Investor Presentation May 2018

1 Investor Presentation May 2018

Forward Looking Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that Diamondback Energy, Inc. (the Company or Diamondback ) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, expect, may, estimates, will, anticipate, plan, intend, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s acquisitions, drilling programs, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management's expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced in the Company s filings with the Securities and Exchange Commission ( SEC ), including its Forms 10-K, 10-Q and 8-K and any amendments thereto, financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company s business plan, impact of compliance with legislation and regulations, successful results from the Company s identified drilling locations, the Company s ability to replace reserves and efficiently develop and exploit its current reserves, the Company s ability to successfully identify, complete and integrate acquisitions of properties or businesses and other important factors that could cause actual results to differ materially from those projected. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether asa result of new information, future events orotherwise, except asrequired by applicable law. The presentation contains the Company s updated 2018 production guidance. The actual levels of production, capital expenditures and expenses may be higher or lower than these estimates due to, among other things, uncertainty in drilling schedules, changes in market demand and unanticipated delays in production. These estimates are based on numerous assumptions, including assumptions related to number of wells drilled, average spud to release times, rig count, and production rates for wells placed on production. All or any of these assumptions may not prove to be accurate, which could result in actual results differing materially from estimates. If any of the rigs currently being utilized or intended to be utilized becomes unavailable for any reason, and the Company is not able to secure a replacement on a timely basis, we may not be able to drill, complete and place on production the expected number of wells. Similarly, average spud to release times may not be maintained in 2018. No assurance can be made that new wells will produce in line with historic performance, or that existing wells will continue to produce in line with expectations. Our ability to fund our 2018 and future capital budgets is subject to numerous risks and uncertainties, including volatility in commodity prices and the potential for unanticipated increases in costs associated with drilling, production and transportation. In addition, our production estimate assumes there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business. For additional discussion of the factors that may cause us not to achieve our production estimates, see the Company s filings with the SEC, including its forms 10-K, 10-Q and 8-K and any amendments thereto. We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective data or to update this prospective data to reflect events or circumstances after the date of this presentation. Therefore, you are cautioned not to place undue reliance on this information. Oil and Gas Reserves The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC s definitions for such terms. The Company discloses only estimated proved reserves in its filings with the SEC. The Company s estimated proved reserves as of December 31, 2017 contained in this presentation were prepared by Ryder Scott Company, L.P., an independent engineering firm, and comply with definitions promulgated by the SEC. Additional information on the Company s estimated proved reserves is contained in the Company s filings with the SEC. This presentation also contains the Company s internal estimates of its potential drilling locations, which may prove to be incorrect in a number of material ways. Actual number of locations that may be drilled may differ substantially. Non-GAAP Financial Measures Consolidated Adjusted EBITDA is a supplemental non-gaap financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Consolidated Adjusted EBITDA as net income (loss) plus non-cash (gain) loss on derivative instruments, net, interest expense, net 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 (benefit) provision and non-controlling interest in net income (loss). Consolidated Adjusted EBITDA is not a measure of net income (loss) as determined by United States generally accepted accounting principles, or GAAP. Management believes Consolidated Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We add the items listed above to net income (loss) in arriving at Consolidated Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Consolidated Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Consolidated Adjusted EBITDA are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Consolidated Adjusted EBITDA. Our computations of Consolidated Adjusted EBITDA may not be comparable to other similarly titled measures of other companies or to similar measures in our revolving credit facility and the indenture governing our senior notes. For 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. 2

Diamondback Energy: Leading Pure-play Permian Operator Permian pure-play with 207,000+ net acres Six core areas with 1,000 Mboe+ EURs in multiple intervals normalized to 7,500 feet ~4,200 gross locations with 72% average working interest and average lateral length of ~8,150 feet Significant resource upside from zone delineation and downspacing Industry leading growth profile and execution Targeting over 40% annual production growth in 2018; 170-190 gross completions with average lateral 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 (1) Area Diamondback Inventory Overview Net Surface Acres Gross 2018 Locations (3) Rig Count Midland Basin ~84,000 ~2,200 6 7 Delaware Basin ~105,000 ~2,000 4 5 Exploratory ~19,000 -- appraisal Total 207,000+ ~4,200 10 12 NASDAQ Symbol: FANG Market Cap: $13,306 million Net Debt: $1,634 million Enterprise Value: $16,205 million Share Count: 99 million Diamondback Acreage Map Core Delaware Basin Development Market Snapshot (2) Annual Dividend: $0.50 (0.4% current yield) Core Midland Basin Development 1 MMBoe+ 7,500 ft. EURs 3 Source: Company data, filings and estimates. Peers include CPE, CXO, EGN, LPI, PE, PXD and RSPP. (1) Cash margins calculated as realized price per boe less LOE, gathering and transportation, production taxes and cash G&A expenses. (2) Market data as of 5/8/2018. Net debt as of 3/31/2018. (3) Location assumptions based on internal company estimates as of 12/31/2017.

