Investor Presentation November 2018

Forward Looking Statement FORWARD LOOKING STATEMENT AND OTHER IMPORTANT INFORMATION FOR INVESTORS AND STOCKHOLDERS Forward-Looking Statements statements, This presentation other contains than statements forward-of looking historical statements fact, included within the in this meaning presentation of Section that27A address of the activities, Securities events Act of or1933 developments and Section that 21E Diamondback of the Securities Energy, Exchange Inc. (the Act “Company” of 1934. All or “Diamondback”) “plan,” “intend,”expects, “foresee,” believes “should,” or anticipates “would,” “could,” will or may or other occursimilar in the expressions future are forward are intended -lookingto statements identify forward . The words -looking “believe,” statements, “expect,” which “may,” are generally “estimates,” not historical “will,” “anticipate,” in nature. However, in this presentation the absence specifically of these words include does thenot expectations mean thatof the plans, statements strategies, are not objectives forwardand -looking anticipated . Without financial limitingand theoperating generalityresults of the foregoing, of the Company, forwardincluding -looking statements as to the Company’s contained assumptions acquisitions, made drillingby programs, the Company production, based on hedging management’s activities,expectations capital expenditure and perception levels and of historical other guidance trends, included current conditions, in this presentation anticipated . These futurestatements developments are and based other on certain factors believed actual results to beto appropriate differ materially . Suchfrom statements those implied are subject or expressed to a number by the of forward assumptions, -looking risks statements and uncertainties, . These include manythe of which factors are discussed beyondor the referenced control ofin the the Company, Company’s which filings may with cause the Securities conditionsand andExchange resulting capital Commission restraints, (“SEC”), prices including and demand its Forms for 10 oil-K, and 10natural -Q and gas, 8-K and availability any amendments of drilling equipment thereto, relating and personnel, to financial availability performance of sufficient and results, capital current to execute economic the reserves Company’s and business efficiently plan, develop impact and ofexploit compliance its current with legislation reserves, the and Company’s regulations, ability successful to successfully results from identify, the complete Company’s and identified integrate drilling acquisitions locations, of properties the Company’s or businesses ability to and replace other important factors that could cause actual results to differ materially from those projected. October Forward-25, looking 2018statements relating toincluded Diamondback’s in this presentation pending merger also with involve Energen certain Corporation risks and uncertainties (“Energen”),discussed which contains, or referenced amongin other Diamondback’s things, additional 424(b)(3) riskprospectus factors relating filed with to the the pending SEC on merger completion thatof could the pending cause the merger, resultsincluding to differthe materially ability to from successfully those expected integrate bythe thebusinesses, management theof occurrence Diamondback of any orevent, Energen change . These or other include circumstances the expected that timing could and give likelihood rise to the of shareholders termination of ofthe Energen merger may agreement, not approve the the possibility merger agreement, that stockholders the riskof that Diamondback the parties may maynot notbe approve able tothe satisfy issuance the conditions of new shares to theof pending common merger stock inin a timely the pending manner merger or at all, or risks that adverse related to effects disruption on theof market management price of Diamondback’s time from ongoing common business stock operations or Energen’s duecommon to the pending stock, the merger, risk ofthe anyrisk unexpected that anycosts announcements or expensesrelating resultingto from the the pending pending merger merger, could the have risk of personnel litigation and relating maintain to the relationships pending merger, with their the risk suppliers that the and pending customers merger and on have their an adverse operating effect results onand the businesses ability of Diamondback generally, the and risk Energen the pending to retain merger customers could distract and retain management and hire key of both not operating entities and as effectively they will incur and efficiently substantialas costs, expected, the risk the that riskproblems that the combined may arise in company successfully may integrating be unable to the achieve businesses synergies of the orcompanies, other anticipated which may benefits result ofin the thepending combined merger company or it may are difficult take longer to predict than expected and are beyond to achieve Diamondback’s those synergies or Energen’s or benefits control, and other including important those factors detailed that incould Diamondback’s cause actual annual results reports to differ onmaterially Form 10-K, from quarterly those projected reports on . Form All such 10factors -Q and annual currentreports reports on on Form Form 10 8-K -K, that quarterly are available reportson onits Form website 10-Q atand http://www current reports .diamondbackenergy on Form 8-K .that comare andavailable on the SEC’s on Energen’s website at website http://www at http://www .sec.gov, and .energen those .com detailed and on in Energen’s the SEC’s accurate website .at http://www.sec.gov. All such forward-looking statements are based on assumptions that Diamondback or Energen believe to be reasonable but that may not prove to be update Any forward any forward -looking -looking statement statement, speaks only whether as of as the a result date on of new which information, such statement future isevents made,or and otherwise, Diamondback except and as required Energen,by asapplicable may be applicable, law. Readers undertake are cautioned no obligation not toto place correct undue or reliance on these forward-looking statements that speak only as of the date hereof. estimates The presentation due to,also among contains otherthe things, Company’s uncertainty updated in drilling 2018 production schedules,guidance changes.in The market actualdemand levels ofand production, unanticipated capitaldelays expenditures in production and expenses . These may estimates be higher are based or lower onthan numerous these assumptions, assumptions may including not prove assumptions to be accurate, related to which number could ofresult wells drilled, in actual average resultsspud differing to release materially times, from rig count, estimates and . If production any of the rates rigs for currently wells placed being utilized on production or intended . All orto any beof utilized these becomes number of unavailable wells. Similarly, for any average reason, spud andto the release Company times is may not able not be to secure maintained a replacement in 2018. No onassurance a timely basis, can be we made maythat not new be able wells to will drill,produce complete in and line with placehistoric on production performance, the expected or that existing commodity wells prices will continue and the potential to produce forin unanticipated line with expectations increases.in Our costs ability associated to fund with our 2018 drilling, andproduction future capital andbudgets transportation is subject . Into addition, numerous ourrisks production and uncertainties, estimate assumes including there volatility will not in business be any new . Forfederal, additional state discussion or local of regulation the factors of that portions may of cause theus energy not to industry achievein our which production we operate, estimates, or an see interpretation the Company’s of existing filings with regulation, the SEC,that including will be itsmaterially forms 10-K, adverse 10-Q and to our 8-K and prospective any amendments data to reflect thereto events . We or circumstances do not undertake afterany the obligation date of thisto presentation release publicly . Therefore, the results you are ofcautioned any future not revisions to placewe undue may reliance make to onthis this information prospective.data or to update this

