, net of valuation allowance1,640 1,950Deferred tax liabilities Derivative instruments1,640 41,903Total current deferred tax liabilities1,640 41,903Net current deferred tax assets— (39,953)Noncurrent: Deferred tax assets Net operating loss carryforwards (subject to 20 year expiration)82,635 49,627Stock based compensation3,873 2,520Alternative minimum tax credit carryforward— 33Other4,533 —Noncurrent deferred tax assets91,041 52,180Valuation allowance(60,038) —Noncurrent deferred tax assets, net of valuation allowance31,003 52,180Deferred tax liabilities Oil and natural gas properties and equipment31,003 213,772Other— —Total noncurrent deferred tax liabilities31,003 213,772Net noncurrent deferred tax liabilities— 161,592Net deferred tax liabilities$— $201,545The 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. In light of the impairmentof oil and gas properties, Management has recorded a $61.1 million valuation against the Company's federal NOLs. The valuation reduces the Company’sdeferred assets to a zero value, as management does not believe that it is more-likely-than-not that this portion of the Company's NOLs are realizable.Management believes that the balance of the Company's NOLs are realizable only to the extent of future taxable income primarily related to the excess ofbook carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment.The Company's U.S. federal NOLs and were incurred in the tax years 2015 and 2014, and will generally be available for use through the tax years2035 and 2034, respectively. The State of Texas currently has no NOL carryover provision. The Company believes that Section 382 of the Internal RevenueCode of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year lookback period, will not have an adverse effect on future NOL usage.F-31Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)13. DERIVATIVESAll derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accountingpurposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidatedstatements of operations under the caption “Gain (loss) on derivative instruments, net.”The Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixedprice swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swapprice, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. TheCompany’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on Inter–Continental Exchange pricing for Brent crude oil.By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Creditrisk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, thecounterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated creditagreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. TheCompany does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are alsolenders in our credit facility and have been deemed an acceptable credit risk.As of December 31, 2015, the Company had open crude oil derivative positions with respect to future production as set forth in the table below.When aggregating multiple contracts, the weighted average contract price is disclosed.Crude Oil—Inter–Continental Exchange Brent Fixed Price Swap Production PeriodVolume (Bbls) Fixed Swap PriceJanuary - February 201691,000 88.72Balance 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.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, 2015 and December 31, 2014. December 31, 2015 2014 (in thousands)Gross amounts of recognized assets$4,623 $117,541Gross amounts offset in the Consolidated Balance Sheet— —Net amounts of assets presented in the Consolidated Balance Sheet$4,623 $117,541F-32Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The 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, 2015 2014 (in thousands)Current Assets: Derivative instruments$4,623 $115,607Noncurrent Assets: Derivative instruments— 1,934Total Assets$4,623 $117,541None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. Thefollowing table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations: Year Ended December 31, 2015 2014 2013 (in thousands)Change in fair value of open non-hedge derivative instruments$(112,918) $117,109 $5,346Gain (loss) on settlement of non-hedge derivative instruments144,869 10,430 (7,218)Gain (loss) on derivative instruments$31,951 $127,539 $(1,872)14. 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.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.F-33Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as ofDecember 31, 2015 and 2014. December 31, 2015 2014 (in thousands)Fixed price swaps: Quoted prices in active markets level 1$— $—Significant other observable inputs level 24,623 117,541Significant unobservable inputs level 3— —Total$4,623 $117,541Assets 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, 2015 December 31, 2014 Carrying Carrying Amount Fair Value Amount Fair Value (in thousands)Debt: Revolving credit facility$11,000 $11,000 $223,500 $223,5007.625% Senior Notes due 2021450,000 450,000 450,000 440,438Partnership revolving credit facility34,500 34,500 — —The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to the Company for bank loans withsimilar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the December 31,2015 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the Partnership’s revolving credit facility approximates itscarrying value based on borrowing rates available to us for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.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.F-34Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)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, 2015:Year Ending December 31,Drilling RigCommitments Office and EquipmentLeases (in thousands)2016$29,536 $1,935201719,893 2,053201816,866 1,9732019589 1,8392020— 1,659Thereafter— 9,583Total$66,884 $19,042The Company leases office space in Midland, Texas from related parties and office space in Oklahoma City, OK from an unrelated third party. Referto Note 11—Related Party Transactions for further information on the related party lease agreements. The following table presents rent expense for the yearsended December 31, 2015, 2014 and 2013. Year ended December 31, 2015 2014 2013 (in thousands)Rent Expense$1,449 $852 $571Drilling contractsAs of December 31, 2015, the Company had entered into drilling rig contracts with one related party and various third parties in the ordinary courseof business to ensure rig availability to complete the Company’s drilling projects. Refer to Note 11–Related Party Transactions for further information on therelated party drilling agreement. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as ofDecember 31, 2015 total approximately $66.9 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 5 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 deficiency volume is calculated. The agreement may beterminated by Shell Trading (US) Company in the event that Shell Trading (US) Company’s contract for transportation on the pipeline is terminated.F-35Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)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 in equal annual installments over a four year period. For the years ended December 31, 2015, 2014 and 2013 the Company paid$1.4 million, $0.4 million and $0.3 million, respectively, in contributions to the plan.16. SUBSEQUENT EVENTSIn January 2016, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares ofcommon stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $55.33 per shareand the Company received net proceeds of approximately $254.5 million from the sale of these shares of common stock, net of offering expenses andunderwriting discounts and commissions.17. GUARANTOR FINANCIAL STATEMENTSDiamondback E&P LLC, Diamondback O&G LLC and White Fang Energy LLC (the “Guarantor Subsidiaries”) are guarantors under the Indenturerelating to the Senior Notes. On June 23, 2014, in connection with the Viper Offering, the Company designated the Partnership, the General Partner and ViperEnergy Partners LLC (the “Non-Guarantor Subsidiaries”) as unrestricted subsidiaries under the Indenture and, upon such designation, Viper Energy PartnersLLC, which was a guarantor under the Indenture prior to such designation, was released as a guarantor under the Indenture. Viper Energy Partners LLC is alimited liability company formed on September 18, 2013 to own and acquire mineral and other oil and natural gas interests in properties in the Permian Basinin West Texas. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 17 is referred to as the“Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine theentities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may notnecessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. TheCompany has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial andnarrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.F-36Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Balance SheetDecember 31, 2015(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedAssets Current assets: Cash and cash equivalents$148 $19,428 $539 $— $20,115Restricted cash— — 500 — 500Accounts receivable— 67,942 9,369 2 77,313Accounts receivable - related party— 1,591 — — 1,591Intercompany receivable2,246,846 205,915 — (2,452,761) —Inventories— 1,728 — — 1,728Other current assets450 6,572 476 — 7,498Total current assets2,247,444 303,176 10,884 (2,452,759) 108,745Property and equipment Oil and natural gas properties, at cost, based on the full cost method ofaccounting— 3,400,381 554,992 — 3,955,373Pipeline and gas gathering assets— 7,174 — — 7,174Other property and equipment— 48,621 — — 48,621Accumulated depletion, depreciation, amortization and impairment— (1,347,296) (71,659) 5,412 (1,413,543)Net property and equipment— 2,108,880 483,333 5,412 2,597,625Investment in subsidiaries79,417 — — (79,417) —Other assets7,795 8,733 35,514 — 52,042Total assets$2,334,656 $2,420,789 $529,731 $(2,526,764) $2,758,412Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade$— $20,007 $1 $— $20,008Accounts payable-related party1 212 4 — 217Intercompany payable— 2,452,759 — (2,452,759) —Other current liabilities8,683 112,431 82 — 121,196Total current liabilities8,684 2,585,409 87 (2,452,759) 141,421Long-term debt450,000 11,000 34,500 — 495,500Asset retirement obligations— 12,518 — — 12,518Total liabilities458,684 2,608,927 34,587 (2,452,759) 649,439Commitments and contingencies Stockholders’ equity:1,875,972 (188,138) 495,144 (307,006) 1,875,972Noncontrolling interest— — — 233,001 233,001Total equity1,875,972 (188,138) 495,144 (74,005) 2,108,973Total liabilities and equity$2,334,656 $2,420,789 $529,731 $(2,526,764) $2,758,412F-37Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Balance SheetDecember 31, 2014(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedAssets Current assets: Cash and cash equivalents$6 $15,067 $15,110 $— $30,183Restricted cash— — 500 — 500Accounts receivable— 85,752 8,239 2 93,993Accounts receivable - related party— 4,001 — — 4,001Intercompany receivable1,658,215 2,167,434 — (3,825,649) —Inventories— 2,827 — — 2,827Other current assets562 119,392 253 — 120,207Total current assets1,658,783 2,394,473 24,102 (3,825,647) 251,711Property and equipment Oil and natural gas properties, at cost, based on the full cost method ofaccounting— 2,607,513 511,084 — 3,118,597Pipeline and gas gathering assets— 7,174 — — 7,174Other property and equipment— 48,180 — — 48,180Accumulated depletion, depreciation, amortization and impairment— (351,200) (32,799) 1,855 (382,144)Net property and equipment— 2,311,667 478,285 1,855 2,791,807Investment in subsidiaries839,217 — — (839,217) —Other assets9,155 7,793 35,015 — 51,963Total assets$2,507,155 $4,713,933 $537,402 $(4,663,009) $3,095,481Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade$— $26,224 $6 $— $26,230Intercompany payable95,362 3,730,287 — (3,825,649) —Other current liabilities49,190 189,264 2,045 — 240,499Total current liabilities144,552 3,945,775 2,051 (3,825,649) 266,729Long-term debt450,000 223,500 — — 673,500Asset retirement obligations— 8,447 — — 8,447Deferred income taxes161,592 — — — 161,592Total liabilities756,144 4,177,722 2,051 (3,825,649) 1,110,268Commitments and contingencies Stockholders’ equity:1,751,011 536,211 535,351 (1,071,562) 1,751,011Noncontrolling interest— — — 234,202 234,202Total equity1,751,011 536,211 535,351 (837,360) 1,985,213Total liabilities and equity$2,507,155 $4,713,933 $537,402 $(4,663,009) $3,095,481F-38Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of OperationsYear Ended December 31, 2015(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedRevenues: Oil sales$— $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(35,651) (4,749) (1,110) — (41,510)Other income1 (588) 1,154 — 567Other income - intercompany— 161 — — 161Gain (loss) on derivative instruments, net— 31,951 — — 31,951Total other income (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)Less: Net income attributable to noncontrolling interest— — — 2,838 2,838Net income (loss) attributable to Diamondback Energy, Inc.