First Quarter Execution and 2018 Activity Overview Year Over Year Execution 2018 Production and Activity Outlook Daily Production Q1 2017 2017 Q1 2018 92,872 102,607 61,610 $9.31 $8.28 $8.42 Targeting >40% y/y production growth within cash flow 170 190 Gross operated completions Cash Costs ($/Boe) $32.62 $37.03 $42.13 79.2 Mboe/d 110 116 Mboe/d 2017 2018E 10 12 Operated horizontal rigs ~9,300 Average lateral length Cash Margins ($/Boe) (1) $175 $302 $341 2018 Capital Budget Diamondback 2018 Capital Activity Adjusted EBITDA $1.56 $1.64 Midland Basin D,C&E per Foot $760 $810 Delaware Basin D,C&E per Foot $1,125 $1,225 $1.04 Diamondback Capex Budget ($MM) Adjusted EPS D,C&E and Non-Operated Properties $1,175 1,325 8.8% 12.3% 13.3% Infrastructure $125 - $175 ROACE (2) Total 2018 Capital Budget $1,300 $1,500 4 Source: Company data, filings and estimates. (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 for current and prior period less average current liabilities for current and prior period.

Diamondback: Investment Highlights Q1 Highlights Q1 2018 production of 102.6 Mboe/d (74% oil), up 10% q/q and 67% year over year Realized cash margins of over 83% in Q1 2018; highest in Company history (1) Completed over 315,000 lateral feet from 35 wells Core Permian footprint 207,000 net surface acres with ~4,200 gross horizontal locations with an average lateral length of 8,150 feet (2) 2018 Guidance Full year production of 110.0 116.0 Mboe/d; implies over 40% y/y growth at midpoint Lowering LOE to $3.75 $4.50 per boe, down 13% from prior guidance midpoint 170 190 gross horizontal completions with an average lateral length of ~9,300 feet Recently added 11 th operating rig and fifth dedicated frac spread; plan to operate between 10-12 rigs in 2018, with flexibility to accelerate as cash flow allows Industry-Leading Execution, Capital Efficiency and Cost Structure Q1 2018 annualized ROACE of 13.3%, up 52% year over year Cash costs down 10% year over year; Q1 2018 cash margins of $42.13 per boe Cash flow positive for Q1 2018, as well as for the past 13 quarters in aggregate Net debt to Q1 2018 Annualized Adjusted EBITDA of 1.2x (3) First quarterly dividend of $0.125/share payable on May 29, 2018 Notable Well Results Pecos WCA well with peak flowing IP90 of 172 boe/d per 1,000 (91% oil) First ReWard 3BS shale well with peak flowing IP90 of 110 boe/d per 1,000 (81% oil) Four-well Midland County pad with average IP30s of 134 boe/d per 1,000 (89% oil) for two WCA wells and 123 boe/d per 1,000 (88% oil) for two LS wells 5 Source: Company data and filings. Financial data as of 3/31/2018 unless otherwise noted. (1) Calculated as realized price per boe less sum of LOE, Gathering and Transportation, Production and Ad valorem taxes and cash G&A expenses per boe divided by unhedged realized price per boe. (2) Net acreage as of 3/31/2018. Location assumptions based on internal company estimates as of 12/31/2017. (3) Excludes cash from Viper. Net debt to Q1 2018 annualized Adjusted EBITDA is net debt as of 3/31/2018 divided by annualized Adjusted EBITDA for the three months ended 3/31/2018. See the disclaimers at the beginning of this presentation.