Important Information for Investors and Shareholders Oil and Gas Reserves with The SEC reasonable generally certainty permitsto oilbe and recoverable gas companies, in future in filings years made from known with the reservoirs SEC, to disclose under existing provedeconomic reserves,and which operating are reserve conditions, estimates and that certain geological probable and and engineering possible reserves data demonstrate that meet the contained SEC’s definitions in this presentation for such terms were.prepared The Company by Ryder discloses Scott only Company, estimated L.P., an proved independent reservesengineering in its filings with firm,the andSEC comply . Thewith Company’s definitions estimated promulgated provedby reserves the SEC as . Additional of December information 31, 2017 on locations, the Company’s which may estimated prove toproved be incorrect reserves in ais number contained of material in the Company’s ways. Actual filings number with the of locations SEC. This that presentation may be drilled alsomay contains differthe substantially Company’s . internal estimates of its potential drilling Non-GAAP Financial Measures investors, Consolidated lenders Adjusted and rating EBITDA agencies is a supplemental . We definenon Consolidated -GAAP financial Adjusted measure EBITDA that asisnet used income by management (loss) plus non and-cash external (gain) users lossof onour derivative financialinstruments, statements, net, suchinterest as industry expense, analysts, net expense, depreciation, assetdepletion retirement and obligation amortization accretion expense, expense, impairment income tax of oil (benefit) and natural provision gas and properties, non-controlling non-cash interest equity in based net income compensation (loss). Consolidated expense, capitalized Adjustedequity EBITDA -based is notcompensation a measure of net more income effectively (loss)evaluate as determined our operating by United performance States’ generally and compare accepted the accounting results ofprinciples, our operations or GAAP from . Management period to period believes without Consolidated regard toAdjusted our financing EBITDA methods is useful orbecause capital structure it allows.it We to add depending the items upon listed accounting above tomethods net income and(loss) bookinvalues arriving ofat assets, Consolidated capital structures Adjusted EBITDA and the because method these by which amounts the can assets vary were substantially acquired.from Consolidated companyAdjusted to company EBITDA within should our industry not be items considered excluded as an from alternative Consolidated to, orAdjusted more meaningful EBITDA are than, significant net income components (loss) as in determined understanding in accordance and assessing witha GAAP company’s or as an financial indicator performance, of our operating such as performance a company’sor cost liquidity of capital . Certain and not tax structure, be comparable as wellto asother the historic similarly costs titled of depreciable measures of assets, othernone companies of which orare to components similar measures of Consolidated in our revolving Adjusted credit EBITDA facility . Our and computations the indenture of Consolidated governing our Adjusted senior notes EBITDA . For may a reconciliation of Consolidated Adjusted EBITDA to net income (loss), and other non-GAAP financial measures, please refer to filings we make with the SEC. Non-Solicitation sell Thisany presentation securities or may a solicitation be deemedof toany relate vote toor a approval pending .merger between Diamondback and Energen and does not constitute an offer to buy or sell or the solicitation of an offer to buy or Other Important Information for Investors and Stockholders statement In connection waswith declared the pending effective merger by the with SECEnergen, on October Diamondback 24, 2018 and filed includes with the a SEC jointaproxy registration statement statement of Diamondback on Form S-4, and asEnergen amended and (Registration also constitutes No. 333 a - prospectus 227328), which of Diamondback registration offering (“thejoint ofproxy securities statement/prospectus”) shall be made except . Each by of means Diamondback of a prospectus and Energen meeting alsothe filed requirements and may in the of future Section file 10other of the relevant U.S. Securities documents Actwith of 1933, the SEC as regarding amended.the A definitive pending merger joint proxy . No statement/prospectus of for Diamondback and/or Energen was mailed to stockholders of Diamondback and shareholders of Energen on October 26, 2018. DOCUMENTS INVESTORS AND THAT SECURITY WERE PREVIOUSLY HOLDERS OF FILED DIAMONDBACK AND MAY IN THE AND FUTURE ENERGEN BE FILED ARE URGED BY EITHER TODIAMONDBACK READ THE REGISTRATION OR ENERGEN STATEMENT, WITH THE SEC JOINT CAREFULLY PROXY STATEMENT/PROSPECTUS AND IN THEIR ENTIRETY BECAUSE AND OTHER THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PENDING MERGER. maintained Investors and by security the SEC holders at http://www can obtain .free sec.gov copies . Copies of these of documents the documents and other fileddocuments with the containing SEC by Diamondback important information are available aboutfree Diamondback of chargeand onEnergen Diamondback’s through the website website at http://www phone at 432 .diamondbackenergy -221-7467. Copies of .com the documents or by contacting filed with Diamondback’s the SEC by Energen Investorare Relations available Department free of charge by email on Energen at IR@Diamondbackenergy website at http://www .com, .energen alawlis@diamondbackenergy .com or by phone at 205- .com, 326-2634 or by . Information Diamondback, about Energen the directors and certain andof executive their respective officers directors of Energen and is set executive forth in officers Energen’s mayproxy be deemed statement to be for participants its 2018 annual in the meeting solicitation of shareholders, of proxies inwhich respect was of filed the pending with themerger SEC on . March the SEC22, on2018 April.27, Information 2018. These about documents the directors can be and obtained executive free officers of charge of Diamondback from the sources is setindicated forth in its above proxy . statement for its 2018 annual meeting of shareholders, which was filed with proxy Other statement/prospectus information regardingand the other participants relevant in materials the proxyfiled solicitations with theand SEC a on description October 25, of2018 their. direct Investors andshould indirect read interests, the joint byproxy security statement/prospectus holdings or otherwise, carefully is contained before making in the joint any voting or investment decisions. You may obtain free copies of these documents from Diamondback or Energen using the sources indicated above.