$148,583 $(724,349) $24,419 $719 $(550,628)F-39Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of OperationsYear Ended December 31, 2014(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedRevenues: Oil sales$— $377,712 $— $71,532 $449,244Natural gas sales— 15,240 — 2,788 18,028Natural gas liquid sales— 24,545 — 3,901 28,446Royalty income— — 77,767 (77,767) —Total revenues— 417,497 77,767 454 495,718Costs and expenses: Lease operating expenses— 55,384 — — 55,384Production and ad valorem taxes— 27,242 5,377 19 32,638Gathering and transportation— 3,294 — (6) 3,288Depreciation, depletion and amortization— 143,477 27,601 (1,073) 170,005General and administrative expenses10,879 7,189 4,372 (1,174) 21,266Asset retirement obligation accretion expense— 467 — — 467Total costs and expenses10,879 237,053 37,350 (2,234) 283,048Income (loss) from operations(10,879) 180,444 40,417 2,688 212,670Other income (expense) Interest income - intercompany10,755 — — (10,755) —Interest expense(30,281) (3,746) (487) — (34,514)Interest expense - intercompany— — (10,755) 10,755 —Other income6 91 459 — 556Other income - intercompany— 1,027 — (906) 121Other expense— (1,416) — — (1,416)Loss on derivative instruments, net— 127,539 — — 127,539Total other income (expense), net(19,520) 123,495 (10,783) (906) 92,286Income before income taxes(30,399) 303,939 29,634 1,782 304,956Provision for income taxes108,985 — — — 108,985Net income (loss)$(139,384) $303,939 $29,634 $1,782 $195,971Less: Net income attributable to noncontrolling interest— — — 2,216 2,216Net income (loss) attributable to Diamondback Energy, Inc.$(139,384) $303,939 $29,634 $(434) $193,755F-40Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of OperationsYear Ended December 31, 2013(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedRevenues: Oil sales$— $174,868 $— $13,885 $188,753Natural gas sales— 5,852 — 397 6,249Natural gas liquid sales— 12,295 — 705 13,000Royalty income— — 14,987 (14,987) —Total revenues— 193,015 14,987 — 208,002Costs and expenses: Lease operating expenses— 21,157 — — 21,157Production and ad valorem taxes— 11,927 972 — 12,899Gathering and transportation— 918 — — 918Depreciation, depletion and amortization— 61,398 5,199 — 66,597General and administrative expenses3,909 7,127 — — 11,036Asset retirement obligation accretion expense— 201 — — 201Intercompany charges— — 87 (87) —Total costs and expenses3,909 102,728 6,258 (87) 112,808Income (loss) from operations(3,909) 90,287 8,729 87 95,194Other income (expense) Interest income - intercompany5,741 — — (5,741) —Interest expense(591) (7,467) (5,741) 5,741 (8,058)Other income— 87 — (87) —Other income - intercompany— 1,077 — — 1,077Loss on derivative instruments, net— (1,872) — — (1,872)Total other income (expense), net5,150 (8,175) (5,741) (87) (8,853)Income (loss) before income taxes1,241 82,112 2,988 — 86,341Provision for income taxes31,754 — — — 31,754Net income (loss)$(30,513) $82,112 $2,988 $— $54,587F-41Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of Cash FlowsYear Ended December 31, 2015(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedNet cash provided by (used in) operating activities$(37,597) $390,266 $63,832 $— $416,501Cash flows from investing activities: Additions to oil and natural gas properties— (419,512) — — (419,512)Acquisition of leasehold interests— (437,455) — — (437,455)Acquisition of royalty interests— — (43,907) — (43,907)Purchase of other property and equipment— (1,213) — — (1,213)Proceeds from sale of assets— 9,739 — — 9,739Equity investments— (2,702) — — (2,702)Intercompany transfers(145,023) 145,023 — — —Other investing activities— — — — —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)Debit issuance costs— (85) (441) — (526)Public offering costs(586) — — — (586)Proceeds from public offerings650,688 — — — 650,688Distribution to parent— — — — —Distribution 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 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 $— $20,115F-42Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of Cash FlowsYear Ended December 31, 2014(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedNet cash provided by (used in) operating activities$(8,862) $313,438 $51,813 $— $356,389Cash flows from investing activities: Additions to oil and natural gas properties— (493,063) (5,276) — (498,339)Acquisition of leasehold interests— (845,826) — — (845,826)Acquisition of royalty interests— — (57,689) — (57,689)Purchase of other property and equipment— (44,213) — — (44,213)Equity investments— (627) (33,850) — (34,477)Intercompany transfers(642,978) 642,978 — — —Other investing activities— (1,453) — — (1,453)Net cash used in investing activities(642,978) (742,204) (96,815) — (1,481,997)Cash flows from financing activities: Proceeds from borrowing on credit facility— 431,400 78,000 — 509,400Repayment on credit facility— (217,900) (78,000) — (295,900)Proceeds from public offerings693,886 — 234,546 — 928,432Distribution to parent— — (148,760) 148,760 —Distribution from subsidiary166,372 — — (166,372) —Distribution to non-controlling interest— — (19,926) 17,612 (2,314)Intercompany transfers(217,900) 217,900 — — —Other financing activities8,962 (1,834) (6,510) — 618Net cash provided by financing activities651,320 429,566 59,350 — 1,140,236Net increase (decrease) in cash and cash equivalents(520) 800 14,348 — 14,628Cash and cash equivalents at beginning of period526 14,267 762 — 15,555Cash and cash equivalents at end of period$6 $15,067 $15,110 $— $30,183F-43Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)Condensed Consolidated Statement of Cash FlowsYear Ended December 31, 2013(In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations ConsolidatedNet cash provided by operating activities$12,302 $138,630 $4,845 $— $155,777Cash flows from investing activities: Additions to oil and natural gas properties— (292,586) — — (292,586)Acquisition of leasehold interests— (195,893) — — (195,893)Acquisition of royalty interests— — (444,083) — (444,083)Intercompany transfers(289,344) 289,344 — — —Other investing activities— (7,578) — — (7,578)Net cash used in investing activities(289,344) (206,713) (444,083) — (940,140)Cash flows from financing activities: Proceeds from borrowing on credit facility— 59,000 — — 59,000Repayment on credit facility— (49,000) — — (49,000)Proceeds from senior notes10,000 — 440,000 — 450,000Proceeds from public offerings322,680 — — — 322,680Intercompany transfers(49,000) 49,000 — — —Other financing activities(6,126) (2,994) — — (9,120)Net cash provided by financing activities277,554 56,006 440,000 — 773,560Net increase in cash and cash equivalents512 (12,077) 762 — (10,803)Cash and cash equivalents at beginning of period14 26,344 — — 26,358Cash and cash equivalents at end of period$526 $14,267 $762 $— $15,555F-44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, 2015 2014 (In thousands)Oil and Natural Gas Properties: Proved properties$2,848,557 $2,345,077Unproved properties1,106,816 773,520Total Oil and Natural Gas Properties3,955,373 3,118,597Accumulated depreciation, depletion, amortization(512,144) (296,317)Accumulated impairment(897,962) (83,164)Net oil and natural gas properties capitalized$2,545,267 $2,739,116Costs 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, 2015 2014 2013 (In thousands)Acquisition costs Proved properties$64,340 $302,234 $339,130Unproved properties448,638 601,188 279,402Development costs42,749 86,097 88,460Exploration costs319,102 475,756 242,929Capitalized asset retirement costs3,458 4,962 697Total$878,287 $1,470,237 $950,618F-45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, 2015 2014 2013 (In thousands)Oil, natural gas and natural gas liquid sales$446,733 $495,718 $208,002Lease operating expenses(82,625) (55,384) (21,157)Production and ad valorem taxes(32,990) (32,638) (12,899)Gathering and transportation(6,091) (3,288) (918)Depreciation, depletion, and amortization(216,056) (168,674) (65,821)Impairment(814,798) — —Asset retirement obligation accretion expense(833) (467) (201)Income tax expense201,310 (108,985) (31,754)Results of operations$(505,350) $126,282 $75,252Oil and Natural Gas ReservesProved oil and natural gas reserve estimates as of December 31, 2015, 2014 and 2013 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-46Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)The changes in estimated proved reserves are as follows: Oil(Bbls) Natural GasLiquids(Bbls) Natural Gas(Mcf)Proved Developed and Undeveloped Reserves: As of January 1, 201326,196,859 8,251,429 34,570,148Extensions and discoveries17,041,744 4,597,856 24,184,540Revisions of previous estimates(5,943,164) (3,455,306) (5,786,180)Purchase of reserves in place7,328,162 1,672,824 10,441,485Production(2,022,749) (361,079) (1,730,497)As of December 31, 201342,600,852 10,705,724 61,679,496Extensions and discoveries37,068,820 7,828,094 52,099,252Revisions of previous estimates(6,784,560) 649,476 (17,726,552)Purchase of reserves in place8,186,053 360,536 19,898,649Production(5,381,576) (1,001,898) (4,345,585)As of December 31, 201475,689,589 18,541,932 111,605,260Extensions and discoveries48,725,132 12,055,631 53,452,948Revisions of previous estimates(12,130,474) (4,080,886) (14,726,160)Purchase of reserves in place2,775,599 1,165,090 7,101,933Production(9,081,135) (1,677,623) (7,931,237)As of December 31, 2015105,978,711 26,004,144 149,502,744 Proved Developed Reserves: January 1, 20137,189,367 2,999,440 12,864,941December 31, 201319,789,965 4,973,493 31,428,756December 31, 201443,885,835 11,221,428 68,264,113December 31, 201560,569,398 15,418,353 96,871,109 Proved Undeveloped Reserves: January 1, 201319,007,492 5,251,989 21,705,207December 31, 201322,810,887 5,732,231 30,250,740December 31, 201431,803,754 7,320,504 43,341,147December 31, 201545,409,313 10,585,791 52,631,635Revisions 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.The Company made one large acquisition of oil and natural gas interests in 2015 located in western Howard and eastern Martin counties. Severalsmall acquisitions were also made in various counties including Andrews, Midland, Martin, and Glasscock counties. The reserves from these acquisitionswere primarily proved producing reserves from 136 vertical wells and four horizontal wells and three vertical wells where additional interest was acquired. Allof the properties were acquired for horizontal exploitation. Although there were four producing horizontal wells on the properties no PUD’s were included inthe acquired properties because of very limited production from the wells at the time of acquisition. Significant extensions occurred in 2015 as a result ofcontinued horizontal development of the Lower Spraberry and Wolfcamp B horizons. There was also initial development of the Wolfcamp A and MiddleSpraberry horizons in some locations. The extensions resulted from two vertical wells and 119 horizontal wells in which the Company has a working interestand 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. The revisions are primarily the result of lower productpricing. As a result of lower pricing 80 vertical wells and 22 horizontal wells in which the Company has a working interest and 22 vertical wells in which theCompany has a mineral interest were downgraded from the proved undeveloped category toF-47Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)probable or possible reserves. Additional downward revisions resulted from shorter producing lives on existing wells as a result of the wells reaching theireconomic limit sooner due to lower revenues.The Company made two major acquisitions of oil and natural gas interests in 2014. One involved properties located in southwest Martin Countyand the other involved properties located predominantly in Glasscock and Midland Counties. The reserves from these acquisitions were primarily provedproducing reserves from 280 existing vertical wells and six existing horizontal wells. The properties were acquired for horizontal exploitation, however theonly horizontal wells that existed on the properties were in one isolated block in Reagan County. As a result, no horizontal PUDs were included in theacquired reserves. Significant extensions occurred primarily as a result of continued horizontal development of the Wolfcamp B horizon and the initialhorizontal development of the Lower Spraberry shale. The extensions resulted from development of 18 vertical wells and 103 horizontal wells in which theCompany has a working interest and one vertical well and 14 horizontal wells in which the Company has a mineral interest through its ownership in Viper. Ofthe total 19 vertical wells and 117 horizontal wells, five of the vertical wells and 66 of the horizontal wells are in the proved undeveloped category. Therevisions are primarily the result of 73 vertical wells that were downgraded from PUDs to probable reserves due to a shift in the Company’s focus tohorizontal development rather than vertical development. As a result these wells are no longer expected to be developed within five years of when they wereoriginally booked.The Company experienced