Permian Takeaway Update Over 92% of current oil production on pipe; continuing to increase 2018: Term sales agreements in place for all barrels (50% of production firm) 2019: Firm sales agreements for over 45,000 bpd (pre-gray Oak 50,000 bpd) Multiple firm transportation contracts in progress to maximize international nearterm and long-term pricing exposure Gatherer: Reliance Purchasers: Shell, EPD, OXY Gatherers: FANG, PAA, EPD, Reliance Purchasers: Shell, OXY, EPD Gatherer: NuStar Purchaser: Koch (30k firm through 6/19) Gatherers: FANG, Oryx Purchasers: Various Late 2019: 50k Firm Gray Oak Pipeline Brent pricing Through 9/18: 8k Firm Magellan FANG s goal is to maximize global pricing exposure through multiple long-term firm transportation agreements in progress, the first of which was executed via commitment to the Gray Oak pipeline 6 Source: Company filings, management data and estimates.

Acquisition Track Record and Subsequent Per Share Value Creation Normalized Growth Pecos $2.55 billion Value Creation to Shareholders (1) FANG Acquisitions and EBITDA/Share Growth Since IPO (2) Reeves / Ward $560 million NW Howard $404 million EBITDA/share Glasscock / Midland $524 million 84% EPS 160% 204% 94% 72% WTI Crude 58% 21% 300% 169% 40% 9% -35% Acquisitions ($mm) $6,000 $5,000 $4,000 $3,000 $2,000 2012 Q1 2013 Q2 2013 Q3 2013 2013 Q1 2014 Q2 2014 Q3 2014 2014 Q1 2015 Q2 2015 Q3 2015 2015 Q1 2016 Q2 2016 Q3 2016 2016 Q1 2017 Q2 2017 Q3 2017 2017 Q1 2018 Acquisitions Adjusted EBITDA/Share Crude Oil 900% 800% 700% 600% 500% 400% 300% EBITDA/Share / WTI $/Bbl Growth SW Martin $188 million 107% 209% -36% $1,000 200% 100% NW Martin / Viper $605 million 224% 369% -41% IPO 2012 Q2 2013 2013 Q2 2014 2014 Q2 2015 2015 Q2 2016 2016 Q2 2017 2017 0% FANG has grown EBITDA/share over 700% since IPO with oil prices down 28% over same period 7 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. (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 2012.

Corporate Level Full-Cycle Economics and Returns Matter 15.0% 12.0% Return on Average Capital Employed ( ROACE ) Over Time (1) ROACE 9.0% 6.0% 3.0% 0.0% Realized Price ($/Boe) Adjusted EPS 10.8% 12.3% 13.3% 8.6% 7.9% 8.6% 8.8% 9.7% 9.4% 5.7% 2.6% FY 2014 FY 2015 Q1 2016 Q2 2016 Q3 2016 2016 Q1 2017 Q2 2017 Q3 2017 2017 Q1 2018 $69.74 $36.98 $25.09 $33.55 $34.39 $38.72 $41.93 $38.18 $38.25 $45.31 $50.55 $2.24 $1.81 $0.02 $0.26 $0.54 $0.90 $1.04 $1.25 $1.33 $1.56 $1.64 LTM Boe/d Added per $MM CAPEX and Cash Flow Outspend Versus Peers (2) Boe/d Capex/CFO Boe/d Added per $MM Capex 45 40 35 30 25 20 15 10 5-38 34 25 25 21 Cash Flow Outspend 16 16 15 Free Cash Flow FANG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 180% 160% 140% 120% 100% 80% 60% LTM Capex / Operating Cash Flow 8 Source: Company data, Bloomberg and latest peer filings as of 5/8/2018. Peers include RSPP, CXO, PE, EGN, CPE, PXD, LPI. (1) Return on Average Capital Employed ( ROACE ) calculated as consolidated annualized EBIT divided by average total assets 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. (2) Capex includes D,C&E as well as infrastructure and midstream, but excludes acquisitions.

Cost Structure Facilitates Capital Compounding If Diamondback and its peers grow oil production at the same rate, Diamondback s cost structure facilitates greater per share EBITDA and earnings growth 2016 / 2017 Recycle Ratio Versus Peers (1) 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.0x 2.8x 2016 Recycle Ratio 2017 Recycle Ratio 2-year average 2.0x 1.9x 1.8x 1.8x 1.6x 1.5x 1.3x Value Creation FANG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Normalized EBITDA/share Growth Versus Peers 350% 300% 250% 200% 150% 100% 50% Q2 2016 Q3 2016 2016 Q1 2017 Q2 2017 Q3 2017 2017 Q1 2018 FANG: +230% Peer 3: +191% Peer 1: +122% Peer 2: +111% Peer 5: +77% Peer 6: +48% Peers 4 & 7: +21% 9 Source: Company data, Seaport Global Securities and latest peer filings as of 5/8/2018. Peers include RSPP, PE, EGN, CXO, PXD, CPE, LPI. (1) Seaport Global Securities calculates Recycle ratio by dividing Operating Margin per Boe by adjusted PDP F&D costs per Boe.