Diamondback Energy: Leading Pure-play Permian Operator Permian pure-play with >394,000 pro forma net acres Diamondback Pro Forma Acreage Map ~7,200 net horizontal locations Industry leading corporate returns, growth within cash Diamondback Energen Quinn Ranch flow and pro forma Tier 1 Inventory depth Industry leading growth profile and execution Targeting 50% annual production growth in 2018; 170 -175 gross horizontal completions with an average lateral length of ~9,300 feet 2018 Plan – Maximize corporate-level returns through organic growth within cash flow Peer-leading cash margins and capital costs per completed lateral foot Announced Pending Acquisition of Energen Corporation Shareholder meetings to vote on the previously announced transaction scheduled for November 27th; deal expected to close shortly thereafter pending shareholder approvals Pro Forma Capital Strategy: (1) Pro Forma Inventory Overview Significant multi-year growth within cash flow and increasing return of capital program Immediate focus on value enhancement from primary and Enterprise Value ($bn)(1) $16.3 $8.1 $24.4 secondary synergies Net Permian Acres(2) 216,000 178,000 394,000 Tier One Permian Acres(3) 174,000 89,000 263,000 Enact “grow and prune” strategy to high-grade capital Tier One Permian Acres (incl. Quinn)(3) 174,000 99,000 273,000 allocation Net Locations 3,260 3,901 7,162 Source: Company data, public filings, and FactSet. Market data as of 11/6/2018. 4 (1) Gives effect to Spanish Trail North acquisitions that closed 10/31/2018. (2) Midland and Delaware only. Energen acreage includes 10,000 Quinn Ranch net acres. (3) IRR greater than 50% at $60 WTI in at least one zone.

Diamondback: Investment Highlights ¡» Q3 2018 production of 123.0 Mboe/d (72% oil), up 9% q/q and 45% year over year ¡» Realized cash margins of over 81% in Q3 2018; Q3 annualized ROACE of 11.3% Q3 Highlights ¡» Update on announced Energen merger: Received regulatory approval; shareholders to vote by November 27th with deal expected to close shortly thereafter pending approval ¡» Core Permian footprint – >394,000 pro forma net acres with ~7,200 net horizontal locations across the Midland and Delaware basins(1) ¡» Acquired ~29,100 net acres in Northwest Martin and Northeast Andrews counties (“Spanish Trail North”) from multiple sellers; transactions closed October 31st Accretive Midland Basin ¡» Includes 3,646 net adjacent acres with current production of ~3,500 boe/d(2) and ORRI Acquisitions increasing NRI by 1% across majority of Ajax acreage ¡» >450 net potential locations; 285 locations across three zones with estimated IRR’s >100% ¡» Accretive on NAV, acreage, top quartile inventory and 2019 financial metrics ¡» Increased Gray Oak volume commitment to 100,000 bo/d; increases total commitment on new long-haul pipelines to 200,000 bo/d (50% take or pay) ¡» Rattler Midstream exercising right to acquire 10% equity interest in Gray Oak Pipeline, Midstream Update subject to certain closing conditions ¡» 2019: >100,000 gross bo/d at fixed discount to Gulf Coast pricing (MEH and Brent); remainder of production covered via term sales agreements ¡» 2020+: 225,000 bo/d of FT to Gulf Coast ¡» Full year 2018 production guidance implies 50% y/y growth at midpoint within cash flow Industry-Leading Growth, Capital Efficiency and Cost ¡» Cash flow positive YTD through Q3 2018, as well as for the past 15 quarters in aggregate ¡» Net debt to Q3 2018 Annualized Adjusted EBITDA of 1.2x(3) Structure ¡» Quarterly dividend of $0.125/share payable on November 26, 2018 Source: Company data and filings. Financial data as of 9/30/2018 unless otherwise noted. 5 (1) Net acreage and net locations based in on internal company estimates pro forma for the pending Energen acquisition. (2) ExL estimated net production as of 11/6/2018. (3) Excludes cash from Viper. Does not take into account the Spanish Trail North acquisitions that closed on 10/31/2018. Net debt to Q3 2018 annualized Adjusted EBITDA is net debt as of 9/30/2018 divided by annualized Adjusted EBITDA for the three months ended 9/30/2018. See the disclaimers at the beginning of this presentation.

Third Quarter Execution and 2018 Activity Overview Year Over Year Execution 2018 Production and Activity Outlook Q3 2017 Q3 2018 122,975 Targeting 50% y/y production growth within cash flow 85,029 Daily Production 170 – 175 Gross operated completions 20% 19% 118.5 – 119.5 12+ Cash Costs (% of $/Boe) Mboe/d Average operated hz. rigs 79.2 Mboe/d $37.89 ~9,300’ $30.58 2017 2018E Average lateral length Cash Margins ($/Boe)(1) 2018 Capital Budget $372 $232 Diamondback 2018 Capital Activity Adjusted EBITDA Midland Basin D,C&E per Foot $760 – $810 Delaware Basin D,C&E per Foot $1,175 – $1,225 $1.67 $1.33 Diamondback Capex Budget ($MM) Adjusted EPS D,C&E and Non-Operated Properties $1,250 – 1,300 11.3% Infrastructure $250 – $275 9.5% Total 2018 Capital Budget $1,500 – $1,575 ROACE(2) Source: Company data, filings and estimates. 6 (1) Cash margins calculated as realized price per boe less LOE, gathering and transportation, production taxes and cash G&A expenses. (2) Return on Average Capital Employed (“ROACE”) calculated as consolidated annualized EBIT divided by average total assets less cash for current and prior period less average current liabilities for current and prior period.