downward reserve revisions in estimated proved oil, natural gas and natural gas liquid reserves in 2013. The downwardrevisions were primarily a result of downgrading 92 vertical locations that were booked as PUDs to probable in accordance with the SEC five year PUD rule.At December 31, 2015, the Company’s estimated PUD reserves were approximately 64,767 MBOE, an 18,419 MBOE increase over the reserveestimate at December 31, 2014 of 46,348 MBOE. The following table includes the changes in PUD reserves for 2015: (MBOE)Beginning proved undeveloped reserves at December 31, 201446,348Undeveloped reserves transferred to developed(13,680)Revisions(12,656)Extensions and discoveries44,755Ending proved undeveloped reserves at December 31, 201564,767The increase in proved undeveloped reserves was primarily attributable to extensions and discoveries of 44,755 MBOE. Approximately 20% of theproved undeveloped reserve extensions are associated with well locations that are more than one offset away from existing producing wells. All of theselocations are within 1,700 feet of producing wells. Partially offsetting the increase in proved undeveloped reserves were decreases due to technical revisions.Downward revisions of approximately 12,656 MBOE were a result of reclassifying 14,619 MBOE of reserves attributable to 80 vertical wells and 22horizontal wells in which the Company has a working interest and 22 vertical wells in which the Company has only a mineral interest held through thePartnership due to lower product prices. Vertical well reclassifications accounted for 8,607 MBOE of the total of 14,619 MBOE. These vertical locations werealso unlikely to be developed within the five-year period required by the applicable SEC rules due to the Company’s focus on horizontal well development.As of December 31, 2015, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they wereinitially recorded. During 2015, approximately $42.7 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 following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board Codification, Topic932–“Extractive Activities–Oil and Gas.” The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted asrepresenting current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of thereserves may notF-48Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.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, 2015, 2014 and 2013. December 31, 2015 2014 2013 (In thousands)Future cash inflows$5,377,783 $7,695,368 $4,604,241Future development costs(548,239) (602,438) (517,075)Future production costs(1,279,101) (1,278,487) (806,895)Future production taxes(363,129) (534,851) (318,396)Future income tax expenses(28,233) (672,380) (674,260)Future net cash flows3,159,081 4,607,212 2,287,61510% discount to reflect timing of cash flows(1,740,948) (2,561,988) (1,311,976)Standardized measure of discounted future net cash flows$1,418,133 $2,045,224 $975,639In 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, 2015 2014 2013 Unweighted Arithmetic Average First-Day-of-the-Month PricesOil (per Bbl)$45.07 $87.15 $92.59Natural gas (per Mcf)$1.83 $4.85 $4.13Natural gas liquids (per Bbl)$12.56 $30.09 $37.82Principal 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, 2015 2014 2013 (In thousands)Standardized measure of discounted future net cash flows at the beginning of the period$2,045,224 $975,639 $367,220Sales of oil and natural gas, net of production costs(331,119) (404,409) (173,946)Purchase of minerals in place57,359 291,807 305,109Extensions and discoveries, net of future development costs629,149 1,135,293 552,450Previously estimated development costs incurred during the period129,901 111,527 76,631Net changes in prices and production costs(1,383,698) (105,210) 51,828Changes in estimated future development costs38,638 (4,877) (5,822)Revisions of previous quantity estimates(377,160) (173,004) (126,993)Accretion of discount236,716 151,481 57,988Net change in income taxes268,963 (12,326) (168,570)Net changes in timing of production and other104,160 79,303 39,744Standardized measure of discounted future net cash flows at the end of the period$1,418,133 $2,045,224 $975,639F-49Diamondback Energy, Inc. and SubsidiariesNotes to Consolidated Financial Statements-(Continued)19. QUARTERLY FINANCIAL DATA (Unaudited)The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. 2015 FirstQuarter SecondQuarter ThirdQuarter FourthQuarterRevenues$101,401 $119,063 $111,946 $114,323Income (loss) from operations1,437 (299,120) (254,773) (187,813)Income tax expense (benefit)3,370 (116,732) (81,461) (6,487)Net income (loss)6,439 (211,352) (156,042) (186,835)Less: Net income attributable to noncontrolling interest590 935 739 574Net income (loss) attributable to Diamondback Energy, Inc.$5,849 $(212,287) $(156,781) $(187,409)Earnings per common share Basic$0.10 $(3.45) $(2.40) $(2.80)Diluted$0.10 $(3.45) $(2.40) $(2.80) 2014 FirstQuarter SecondQuarter ThirdQuarter FourthQuarterRevenues$98,004 $127,004 $139,127 $131,583Income from operations48,063 63,192 63,516 37,899Income tax expense (benefit)13,601 15,163 23,978 56,243Net income23,589 27,824 44,641 99,917Less: Net income attributable to noncontrolling interest— 71 902 1,243Net income attributable to Diamondback Energy, Inc.$23,589 $27,753 $43,739 $98,674Earnings per common share Basic$0.49 $0.55 $0.79 $1.74Diluted$0.48 $0.54 $0.79 $1.73F-50Table of ContentsEXHIBIT INDEXExhibit 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).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 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 September 18, 2013, among Diamondback Energy, Inc., the subsidiary guarantors party thereto and Wells Fargo,N.A., as trustee (including the form of Diamondback Energy, Inc.’s 7.625% Senior Note due October 2021 (incorporated by reference toExhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 18, 2013).4.4 First Supplemental Indenture, dated as of November 5, 2013, by and among Diamondback Energy, Inc., the subsidiary guarantors partythereto and Wells Fargo, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 19, 2014).4.5 Second Supplemental Indenture, dated as of October 8, 2014, by and among Diamondback Energy, Inc., White Fang Energy LLC, assubsidiary guarantor, other subsidiary guarantors party thereto and Wells Fargo, National Association, as trustee (incorporated byreference to Exhibit 4.6 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 19, 2015).10.1+ Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with theSEC on November 16, 2012).