Capital Discipline Creates Long-Term Value Growth within cash flow aligns Company strategy with shareholder interests; no growth for growth s sake Dividend initiated to begin return of capital, rewarding shareholders for support of company s growth 2018 Illustrative Sources and Uses of Cash Upside to growth with higher oil prices Incremental cash flow Scheduled capex program and dividend to be funded within cash flow at current commodity prices Reinvest to grow within cash flow Cash flow at current prices 37% - 46% y/y production growth >46% y/y production growth Sustain production and dividend at <$40/Bbl Cash on Hand Cash flow at $40/bbl ~$600MM / Yr ~$50MM / Yr ~35% y/y production growth Sources of Cash Maintenance Capex (Flat Y/Y Production) Base Dividend Current Rig Count (11) Anticipated Rig Count (10-12) Acceleration (>12 rigs) First Priority Disciplined Reinvestment as Cash Flow Allows 10 Source: Company filings, management data and estimates.

Multi-Year 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 for multiple years at today s commodity prices $400 D,C&E CAPEX Adjusted EBITDA Infrastructure CAPEX Total Production (Boe/d) Oil Production (Bo/d) 120,000 $300 $258 $307 $302 $318 $341 100,000 80,000 WTI Oil ($/Bbl) $MM $200 $100 $151 $109 $91 $110 $84 $110 $93 $121 $86 $58 $63 $78 $94 $102 $121 $138 $116 $175 $180 $218 $232 60,000 40,000 20,000 Boe/d $0 0 Since Q1 2017, FANG has generated $90 million in excess Adjusted EBITDA above CAPEX, while growing production 67% 11 Source: Company filings, management data and estimates.

Balanced, Capital Efficient Development Drilling an average of ~500 lateral feet per day per rig in the Midland Basin including move time; ~400 feet per day in Delaware Basin Completing an average of ~1,500 lateral feet per day per completion crew in Midland Basin; 800-1,000 feet per day in Delaware Basin Maximizing average lateral length completed improves capital efficiency 12,000 Completed Lateral Footage Average Lateral Length per Well 383,458 400,000 10,000 315,004 350,000 Average Lateral Length 8,000 6,000 4,000 2,000 113,220 94,523 143,400 99,806 61,672 90,970 169,302 206,356 220,194 270,060 230,472 300,000 250,000 200,000 150,000 100,000 50,000 Completed Lateral Footage 0 Drilled / Completed wells Q1 2015 15 / 18 Q2 2015 Q3 2015 2015 Q1 2016 Q2 2016 Q3 2016 11 / 13 21 / 20 17 / 14 16 / 8 15 / 11 17 / 21 25 / 23 28 / 26 34 / 35 42 / 24 46 / 38 41 / 35 FANG continues to maximize long-lateral efficient pad development across its acreage 2016 Q1 2017 Q2 2017 Q3 2017 2017 Q1 2018 0 12 Source: Company filings, management data and estimates.

Highest Realized Cash Margin in Company History Q1 2018 Cash Margins Versus Extended Peer Group ($/Boe) (1) Cash Margin (% of Realized $/Boe) 90% 80% 70% 60% 50% 40% 83% 81% 79% 79% 78% $42.13 % of Realized Price ($/Boe) Cash Margin ($/Boe) 76% 75% 75% 73% 73% 71% 71% 70% 69% 66% 63% 62% 61% 59% 56% 53% $50 $40 $30 $20 $10 $0 $/Boe Q1 2018 Cash Operating Costs Versus Extended Peer Group ($/Boe) (2) $/Boe $16 $12 $8 $8.42 $8.62 $8.87 $9.16 $9.83 $9.87 $10.17 LOE Prod. taxes Cash G&A G&T $11.17 $11.22 $11.73 $12.04 $12.58 $12.60 $12.90 $13.18 $13.24 $13.37 $13.51 $14.26 $14.95 $15.96 $4 $0 13 Source: Company and latest peer filings as of 5/8/2018. Extended peers include JAG, RSPP, PE, CPE, EGN, LPI, CDEV, EOG, CXO, PXD, PDCE, MTDR, XEC, WPX, NBL, SM, REN, ECA, QEP and AREX. (1) Cash margins calculated as realized price per boe less LOE, gathering and transportation, production taxes and cash G&A expenses per boe. Peer group data as of most recent quarterly filing. (2) Cash operating costs calculated as the sum of LOE, gathering and transportation, production taxes and cash G&A expenses per boe. Peer group data as of most recent quarterly filing.