Acquisition Track Record and Subsequent Per Share Value Creation Value Creation to Shareholders(1) FANG Acquisitions and EBITDA/Share Growth Since IPO(2) 201 201 Q4 Normalized Growth EBITDA/share EPS WTI Crude Q4 Q1 Q2 Q3 Acquisitions Q4 Q1 Q2 Q3 Q4 Q1 Q2 Adjusted Q3 Q4 Q1 EBITDA/Share Q2 Q3 Q4 Q1 Q2 Q3 Q4 Crude Q1 Q2 Oil Q3PF $18,000 1000% Pecos $2.55 billion 100% 61% 34% 900% 800% Reeves / Ward 184% 209% $560 million 55% 700% Growth NW Howard 600% /Bbl 307% $ $404 million 20% 111% 500% WTI / Glasscock / Midland 400% 174% $524 million 88% EBITDA/Share -29% 300% SW Martin 200% 215% $188 million 126% -30% 100% IPO NW Martin / Viper 253% 377% 0% $605 million Q4 Q2 Q4 Q2 Q4 Q2 Q4 Q2 Q4 Q2 PF -34% 2012 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 Q4 FANG has grown EBITDA/share over 800% since IPO with oil prices down 21% over same period Source: Company data and filings. Acquisition prices as of the date announced. Note: NW Martin / Viper acquisitions are combined as both transactions were completed in Q3 2013. 7 (1) Reflects Adjusted EBITDA/share and adjusted EPS performance relative to WTI price per barrel. Performance period benchmarked to the quarter each acquisition closed. (2) Cumulative quarterly Adjusted EBITDA/share relative to average quarterly WTI price per barrel since Q4 2012.

Substantial Pro Forma Economic Inventory Net Midland Basin Location by Zone / Lateral(1) Net Delaware Basin Locations by Zone / Lateral 5,000’+ 7,500’+ 10,000’+ Total Avg. Lateral 5,000’+ 7,500’+ 10,000’+ Total Avg. Lateral MS 162 264 317 743 8,100’ 2BS 107 92 97 296 7,300’ LS 260 394 424 1,078 7,900’ 3BS 222 155 163 540 7,100’ WCA 209 249 344 802 7,900’ WCA 326 270 249 845 7,100’ WCB 194 242 307 744 7,900’ WCB 358 286 306 951 7,400’ Other 126 372 342 840 8,100’ Other 151 73 98 323 6,800’ Total 952 1,521 1,734 4,207 8,000’ Total 1,165 877 913 2,955 7,100’ Midland Basin Premium Zone Spacing Assumptions vs. Peers(2) Delaware Basin Premium Zone Spacing Assumptions vs. Peers(2) FANG EGN Peer 1 Peer 2 FANG EGN Peer 2 Peer 3 Middle 2nd Bone Spraberry Spring 3rd Bone Lower Spring Spraberry Upper Wolfcamp A Wolfcamp A Lower Wolfcamp A Wolfcamp B Wolfcamp B TOTAL TOTAL 28 28 34 38 20 20 24 29 wells/section wells/section Conservative spacing assumptions and depth of Tier One, long lateral inventory to drive capital efficient growth Source: Company data, filings and estimates. 8 (1) Includes Ajax and ExL transactions that closed on 10/31/2018 and pro forma for the Energen merger as announced of 8/14/2018. (2) Midland peers include QEP and PE. Delaware peers include PE and JAG.

Multiple Acquisitions Create Spanish Trail North Overview of Acquisitions (Closed 10/31/2018): Spanish Trail North Acreage Map  $1.21B cash consideration and 2.58MM FANG shares 29,139 net acres (~25,000 in Martin / Andrews counties) >450 net potential locations; 285 in 3 zones with estimated IRRs >100% (top quartile of FANG’s current inventory) Average lateral length of ~9,300 feet  ExL bolt-on acquisition adds >3,600 net surface acres within core prospectivity windows for WCA, MS and LS ~3,500 boe/d of estimated current net production(1) Strategic Rationale / Synergies:  ~6,500 acres adjacent to existing acreage Shared infrastructure assets (Rattler Midstream): 40 Mb/d of SWD gathering lines and disposal capacity; growing to 60 Mb/d by Q4 2018 of existing fresh water Net Potential Acquisition Locations By Zone / Lateral 45 Mb/d production 20 miles of fresh water / SWD gathering lines 5,000’+ 7,500’+ 10,000’+ Total Avg. Lateral >700 acres of surface MS 9 58 53 120 9,042’  Acreage >75% NRI opportunity for VNOM dropdown LS 8 52 56 115 9,255’  Acreage HBP allows for efficient development with 12+ WCA 9 46 52 107 9,394’ well multi-zone pads WCB 9 47 53 109 9,409’  Accretive on NAV, acreage, top quartile inventory and Total 35 203 214 452 9,268’ 2019 financial metrics Source: Company data, filings and estimates and data from the Sellers. 9 (1) Estimated daily net production for ExL acquisition as of 11/6/2018.