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).10.3+ 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).E-1Table of ContentsExhibit Number Description10.6 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).10.20 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).E-2Table of ContentsExhibit Number Description10.23 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).10.37 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).E-3Table of ContentsExhibit Number Description10.39 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).10.40 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 10.2 to the Form 10-Q, File No. 001-35700,filed by the Company with the SEC on May 9, 2014).10.41 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 6,2015).10.42 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).10.43 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).10.44 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).10.45 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).10.46 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).10.47 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).10.48 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).10.49 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.E-4Table of ContentsExhibit Number Description32.2** 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 21, 2016, 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, 2015.99.2* Report of Ryder Scott Company, L.P., dated January 21, 2016, 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, 2015.101.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._______________*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.E-5Exhibit 21.1Diamondback Energy, Inc.Subsidiaries of RegistrantName of SubsidiaryJurisdiction of IncorporationDiamondback E&P LLCDelawareDiamondback O&G LLCDelawareWhite Fang Energy 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 19, 2016, 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, 2015.We consent to the incorporation by reference of said reports in the Registration Statements of Diamondback Energy, Inc. on Form S-3(File No. 333-192099, effective November 5, 2013) and on Form S-8 (File No. 333-188552, effective May 13, 2013)./s/ GRANT THORNTON LLPOklahoma City, OklahomaFebruary 19, 2016Exhibit 23.2CONSENT OF RYDER SCOTT COMPANY, L.P.We have issued our report dated January 21, 2016 on estimates of proved reserves, future production and income attributable tocertain leasehold interest of Diamondback Energy, Inc. (“Diamondback”) as of December 31, 2015. 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 Form S-8 (File No. 333-188552, effective May 13, 2013) and on Form S-3 (File No.333-192099, effective November 5, 2013) /s/ Ryder Scott Company, L.P. RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580Houston, TexasFebruary 19, 2016Exhibit 23.3CONSENT OF RYDER SCOTT COMPANY, L.P.We have issued our report dated January 21, 2016 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, 2015.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 Form S-8 (File No. 333-188552, effective May 13,2013) and on Form S-3 (File No. 333-192099, effective November 5, 2013). /s/ Ryder Scott Company, L.P. RYDER SCOTT COMPANY, L.P. TBPE Firm Registration No. F-1580Houston, TexasFebruary 19, 2016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 19, 2016 /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 19, 2016 /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, 2015 (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 19, 2016 /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, 2015 (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 19, 2016 /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, 2015\s\ Don P. GriffinDon P. Griffin, P.E.TBPE License No. 64150Senior Vice President[SEAL]RYDER SCOTT COMPANY, L.P.TBPE Firm License No. F-1580RYDER SCOTT COMPANY PETROLEUM CONSULTANTSTBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-08491100 LOUISIANA STREET SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191January 21, 2016Diamondback 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 31,2015. 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 15, 2016 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, 2015.The results of this study are summarized below.SEC PARAMETERSEstimated Net Reserves and Income DataCertain Leasehold Interests ofDiamondback Energy, Inc.As of December 31, 2015 Proved Developed Total Producing Non-Producing Undeveloped ProvedNet Remaining Reserves Oil/Condensate – MBbl 50,828 41 36,732 87,601Plant Products – MBbl 13,203 10 8,875 22,088Gas – MMCF 83,088 44 42,063 125,195MBOE 77,879 58 52,618 130,555 Income Data ($M) Future Gross Revenue $2,502,077 $1,950 $1,747,279 $4,251,306Deductions 1,008,549 1,502 904,441 1,914,492Future Net Income (FNI) $1,493,528 $448 $842,838 $2,336,814 Discounted FNI @ 10% $800,928 $218 $232,192 $1,033,338SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258The estimated reserves and future net income amounts presented in this report, as of December 31, 2015 are related tohydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the un-weighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required bythe SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes ofreserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantitiespresented in this report.Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBbl). All gas volumes are reported on an“as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which thegas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas isconverted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousandsbarrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars(M$).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 and development costs. The future net income is before the deduction ofstate and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that mayexist nor does it include any adjustment for cash on hand or undistributed income.Liquid hydrocarbon reserves account for approximately 94.7 percent and gas reserves account for the remaining 5.3percent of total 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. Discounted Future Net Income (M$) As of December 31, 2015Discount Rate Total Percent Proved 5 $1,441,824 15 $804,611 20 $659,143 25 $558,724 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS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 reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitionsand Guidelines” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category.