Conservatively Spaced, Balanced Inventory Across Zones Gross Delaware Basin Locations By Zone / Lateral 5,000'+ 7,500'+ 10,000'+ Total Avg. Lateral 2BS 146 95 114 355 7,346' 3BS 139 109 125 373 7,475' WCA 261 213 232 706 7,448' WCB 197 162 208 567 7,607' Other -- -- -- -- -- Total 743 579 679 2,001 7,480' Gross Midland Basin Locations By Zone / Lateral 5,000'+ 7,500'+ 10,000'+ Total Avg. Lateral MS 42 141 234 417 8,957' LS 59 161 255 475 8,776' WCA 30 154 233 417 8,946' WCB 21 159 223 403 9,056' Other 111 203 205 519 8,169' Total 263 818 1,150 2,231 8,751' Delaware Basin Premium Zone Spacing Assumptions Midland Basin Premium Zone Spacing Assumptions 2nd Bone Spring 3rd Bone Spring Upper Wolfcamp A Lower Wolfcamp A Wolfcamp B FANG Peer 1 Peer 2 Peer 3 Middle Spraberry Lower Spraberry Wolfcamp A Wolfcamp B FANG Peer 1 Peer 2 Peer 3 TOTAL wells/section TOTAL 20 24 22 29 wells/section 28 34 38 28 Over 3,800 gross locations economic at $60/Bbl (1) 14 Source: Company data, filings and estimates. Peers include CDEV, EGN, JAG, PE and RSPP. (1) Location assumptions based on internal company estimates. Economic locations reflect expected IRR s above 10% assuming $60/Bbl NYMEX oil prices and $3.00/Mcf NYMEX natural gas prices.

Southern Delaware Basin Execution and 2018 Plans 2018 Development Plan: Delaware Basin Well Performance WELL COUNTY TARGET LATERAL DAYS IP (Boe/d / 1k ) LETHCO 39-37 UNIT 2WA Pecos L WCA 7,527 60 141 (84% oil) ROGERS 6 UNIT 3TB Reeves 3BS shale 9,401 90 110 (81% oil) AYERS 24-2 3WB Reeves WCB 8,801 90 123 (80% oil) STATE BIGGS 12A-2 2WA Pecos L WCA 6,505 90 172 (91% oil) Currently running five rigs with two dedicated completion crews; expect to average five rigs and 2+ completion crews in 2018 2018 activity focused on long-lateral Wolfcamp A wells in both ReWard and Pecos Drilling: Continue to decrease drilling times Utilizing 2 pre-set rigs, deep setting intermediate casing to decrease cost and days on location Completion Design: Focused on HDNW design: 2,000 2,500 Lbs. / Ft. of proppant and tighter stage spacing Continued optimization of completion design, fluid, diverting agents, cluster spacing, etc. Lift / Production Optimization: ESPs now primary form of lift in Delaware Southern Delaware Basin Acreage High-Grading Additional tests of Second Bone Spring in Pecos County as well as Wolfcamp B in ReWard Predominantly multi-well pad development Ongoing infrastructure investment poised to improve netbacks: oil/gas gathering systems and upgrades, SWD and freshwater systems, electrical infrastructure Net Acres 110,000 100,000 90,000 80,000 Net Acres Trades / Bolt-ons Working Interest 82% 72% As Announced 3/31/2018 90% 80% 70% 60% 50% 40% Working Interest (%) 15 Source: Company filings, data and estimates.

Delaware Basin Infrastructure Investment: ReWard Oil: gathering system completed in Q1 2018, improves realizations by ~$2.00 / barrel Selling to Oryx at Reeves Crude station (30,000 barrel tank), capacity for full field development SWD Capacity: 57,000 bpd across three wells, moving to 82,000 bpd by YE 2018 Gas: gathering system complete, owned and operated by EagleClaw Fresh Water: line connects all existing frac pits to flow barrels through field Electricity: Full field 30mW substation in service 2018 (~$60k / well monthly savings for each ESP) Substation: 2018 Super ROW: 150 foot wide field-length right of way for oil, gas, freshwater, SWD gathering and electric lines Gas Line: To EagleClaw Crude: FANG Owned Reeves Crude station; 30,000 barrel tank, to Oryx firm to Crane / Midland Super ROW Battery Frac Pit SWD Future SWD Significant infrastructure investments to begin improving realizations and lowering LOE in 2018 16 Source: Company filings, management data and estimates.