Spanish Trail North: Prolific Well Results Across Three Proven Zones 2 3 4 5 UL Comanche Unit A4144 4 UL Comanche Unit A4144 5 UL Comanche Unit A4144 6 Vineyard Hz B Unit 0601WA EXL Petroleum EXL Petroleum EXL Petroleum Ajax Resources IP30/1k’: 145 boe/d (93% oil) IP30/1k’: 157 boe/d (91% oil) IP30/1k’: 196 boe/d (95% oil) IP30/1k’: 174 boe/d (93% oil) 1 H UL Comanche Unit A4144 2 UL Tawny Unit 8-12 1LS EXL Petroleum Diamondback IP30/1k’: 190 boe/d (93% oil) ~3,500 acres IP30/1k’: 147 boe/d (91% oil) A ~78% NRI I Vineyard Hz O Unit 1701LS ~11,000 acres Mabee Breedlove 4001LS Ajax Resources Diamondback IP30/1k’: 129 boe/d (92% oil) ~75% NRI IP30/1k’: 159 boe/d (88% oil) B J University 6-40 Unit 105LS Mabee Breedlove 4003LS Ajax Resources Diamondback IP30/1k’: 160 boe/d (92% oil) IP30/1k’: 171 boe/d (88% oil) 5 C K K UL Comanche Unit A4144 1 A Vineyard Hz B Unit 0601LS EXL Petroleum L 6 Ajax Resources IP30/1k’: 152 boe/d (91% oil) Martin IP30/1k’: 108 boe/d (93% oil) y 3 D 4 1 L UL Mason East Unit 3LS 2 C University 6-16 26 27 101LS Diamondback Ajax Resources IP30/1k’: 115 boe/d (90% oil) B ~14,600 acres IP30/1k’: 122 boe/d (93% oil) ~79% NRI on 11,000 acres E x UL Mason East Unit 5LS x J ~75% NRI on 3,600 acres UL MS Hz Blk 6 Unit 4106 I Diamondback EnergyQuest II IP30/1k’: 113 boe/d (91% oil) D E IP30/1k’: 149 boe/d (90% oil) F F y UL Mason East Unit 4LS UL MS Hz Blk 6 Unit 3107 Diamondback Diamondback Ajax Resources IP30/1k’: 124 boe/d (90% oil) IP30/1k’: 135 boe/d (91% oil) H G Ajax Resources G 6 UL Carpenter 7- 20 4LS ExL Petroleum Vineyard Hz O Unit 1701WA Diamondback Ajax Resources IP30/1k’: 139 boe/d (88% oil) IP30/1k’: 132 boe/d (92% oil) Middle Spraberry Lower Spraberry Wolfcamp A Source: Management data and estimates and data from the Sellers. 10

Corporate Level Full-Cycle Economics and Returns Matter ¡» Diamondback’s cost structure and disciplined approach to investment facilitates greater per share EBITDA and earnings growth, and is reflected in an industry-leading ROACE Return on Average Capital Employed (“ROACE”) Over Time(1) 15% 12% 9% 13.8% ROACE 6% 12.5% 11.3% 10.9% 11.0% 10.3% 8.9% 9.7% 9.5% 3% 6.2% 8.5% 2.7% 0% FY 2014 FY 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 YTD 2018 Q3 2018 Realized Price ($/Boe) $69.74 $36.98 $25.09 $33.55 $34.39 $38.72 $41.93 $38.18 $38.25 $45.31 $49.00 $46.59 Adjusted EPS $2.24 $1.81 $0.02 $0.26 $0.54 $0.90 $1.04 $1.25 $1.33 $1.56 $4.90 $1.67 Normalized Adjusted EBITDA/share Growth Versus Peers 350% FANG: +250% Peer 1: +226% 300% Peer 2: +168% 250% Peer 3: +101% 200% Peer 4: +69% 150% Peer 5: +40% 100% Peer 6: +38% 50% Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Source: Company data, Bloomberg and latest peer filings as of 11/6/2018. Peers include EGN, PE, PXD, CPE, LPI and CXO. 11 (1) Return on Average Capital Employed (“ROACE”) calculated as consolidated annualized EBIT divided by average total assets less cash for current and prior period less average current liabilities for current and prior period. In this presentation, the Company defines Consolidated EBIT as Consolidated Adjusted EBITDA before depreciation, depletion and amortization. For a definition and reconciliation of Consolidated Adjusted EBITDA, see “Froward Looking Statements” included in this presentation, and filings the Company makes with the SEC, including its form 10-k.

Consistent Capital Discipline and Growth Within Cash Flow ¡» FANG has a track record of achieving robust production growth while spending within cash flow ¡» Cumulative cash flow has more than offset D,C&E and Infrastructure spending since the beginning of 2015 ¡» Asset base can support differential growth within cash flow and increasing return of capital program D,C&E CAPEX Operating Cash Flow Infrastructure CAPEX Total Production (Boe/d) Oil Production (Bo/d) $500 140,000 $ 426 $ 396 120,000 $400 425 307 318 $ 387 100,000 $ $ $ $300 258 WTI Oil ($/Bbl) 80,000 $ 339 MM $ $ Boe/d 180 $ 251 60,000 $200 244 $ 151 219 $ $ 121 116 $ 40,000 91 93 94 $ $ 176 84 $ 86 $ $ $ $ $100 $ 140 63 $ $ 99 101 105 106 20,000 $ $ $ 77 73 $ $ $ 49 $0 $ 0 Since Q1 2017, FANG has generated $39 million in free cash flow, while doubling production Source: Company filings, management data and estimates. 1

Balanced, Capital Efficient Development ¡» Completing an average ~1,400 lateral feet per day per completion crew in the Midland Basin ¡» Completing an average of ~900 feet per day in the Delaware Basin Completed Lateral Footage by Quarter Completed Lateral Footage Average Lateral Length per Well 12,000 500,000 464,995 450,000 414,434 10,000 383,458 400,000 350,000 8,000 315,004 Footage Length 300,000 270,060 teral 6,000 230,472 250,000 220,194 Lateral La 206,356 169,302 200,000 Average 4,000 143,400 150,000 113,220 Completed 94,523 99,806 90,970 100,000 2,000 61,672 50,000 0 0 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Drilled / Completed 15 / 18 11 / 13 21 / 20 17 / 14 16 / 8 15 / 11 17 / 21 25 / 23 28 / 26 34 / 35 42 / 24 46 / 38 41 / 35 53 / 50 40 / 43 wells FANG continues to maximize long-lateral efficient pad development across its acreage Source: Company filings, management data and estimates.