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 addresses 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.”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 andRYDER SCOTT COMPANY PETROLEUM CONSULTANTSpolicies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differsignificantly from the estimated quantities.The estimates of reserves presented herein were based upon a detailed study of the properties in which Diamondbackowns an 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 singularly or in combination by the reserveevaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination ofmethods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience andengineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoirbeing 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.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 early December 2015 in those cases where such dataRYDER SCOTT COMPANY PETROLEUM CONSULTANTSwere considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Diamondback and wereconsidered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves were estimated byanalogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequatehistorical performance data to establish a definitive trend and where the use of production performance data as a basis for thereserve estimates was considered to be inappropriate.All proved developed non-producing and 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.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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS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, 2015. 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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS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.GeographicAreaProductPriceReferenceAverageBenchmarkPricesAverage ProvedRealizedPricesNorth America United StatesOil/CondensateWTI Cushing$50.28/Bbl$45.08/Bbl NGLsPropane, Mt. Belvieu$19.90/Bbl$12.76/Bbl GasHenry Hub$2.58/MMBTU$1.87/MCFThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individualproperty evaluations.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. Diamondback’s estimates ofzero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed adetailed study of the abandonment costs or the salvage value and makes no warranty for Diamondback’s estimate.The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordancewith Diamondback’s plans to develop these reserves as of December 31, 2015. The implementation of Diamondback’sdevelopment plans as presented to us and incorporated herein is subject to the approval process adopted by Diamondback’smanagement. As the result of our inquiries during the course of preparing this report, Diamondback has informed us that thedevelopment activities included herein have been subjected to and received the internal approvals required by Diamondback’smanagement at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certaindevelopment activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements orother administrative approvals external to Diamondback. Additionally, Diamondback has informed us that they are not aware of anylegal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from thoseRYDER SCOTT COMPANY PETROLEUM CONSULTANTSunder existing economic conditions as of December 31, 2015, such changes 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 references to our name as well as to the references to our third party report for Diamondback,which appears in the December 31, 2015 annual report on Form 10-K of Diamondback. Our written consent for such use isincluded as a separate exhibit to the filings made with the SEC by Diamondback.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS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\ Don P. GriffinDon P. Griffin, P.E.TBPE License No. 64150Senior Vice President[SEAL]DPG (FWZ)/plRYDER SCOTT COMPANY PETROLEUM CONSULTANTSProfessional Qualifications of Primary Technical PersonThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineersfrom Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of thereserves, future production and income presented herein.Mr. Griffin, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible forcoordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For moreinformation regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website atwww.ryderscott.com/Company/Employees.Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and theSociety of Petroleum Evaluation 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. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2015 covering such topics as reservoirengineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.Based on his educational background, professional training and more than 30 years of practical experience in the estimation andevaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and ReservesAuditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”promulgated by the Society 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)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 99.2VIPER ENERGY PARTNERS, LPEstimatedFuture Reserves and IncomeAttributable to CertainRoyalty InterestsSEC ParametersAs ofDecember 31, 2015\s\ Don P. GriffinDon P. Griffin, P.E.TBPE License No. 64150Senior Vice President[SEAL]RYDER SCOTT COMPANY, L.P.TBPE Firm License No. F-1580RYDER SCOTT COMPANY PETROLEUM CONSULTANTSTBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-08491100 LOUISIANA STREET SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191January 21, 2016Viper 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, 2015. 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 15, 2016 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, 2015.The results of this study are summarized below.SEC PARAMETERSEstimated Net Reserves and Income DataCertain Royalty Interests ofViper Energy Partners, LPAs of December 31, 2015 Proved Developed Total Producing Non-Producing Undeveloped ProvedNet Remaining Reserves Oil/Condensate – MBbl 9,683 17 8,677 18,377Plant Products – MBbl 2,201 4 1,711 3,916Gas – MMCF 13,721 18 10,569 24,308MBOE 14,171 23 12,150 26,344 Income Data ($M) Future Gross Revenue $460,393 $780 $406,684 $867,857Deductions 9,208 15 8,134 17,357Future Net Income (FNI) $451,185 $765 $398,550 $850,500 Discounted FNI @ 10% $215,061 $405 $182,538 $398,004SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258The estimated reserves and future net income amounts presented in this report, as of December 31, 2015 are related tohydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the un-weighted arithmetic averages of the prices in effect on thefirst-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required bythe SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes ofreserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantitiespresented in this report.Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBbl). All gas volumes are reported on an“as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which thegas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas isconverted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousandsbarrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars(M$).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 95.6 percent and gas reserves account for the remaining 4.4percent of total 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. Discounted Future Net Income ($M) As of December 31, 2015Discount Rate Total Percent Proved 5 $531,999 15 $324,301 20 $277,006 25 $243,691 RYDER SCOTT COMPANY PETROLEUM CONSULTANTS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 reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitionsand Guidelines” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category.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.”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 andRYDER SCOTT COMPANY PETROLEUM CONSULTANTSpolicies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differsignificantly from the estimated quantities.The estimates of reserves presented herein were based upon a detailed study of the properties in which Viper owns aninterest; however, we have not made any field examination of the properties. No consideration was given in this report to potentialenvironmental 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 singularly or in combination by the reserveevaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination ofmethods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience andengineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoirbeing 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.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 early December 2015 in those cases where such dataRYDER SCOTT COMPANY PETROLEUM CONSULTANTSwere considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Diamondback and wereconsidered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves were estimated byanalogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequatehistorical performance data to establish a definitive trend and where the use of production performance data as a basis for thereserve estimates was considered to be inappropriate.All proved developed non-producing and 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.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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS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, 2015. 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.RYDER SCOTT COMPANY PETROLEUM CONSULTANTS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.GeographicAreaProductPriceReferenceAverageBenchmarkPricesAverage ProvedRealizedPricesNorth America United StatesOil/CondensateWTI Cushing$50.28/Bbl$45.03/Bbl NGLsPropane, Mt. Belvieu$19.90/Bbl$11.41/Bbl GasHenry Hub$2.58/MMBTU$1.64/MCFThe effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individualproperty evaluations.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 proved developed non-producing and undeveloped reserves in this report have beenincorporated herein in accordance with Diamondback's plans to develop these reserves as of December 31, 2015. Theimplementation of Diamondback's development plans as presented to us and incorporated herein is subject to the approvalprocess adopted by Diamondback's management. As the result of our inquiries during the course of preparing this report,Diamondback has informed us that the development activities included herein have been subjected to and received the internalapprovals required by Diamondback’s management at the appropriate local, regional and/or corporate level. In addition to theinternal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint OperatingAgreement (JOA) requirements or other administrative approvals external to Diamondback. Additionally, Diamondback hasinformed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. Whilethese plans could change from those under existing economic conditions as of December 31, 2015, such changes were, inaccordance with rules adopted by the SEC, omitted from consideration 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 haveRYDER SCOTT COMPANY PETROLEUM CONSULTANTSauthored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain andenhance their professional skills by actively participating in 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 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 UsageViper 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, 2015 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\ Don P. GriffinDon P. Griffin, P.E.TBPE License No. 64150Senior Vice President[SEAL]DPG (FWZ)/plRYDER SCOTT COMPANY PETROLEUM CONSULTANTSProfessional Qualifications of Primary Technical PersonThe conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineersfrom Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of thereserves, future production and income presented herein.Mr. Griffin, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible forcoordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For moreinformation regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website atwww.ryderscott.com/Company/Employees.Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and theSociety of Petroleum Evaluation 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. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2015 covering such topics as reservoirengineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.Based on his educational background, professional training and more than 30 years of practical experience in the estimation andevaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and ReservesAuditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information”promulgated by the Society 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)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

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