Delaware Basin Infrastructure Investment: Pecos County Oil: gathering system in service Q2 2018, improves realizations by ~$2.00 / barrel Coyanosa Crude station (30,000 barrel tank); upgrades and extensions continuing SWD Capacity: ~225,000 bpd across 9 wells, ~325,000 bpd by YE 2018 across 13 wells; ability to flow barrels throughout leasehold Gas: low pressure gathering and compression owned by Diamondback; to Brazos downstream Fresh Water: lines connect most existing frac pits and continues to be expanded as activity increases Electricity: 120mW substation in service Q3 2018 (~$60k / well monthly savings for each ESP) Coyanosa Crude Station: In Service, 30k barrel tank, to Oryx firm to Crane / Midland Super ROW Battery Frac Pit SWD Future SWD Substation: July 2018 Four Corners Compressor Station: to Brazos Super ROW: 150 foot wide field-length right of way for oil, gas, freshwater, SWD gathering and electric lines Utah Compressor Station: To Brazos Significant infrastructure investments to begin improving realizations and lowering LOE in 2018 17 Source: Company filings, management data and estimates.

Southern Delaware Basin Wolfcamp A Update Southern Delaware WCA Performance Normalized to 7,500 (Mbo) CUM OIL PRODUCTION, MBBL 200 175 150 125 100 75 50 25 0 WELL COUNTY TARGET 1,100 MBOE (975 MBO) STATE NEAL LETHCO 36-32 1WA STATE NEAL LETHCO 36-32 2WA OATES 10N 2-1H NEAL LETHCO STATE 20-1H COLDBLOOD 7372 1WA (UPR WCA) WALER STATE UNIT 4 1WA STATE ARDENNES UNIT 1101WA WARLANDER WEST 501WA STATE BIGGS 12A-2 2WA NEAL LETHCO 39-37 UNIT 2WA AYERS 24 2WA 0 50 100 150 200 250 300 DAYS IP30 (Boe/d / 1k ) % Oil NEAL LETHCO 39-37 UNIT 2WA Pecos L WCA 159 84% STATE BIGGS 12A-2 2WA Pecos L WCA 226 91% AYERS 24 2WA Reeves WCA 226 82% WARLANDER 501 WA Reeves WCA 186 80% STATE ARDENNES 1101 WA Ward WCA 154 81% NEAL LETHCO 36-3201/02WA Pecos U/L WCA 130 88% STATE MCGARY 16-1H Pecos U WCA 219 85% WALER STATE UNIT 4 1WA Reeves WCA 205 80% COLDBLOOD 7372 UNIT 1WA Ward WCA 176 87% Central Type Log and Landing Targets Oil-In-Place WC A & B OOIP 53 MMbbls/sec. WOLFCAMP U WC A U WC B L WC A High-graded landing zones through integration of captured core and log data; high-res 3-D seismic shoot expected throughout 2018 Well results confirming geologic assessment of rock quality FANG Primary Targets 18 Source: Company filings, management data and estimates.

Midland Basin: Continued Best-in-Class Execution 2018 Development Plan: Currently running six rigs; expect to average between six and seven operated rigs in 2018 Operating Plan focused on most efficient development of reservoir: Spanish Trail: recently completed 2nd eight-well pad co-developing three zones (LS, WCA, WCB) Midland County: four-well stacked pads (MS, LS, WCA, WCB) with less than 180 days between pads Howard County: co-developing LS / WCA with minimum four-well pads Glasscock County: recently completed seven-well pad targeting WCA / WCB Local Sand Update: First pad completed in Q1 2018 Currently running 2 spreads with local sand All Midland Basin wells expected to use by Q3 2018 ~$60/ft savings vs Q1 2018 completion costs Continue to actively block up acreage in core areas via trades and bolt-on acquisitions Howard County WCA Performance Normalized to 7,500 (Mbo) CUMULATIVE OIL, MBO 250 200 150 100 50 0 0 50 100 150 DAYS 200 250 300 350 Midland County WCA Performance Normalized to 7,500 (Mbo) CUMULATIVE OIL, MBO 150 100 50 0 1st BOMBARDIER PAD - 1600 LBS/FT 2nd BOMBARDIER PAD - 2000 LBS/FT 3rd BOMBARDIER PAD - 2000 LBS/FT 670 MBO TYPE CURVE 750 MBO - RYDER SCOTT TC 900 MBO TC 1000 MBO TC ASRO 13-1WA BULLFROG 47 NORTH 1WA BULLFROG 47 SOUTH 4WA METCALF 21 1WA PHILLIPS-HODNETT 1WA REED 1A 1WA W H 48 1WA W H 48 2WA 0 40 80 DAYS 120 160 200 19 Source: Company filings, management data and estimates.