Southern Delaware Basin Wolfcamp A Update Southern Delaware WCA Performance – Normalized to 7,500’ (Mbo) Central Type Log and Landing Targets 200 FANG 175 Primary MBBL Targets 150 125WC A U 1,100 MBOE (975 MBO) SNL 36-32 2WA 100 NEAL LETHCO STATE 20-1H Oil-In-Place PRODUCTION, COLDBLOOD 7372 1WA WALER STATE UNIT 4 1WA WC A & B OOIP A 75 STATE ARDENNES 1101WA OIL WARLANDER WEST 501WA 53 MMbbls/sec. WC STATE BIGGS 12A-2 2WA 50 L CUM NEAL LETHCO 39-37 UNIT 2WA AYERS 24 2WA JANE M GRAVES A 3WA WOLFCAMP 25 STATE NEAL LETHCO 10-9 B 2WA BLAZER UNIT 14 1WA B 0 STATE NEAL LETHCO 20-19 1WA WC 0 50 100 150 200 250 300U DAYS WELL COUNTY TARGET % Oil NOKOTA 19 DODT 1WA/2WA Reeves WCA 74% NEAL LETHCO A 17-18 1WA Pecos WCA 89% High-graded landing zones through NEAL LETHCO 10-9 B 2WA Pecos WCA 80% integration of captured core and log JANE GRAVES A 3WA Reeves WCA 81% data; continue to receive high-res 3-D BLAZER UNIT 14 1WA Reeves WCA 82% seismic data NEAL LETHCO 39-37 UNIT 2WA Pecos L WCA 84% STATE BIGGS 12A-2 2WA Pecos L WCA 91% Well results confirming geologic AYERS 24 2WA Reeves WCA 82% assessment of rock quality WARLANDER 501 WA Reeves WCA 80% Source: Company filings, management data and estimates. 14 (1) Reflects average peak-24 hour IP rate as of 11/6/2018.

Near Term and Long Term Solutions for Permian Oil Takeaway Diamondback: Pro Forma In Basin Oil Takeaway  Volume-weighted average transport cost to Midland market: $1.00 - $1.25/Bbl (ex-Rattler) Purchaser Plains  Firm to Midland market on all barrels (ample reserved Gatherer: Reliance space on in-basin gathering systems) Purchaser Purchasers: Vitol, Oxy Plains Long Haul: EPIC  2019: FT agreements cover >100,000 gross bo/d at fixed discount Gulf Coast pricing (Brent, MEH) Gulf Gatherer: Coast differentials weakest Q4 2018 and Q1 2019, Nustar improving through remainder of 2019 Purchasers Shell, Koch, Term sales agreements cover remainder of barrels Vitol Long Haul:  Long term: 225,000 bo/d of FT to Gulf Coast markets EPIC 100,000 bo/d on EPIC for Midland Basin barrels Gatherers: Rattler, Enterprise, 100,000 bo/d on Gray Oak for Delaware Basin barrels Plains, Reliance 50% take or pay Purchasers: Trafigura, Oxy, Shell Long Haul: Majority on EPIC “Wellhead to water” solutions Purchaser Energen: Plains  Production supported by Basin-wide flow assurance with 85% of oil production on pipe Gatherers: Rattler, Oryx  Multi-year term purchasing contracts in place at Purchasers: Shell, Vitol Long Haul: Gray Oak Midland market prices  Hedging mitigates exposure to basis differentials ~50,000 net Bo/d of 2019 oil production hedged at ($5.13)/Bbl as of November 2018 Diamondback Energen Quinn Ranch Gray Oak and EPIC pipeline commitments and joint ventures provide Diamondback with “wellhead to water” solutions for the majority of projected standalone production for years to come, removing Midland market risk Source: Company filings, management data and estimates.

Build-out of Midstream Assets Through Rattler Midstream Rattler Midstream: Wholly-owned midstream subsidiary created by Rattler Midstream Asset Map  Diamondback Martin / Andrews: ⧫ Fresh Water  Interests fully aligned with upstream operations: ⧫ SWD Organic growth via accelerating development Assets located in all six core operating areas Energen adds significant existing capacity in both Reeves / Loving: Howard County: ⧫ Fresh Water ⧫ Spanish Trail: ⧫ Fresh Water the Midland and Delaware Basins SWD ⧫ Fresh Water ⧫ SWD ⧫ SWD  Energen’s extensive midstream assets will add ⧫ Crude Gathering critical mass for midstream value creation opportunities at Diamondback Pro Forma Capacity Overview Fee Stream Midland Delaware Glasscock County: ⧫ Crude Gathering SWD – Bbl/d 744,400 809,000 Pecos County / ⧫ SWD ⧫ Fresh Water Fresh Water – Bbl/d 371,200 369,500 ReWard: ⧫ Fresh Water Crude Oil – Bbl/d 90,000 176,000 ⧫ SWD ⧫ Crude Gathering (1) ⧫ Gas Gathering (Pecos) Natural Gas – Mcf/d -- 150,000 Total >1,205,600 >1,379,500 Diamondback Energen Quinn Ranch Rattler secures FANG’s access to vital midstream services and supports FANG’s low-cost operations via improving realizations and lowering LOE Source: Company filings, management data and estimates. 16 (1) Excludes 36,000 Mcf/d compression capacity.

Infrastructure Development Ahead of Continued Acceleration  >100,000 net Delaware Basin acres acquired in 2018 YTD Infrastructure Capital Spend 2016 with minimal infrastructure in place  Building out infrastructure, retaining 100% Total Infrastructure & Midstream ownership of assets with 100% utilization ~$205MM  Assets being set up for efficient, large scale development which is critical for capital efficient growth Batteries & Electricity (40%) Midstream (60%)  Over time, total infrastructure spend to trend Midland: ~15% Midland: ~10% to <10% of total capital like Midland Basin Delaware: ~25% Delaware: ~50% Capital Spend Breakdown Midland Basin Delaware Basin Pecos: 120 mW ReWard: 30 mW Oil Gathering: SWD: 216,000 bo/d 589,000 bbl/d substation substation 3% capacity capacity 5% 17% Gas Gathering: Fresh Water: 11% ~$60k / well ~$60k / well 150,000 mcf/d 740,700 bbl/d monthly savings monthly savings capacity capacity 72% for each ESP for each ESP 92% Improves Infrastructure & Reduces LOE ~8% of total ~28% of realizations Midstream as percent of total capital total capital CAPEX: Source: Company filings, management data and estimates.