Current Hedge Summary Crude Oil (Bbls/day, $/Bbl) Q2 2018 Q3 2018 2018 Q1 2019 Q2 2019 Q3 2019 2019 (1) Swaps - WTI Swaps - Brent 29,000 27,000 26,000 7,000 4,000 4,000 3,000 $51.24 $51.27 $51.27 $55.29 $51.86 $51.59 $49.82 6,000 6,000 6,000 $55.07 $54.99 $54.92 Basis Swaps Three-Way Collars - WTI 15,000 15,000 15,000 ($0.88) ($0.88) ($0.88) 10,000 10,000 Floor $55.00 $55.00 Ceiling $70.76 $69.71 Three-Way Collars - Brent 4,000 4,000 Floor $65.00 $65.00 Ceiling $77.85 $77.85 Natural Gas (Mmbtu/day, $/Mmbtu) Q2 2018 Q3 2018 2018 Q1 2019 Q2 2019 Q3 2019 2019 Swaps 20,000 20,000 20,000 $3.00 $3.02 $3.07 20 Source: Company data as of 5/8/2018. (1) Sub-floors for both WTI and Brent three-way collars are priced $10/Bbl below the respective floor price for each period.

Liquidity Strength Creates Capital Flexibility Net Debt to Q1 2018 Annualized Adjusted EBITDA of 1.2x (1) ; continue to target leverage below 2.0x Lead bank recently recommended increasing FANG s borrowing base to $2.0 billion from $1.8 billion: FANG electing to keep elected commitment unchanged at $1.0 billion Lead bank on Viper s credit facility recommended increasing borrowing base to $475 million from $400 million previously FANG standalone liquidity of $888 million as of March 31, 2018 FANG s Liquidity and Capitalization FANG's Consolidated Capitalization 3/31/2018 ($MM) Cash and cash equivalents $72 FANG's Revolving Credit Facility 166 VNOM's Revolving Credit Facility 241 4.750% Senior Notes Due 2024 500 5.375% Senior Notes Due 2025 800 Total Debt $1,707 FANG's Standalone Liquidity 3/31/2018 Cash (1) $54 Elected commitment amount 1,000 FANG borrowing base 1,800 Liquidity $888 $1,000 $800 $600 $400 $200 $0 FANG s Debt Maturity Profile ($MM) FANG Credit Facility Undrawn 4.750% Senior Notes 5.375% Senior Notes 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 21 Source: Company Filings, Management Data and Estimates. (1) Excludes cash from Viper.

Updated 2018 Guidance Targeting annual production growth of over 40% in 2018 Lowering LOE guidance to $3.75 - $4.50 per boe, down 13% from prior guidance midpoint 2018 D,C&E CAPEX budget of $1,175 $1,325 million from a 10 to 12 rig program Diamondback Energy, Inc. Viper Energy Partners LP Net Production Mboe/d 110.0 116.0 15.5 16.5 Oil Production (% of Net Production) Unit Costs ($/boe) 73% - 76% 71% 75% Lease Operating Expenses $3.75 $4.50 n/a Gathering & Transportation $0.25 $0.50 $0.10 $0.30 Anticipated infrastructure capital expenditures of $125 - $175 million Expect to complete 170 190 gross horizontal wells with an average lateral length of ~9,300 feet Targeting annual production growth of over 45% for Viper Energy Partners in 2018 2018 capital budget will target estimated operating cash flow and drilling rigs will be added or dropped accordingly Cash G&A Under $1.00 $0.75 $1.25 Non-Cash Equity Based Compensation $0.75 $1.25 $0.75 $1.25 DD&A $11.00 $14.00 $9.00 $11.00 Interest Expense (net) $1.00 $2.00 Production and Ad Valorem Taxes (% of Revenue) (1) 7.0% 7.0% Corporate Tax Rate 20% - 23% n/a Diamondback 2018 Capital Activity Gross (Net) Horizontal Wells Completed 170 190 (146 163) Midland Basin D,C&E per Foot $760 $810 Delaware Basin D,C&E per Foot $1,125 $1,225 Diamondback Capex Budget ($MM) 2018 Capital Budget $1,300 $1,500 22 Source: Company filings, management data and estimates. Note: Based on updated 2018 guidance provided on 5/8/2018, 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.

Viper Update Q1 2018 cash distribution of $0.480 per unit, up 59% over Q1 2017 and the highest in Viper s history Proposed tax status election to a taxable entity expected to be effective on or after May 10, 2018 Focused on mineral acquisitions in oil-weighted basins with high visibility towards active development Robust A&D activity: 21 deals closed in Q1 2018, adding 967 net royalty acres for a total 10,537 net royalty acres (33% FANG-operated) Distributions Have Eclipsed Prior Highs Production Growth of 514% Since IPO $0.500 $120 $900 15,000 $0.450 $0.480 $0.400 $100 $750 $158 12,000 Quarterly Distribution $0.350 $0.300 $0.250 $0.200 $0.150 $0.100 $0.050 $0.000 $0.250 Q3 '14 $0.250 '14 $0.190 Q1 '15 $0.220 Q2 '15 $0.200 Q3 '15 $0.230 '15 $0.149 Q1 '16 $0.189 Q2 '16 $0.207 Q3 '16 $0.258 '16 $0.302 Q1 '17 $0.332 Q2 '17 $0.337 Q3 '17 $0.460 '17 Q1 '18 $80 $60 $40 $20 $0 WTI Oil Price ($/Bbl) Acquisitions ($mm) $600 $450 $300 $150 $92 Q3 '14 '14 Q1 '15 Q2 '15 $32 $12 $2 $9 Q3 '15 '15 Q1 '16 Q2 '16 $68 $8 $126 Q3 '16 '16 Q1 '17 $178 $117 Q2 '17 Q3 '17 $39 '17 Q1 '18 9,000 6,000 3,000 0 Net Production (Boe/d) 23 Source: Company data and filings.

Return On and Return Of Capital Significant Resource Potential Conservative Financial Management Strategic Acquisitions Efficient Conversion of Resource to Cash Flow 24

25 APPENDIX

Limelight Prospect Emerging Mississippian Oil Potential Diamondback Limelight Acreage Map Limelight Type Log Atoka-Bend Limelight Springer Seal Early geologic assessments indicate the target to be a significant oil source and producing interval. ~19,000 acres acquired at low entry cost Mississippian Barnett (Springer-Chester equiv) and Meramec are prospective on terrace structures along the Central Basin Platform and Midland Basin boundary, at depths where maturation is within peak oil window Analogous to recent successful Mississippian horizontal activity in Andrews County Plan to begin initial appraisal of acreage in 2018 Barnett Meramec Miss Lime Woodford Devonian Chert-Lime Limelight Zone of Interest Stratigraphic and geochemical characteristics are comparable to Andrews County Barnett/Meramec 26 Source: Company filings, management data and estimates.

High Growth, Oil Weighted Reserves 2017 total proved reserves increased 63% y/y to 335.4 MMboe FANG standalone reserves increased 71% y/y to 297.1 MMboe 62% proved developed; conservatively booked Proved developed F&D for 2017 was $9.09/Boe 63.6 10.3 53.3 Total Reserves Growth (MMboe) (1) FANG Standalone VNOM 335.4 38.2 205.5 156.9 31.4 112.8 26.3 297.1 18.5 174.0 130.6 94.3 2013 2014 2015 2016 2017 F&D Costs 1P Reserves By Commodity 1P Reserves By Category ($/boe) 2014 2015 2016 2017 Natural Gas 14% Drill Bit F&D (2) $11.09 $5.51 $6.31 $7.22 Reserve Replacement (3) 793% 465% 409% 549% NGL 16% Oil 70% PUD 38% PD 62% Organic Reserve Replacement (4) 626% 422% 380% 443% 335.4 MMBOE 27 Source: Company Filings, Management Data and Estimates. (1) Historical FANG reserves per independent reserve report prepared by Ryder Scott as of 12/31/2017. (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 500 West Texas Ave., Suite 1200 Midland, TX 79701 www.diamondbackenergy.com Adam Lawlis, Director, Investor Relations (432) 221-7400 ir@diamondbackenergy.com 28