Capital Structure and Liquidity ¡» Net Debt to Q3 2018 Annualized Adjusted EBITDA FANG’s Liquidity and Capitalization(2) of 1.2x(1); continue to target leverage below 2.0x FANG’s Consolidated Capitalization 9/30/2018 Pro Forma ($MM) ¡» In September 2018, FANG issued $750 million of Cash and cash equivalents $508 17 tack-on 4.750% Senior Notes; proceeds used to pay down revolver and to fund a portion of the Ajax FANG’s Revolving Credit Facility - 659 acquisition VNOM’s Revolving Credit Facility 297 297 4.750% Senior Notes Due 2024 1,250 1,250 ¡» In October 2018, FANG’s borrowing base was increased to $2.65 billion; FANG elected to increase 5.375% Senior Notes Due 2025 800 800 its commitment to $2.0 billion from $1.0 billion Total Debt $2,347 $3,005 previously FANG’s Standalone Liquidity 9/30/2018 Pro Forma Cash(1) $492 - ¡» Pro forma for the Ajax and ExL transactions, FANG Elected commitment amount 1,000 2,000 had standalone liquidity of over $1.3 billion as of FANG borrowing base 2,000 2,650 September 30, 2018 Liquidity $1,492 $1,341 FANG’s Debt Maturity Profile ($MM) $2,500 $2,000 $1,500 Pro Forma Undrawn $1,000 4.750% Senior 5.375% $500 FANG Credit Notes Senior Facility $0 Notes 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Source: Company Filings, Management data and Estimates. (1) As of 9/30/2018. Excludes cash from Viper. Does not take into account the Spanish Trail North acquisitions that closed on 10/31/2018. 18 (2) Pro forma liquidity reflects the remaining cash portion of the Spanish Trail North acquisitions that closed on 10/31/2018 as well as its increased borrowing capacity following its Fall 2018 redetermination of its revolving credit facility.

Updated 2018 Guidance growth of 50% Diamondback Viper Energy  Targeting annual production Energy, Inc. Partners LP within cash flow in 2018 Net Production – Mboe/d 118.5 – 119.5 16.75 – 17.25  2018 D,C&E CAPEX budget of $1,250 – $1,300 Oil Production – (% of Net 72% - 74% 69% – 73% Production) million from a 12+ average rig program; Unit Costs ($/boe) anticipate running 14 horizontal rigs in Q4 2018 Lease Operating Expenses $3.75 – $4.50 n/a  Anticipated infrastructure capital expenditures Gathering & Transportation $0.25 – $0.75 $0.20 – $0.40 of $250 - $275 million Cash G&A Under $1.00 $0.75 – $1.25  Expect to complete 170 – 175 gross horizontal Non-Cash Equity Based $0.50 – $1.00 $0.50 – $0.75 wells with an average lateral length of ~9,300 Compensation DD&A $11.00 – $14.00 $8.00 – $11.00 feet Interest Expense (net) $1.00 – $2.00  Targeting annual production growth of over Production and Ad Valorem 7.0% 7.0% 50% for Viper Energy Partners in 2018 Taxes (% of Revenue)(1) Corporate Tax Rate 20% - 23% n/a  2018 capital budget will target estimated Diamondback 2018 Capital Activity operating cash flow and drilling rigs will be Gross (Net) Horizontal Wells Completed 170 – 175 (146 – 154) added or dropped accordingly Midland Basin D,C&E per Foot $760 – $810 Delaware Basin D,C&E per Foot $1,175 – $1,225 Diamondback Capex Budget ($MM) 2018 Capital Budget $1,500 – $1,575 Source: Company filings, management data and estimates. 19 Note: Based on updated 2018 guidance provided on 11/6/2018, which is subject to numerous assumptions and risks. See the disclaimer at the beginning of this presentation. (1) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.

Differential Growth Within Cash Flow Return On and Return Of Capital Significant Resource Potential Conservative Financial Management Strategic Acquisitions Efficient Conversion of Resource to Cash Flow

APPENDIX

Current Hedge Summary Crude Oil (Bbls/day, $/Bbl) Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 26,000 7,000 4,000 4,000 3,000 Swaps - WTI $51.27 $55.29 $51.86 $51.59 $49.82 7,000 7,000 4,000 2,000 1,000 Swaps - MEH $71.06 $69.65 $74.64 $75.65 $75.74 10,000 5,000 2,000 2,000 2,000 Swaps - Brent $62.51 $72.82 $75.43 $74.95 $74.45 15,000 3,000 – – –Basis Swaps - WTI ($0.88) ($9.42) – – – Three Way Collars - WTI – 10,000 10,000 – – Floor / Ceiling – $55.00 / $70.76 $55.00 / $69.71 – – Three Way Collars - MEH 7,000 7,000 4,000 – – Floor / Ceiling $66.43 / $78.82 $66.43 / $77.56 $67.50 / $77.68 – – Three Way Collars - Brent – 8,000 8,000 4,000 2,000 Floor / Ceiling – $65.00 / $81.25 $65.00 / $81.25 $65.00 / $84.58 $65.00 / $87.90 Natural Gas (Mmbtu/day, $/Mmbtu) Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 20,000 – – – –Swaps $3.07 – – – – Source: Company data as of 11/6/2018. 22 (1) Sub-floors for three way collars are priced $10/Bbl below the respective floor price for each period.

Peer-Leading Cash Margins and Operating Costs Q3 2018 Cash Margins Versus Extended Peer Group ($/Boe)(1) 90% % of Realized Price ($/Boe) Cash Margin ($/Boe) $50 /Boe) 82% 81% $ 78% 78% 80% 77% 76% $40 74% 73% 73% 73% 72% 71% 70% 70% $37.89 69% 68% 67% $30 Realized 66% 65% of 62% /Boe 58% (% 60% 57% $20 $ Margin 50% $10 Cash 40% $0 Q3 2018 Cash Operating Costs Versus Extended Peer Group ($/Boe)(2) LOE Prod. taxes Cash G&A G&T $15.33 $16 $13.95 $12.65 $12.75 $12.80 $12.91 $11.46 $12.02 $12.21 $12.34 $11.04 $11.14 $11.21 $11.38 $12 $10.44 $10.77 $10.22 $8.70 $8.73 $8.96 $7.99 /Boe $8 $ $4 $0 Source: Company and latest peer filings as of 11/6/2018. Extended peers include JAG, PE, CPE, LPI, EOG, MTDR, PXD, CXO, EGN, CDEV, PDCE, XEC, REN, WPX, SM, QEP, NBL, ECA, DVN and AREX. 23 (1) Cash margins calculated as realized price per boe less LOE, gathering and transportation, production taxes and cash G&A expenses per boe. (2) Cash operating costs calculated as the sum of LOE, gathering and transportation, production taxes and cash G&A expenses per boe.

Viper Update    Viper Update ¡» Q3 2018 cash distribution of $0.580 per unit, up 72% over Q3 2017 ¡» Organic growth on legacy assets provide consistent volume and distribution growth ¡» Focused on mineral acquisitions in oil-weighted basins with high visibility towards active development ¡» Robust acquisition activity: 65 deals closed YTD through Q3 2018, adding 4,348 net royalty acres for a total of $521 million; increases asset base to 13,908 net royalty acres (38% FANG-operated) Distributions Have Tripled In Last Nine Quarters Production Growth and Acquisitions Since IPO $0.600 $120 $1,200 20,000 $1,050 $260 $0.500 $100 16,000 $900 $103 $0.400 $80 $750 12,000 /Bbl) mm) $158 $ (Boe/d) Distribution ( ( $ $39 $0.300 $0.600 $60 Price $600 $0.580 Oil Quarterly $0.480 $176 Production $0.460 WTI Acquisitions $450 8,000 $0.200 $0.337 $40 Net $0.332 $117 $0.250 $0.302 $300 $8 $0.230 $68 $0.250 $0.220 $0.258 $0.100 $20 4,000 $0.200 $0.207 $126 $0.190 $150 $0.189 $12$2 $9 $0.149 $32 $0.000 $0 $58 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 – 0 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 ‘14 ‘14 ‘15 ‘15 ‘15 ‘15 ‘16 ‘16 ‘16 ‘16 ‘17 ‘17 ‘17 ‘17 ‘18 ‘18 ‘18 ‘14 ‘14 ‘15 ‘15 ‘15 ‘15 ‘16 ‘16 ‘16 ‘16 ‘17 ‘17 ‘17 ‘17 ‘18 ‘18 ‘18 Source: Company data and filings. 24

“Limelight” Prospect – Emerging Mississippian Oil Potential Diamondback “Limelight” Acreage Map “Limelight” Type Log Atok Bend Early geologic Springer assessments indicate “Seal” the target to be a “Limelight” significant oil source and producing interval. Barnett  ~22,000 acres acquired at low entry cost “Limelight” Zone of Interest  Mississippian Barnett (Springer-Chester equiv.) and Meramec Meramec are prospective on “terrace” structures along Miss Lime the Central Basin Platform and Midland Basin boundary, at depths where maturation is within peak oil window Woodford  Analogous to recent successful Mississippian horizontal activity in Andrews County Devonian Cher Lime  Plan to begin initial appraisal of acreage in 2019 Stratigraphic and geochemical characteristics are comparable to Andrews County Barnett/Meramec Source: Company filings, management data and estimates. 25

High Growth, Oil Weighted Reserves Total Reserves Growth (MMboe) (1) 2017 total proved reserves increased 63% y/y FANG Standalone VNOM 335.4 to 335.4 MMboe 38.2 FANG standalone reserves increased 71% y/y to 205.5 297.1 MMboe 156.9 31.4 112.8 62% proved developed; conservatively booked 26.3 297.1 63.6 18.5 174.0 Proved developed F&D for 2017 was $9.09/Boe 10.3 130.6 53.3 94.3 2013 2014 2015 2016 2017 F&D Costs 1P Reserves – By Commodity 1P Reserves – By Category Natural ($/boe) 2014 2015 2016 2017 Gas 14% Drill Bit F&D(2) $11.09 $5.51 $6.31 $7.22 PUD NGL 16% 38% PD Reserve Oil 62% 793% 465% 409% 549% 70% Replacement(3) Organic Reserve 626% 422% 380% 443% Replacement(4) 335.4 MMBOE Source: Company Filings, Management Data and Estimates. (1) Historical FANG reserves per independent reserve report prepared by Ryder Scott as of 12/31/2017. 26 (2) Defined as exploration and development costs divided by the sum of extensions and discoveries and revisions. 2014 F&D excludes 6.2 MMboe of revisions due to vertical PUD downgrades. 2015 F&D excludes 14.6 MMboe of revisions due to vertical and horizontal PUD downgrades. (3) Defined as the sum of extensions, discoveries, revisions, and purchases, divided by annual production. (4) Defined as the sum of extensions, discoveries, and revisions, divided by annual production.

Diamondback Energy Corporate Headquarters Adam Lawlis, Director, Investor Relations 500 West Texas Ave., Suite 1200 (432) 221-7400 Midland, TX 79701 ir@diamondbackenergy.com www.diamondbackenergy.com