Investor Presentation August 2016

1 Investor Presentation August 2016

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 Energy, Inc. (the Company or ) 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 drilling program, 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, risks relating to the acquisition described in this presentation, 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 estimated full-year 2016 production, capital expenditures, expenses and other matters. 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 2016. 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 finance our 2016 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, 2015 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 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 Adjusted EBITDA as net income (loss) plus non-cash loss on derivative instruments, net, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense and income tax (benefit) provision. Adjusted EBITDA is not a measure of net income (loss) as determined by United States generally accepted accounting principles, or GAAP. Management believes 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 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. 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 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 Adjusted EBITDA. Our computations of 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 Adjusted EBITDA to net income (loss), please refer to filings we make with the SEC. 2

Energy Overview Quality Acreage in Northern Midland Basin ~86,000 net acres containing 2,700+ gross locations ~1,500 gross locations economic at $40/bbl WTI (1) ~2,200 gross locations economic at $50/bbl WTI (1) Strategic Entry into Southern Delaware Basin ~19,180 net acres with 611 gross identified locations Contiguous footprint with lateral lengths of ~9,500 Upside from additional zones and downspacing Best in Class Execution Peer-leading spud to TD times and cash margins (2) Lean organization with low G&A Conservative Financial Management Continued commitment to best in class leverage $719 million of liquidity (3) Highest recycle ratio among peers (4) 84% Ownership of Viper Energy Partners Acquired or entered into agreements to acquire 2,185 net royalty acres for $269 million since IPO in June 2014 Recent Acquisition Acreage Energy Acreage Map Spanish Trail 3 Source: Company data, filings and estimates. Financial data as of June 30, 2016. (1) Assumes $5.4 mm for a 7,500 ft lateral at WTI of $40 per bbl and $5.6 mm for a 7,500 ft lateral at WTI of $50 per bbl, in each case with 10% rate of return; EUR assumptions are based on either Ryder Scott or internal company estimates. (2) Calculated as unhedged EBITDA divided by total production. (3) As of June 30, 2016. FANG s borrowing base set at $700 million in Spring 2016 redetermination, but elected to maintain its commitment amount of $500 million. (4) Peers include CPE, CXO, EGN, LPI, PE, PXD and RSPP. Recycle ratio is calculated by dividing 2015 Adjusted EBITDA per BOE by 3-year average 1 year F&D costs per BOE for the years 2013, 2014 and 2015.

Recent Highlights Q2 2016 Review Q2 2016 production of 36.8 Mboe/d, 23% y/y growth from 30.0 Mboe/d in Q2 2015 s five Glasscock County wells tracking 1 MMboe type curve on average Completed first three-well pad in Howard County with a second awaiting completion Accretive Delaware Basin Acquisition Recently announced strategic acquisition of over 19,000 net acres in Core Oil Window of the Southern Delaware Basin for $560 million Stacked pay development potential with 3 zones currently de-risked and 2-3 upside zones Rapidly improving well performance and well cost reductions in the Delaware Basin Well-Positioned for Acceleration Peer-Leading Capital Discipline and Cost Optimization Inventory of over 20 drilled but uncompleted wells Added a fourth drilling rig in July, with potential for a fifth rig in 2016 $219 million in cash and an undrawn revolver of $500 million enable acceleration without stressing balance sheet Leading edge D,C & E costs below $6.0 million for a 10,000 ft lateral and below $5.0 million for a 7,500 ft lateral Net debt to Q2 2016 Trailing Twelve Months Adjusted EBITDA of 0.8x (1)(2) Liquidity of $719 million with undrawn revolver (1) Updated 2016 Guidance Increased 2016 guidance as a result of increased completion activity 2016 production guidance of 38.0 40.0 Mboe/d from 34.0 38.0 Mboe/d 60 75 gross horizontal completions Expected LOE range of $5.50 $6.25/boe, down from $5.50 $6.50/boe 4 Source: Company data and filings. Financial data as of June 30, 2016. (1) As of June 30, 2016. FANG s borrowing base set at $700 million in Spring 2016 redetermination, but elected to maintain its commitment amount of $500 million. (2) Trailing Twelve Months Adjusted EBITDA is consolidated Adjusted EBITDA for the twelve months ended 6/30/16, which has been derived by adding the consolidated Adjusted EBITDA for the twelve months ended 12/31/15 to the consolidated Adjusted EBITDA for the six months ended 6/30/16 and subtracting the consolidated Adjusted EBITDA for the six months ended 6/30/15. Actual consolidated Adjusted EBITDA for 2016 will depend on many factors and may differ from Trailing Twelve Months Adjusted EBITDA. See the disclaimers at the beginning of this presentation.

Strategic Entry into the Core of the Southern Delaware Basin Recently signed agreement to acquire 19,180 net acres primarily in Reeves and Ward Counties along the Pecos River for $560 million Acquisition Acreage Map Production of 1,000 Boe/d (1) from 30 gross wells (11 Hz and 19 Vt) and 2.2 MMboe of proved developed reserves (2) 290 net identified potential horizontal drilling locations with an anticipated average lateral length of ~9,500 feet Includes tank batteries, frac pits, salt water disposal facilities and pipelines Management believes acreage is in top quartile of FANG s existing acreage portfolio based on well results in immediate proximity The Company believes 3 horizontal zones de-risked 3 rd Bone Spring, Wolfcamp B and Wolfcamp A. Upside potential exists in additional Bone Spring and Wolfcamp intervals Acreage Net Potential Locations 3 County Net Wolfcamp A Wolfcamp B 3rd Bone Spring 2nd Bone Spring Total Reeves / Ward Co Line 13,048 65 61 43 43 212 Central Reeves 2,915 12 11 8 8 38 Central Ward 3,217 12 12 8 8 39 Total 19,180 88 84 59 59 290 5 Source: Company data and management estimates. (1) Represents production from properties subject to acquisition announced in July 2016. Acquisition production is as of July 2016 and based on data provided by sellers not verified by the Company. Actual production from acquired wells may vary materially. (2) Acquisition reserve estimates are based solely on management s internal evaluation and interpretation of reserve information and of other information provided to management in the course of due diligence review of the acquired properties. Such estimates have not been reviewed by the Company s independent reserve engineers and are subject to numerous assumptions and risks, including those discussed above. (3) Based on management internal estimates.

Attractive Southern Delaware Basin Acquisition Strategic rationale for acquisition The Company believes acreage contains significantly more oil in place than in the Northern Midland Basin Stacked pay development potential with 3 zones currently derisked and 2-3 additional upside zones Rapidly improving well performance and well cost reductions in the Delaware Basin Permian Basin Net Acreage 105,002 19,180 85,822 85,822 Contiguous acreage set up for long lateral horizontal development and efficient infrastructure buildout Attractive entry price relative to recent Northern Midland Basin transactions Accretive to stockholders Expected to be accretive on net asset value and acreage valuation metrics Attractive acquisition price of ~$26,700 per adjusted net acre (1) Significant value from exposure to mostly undeveloped horizontal acres in core of Southern Delaware Basin Entry point to attractive Southern Delaware Basin core Standalone Midland Delaware PF Total Net Horizontal Locations 2,142 290 1,852 1,852 Transaction provides a strategic foothold in prolific Delaware core for additional potential bolt-ons One dedicated horizontal rig expected to be added in 2017 Standalone Midland Delaware PF 6 Source: Company data, filings and estimates. (1) Purchase price adjusted for production valued at $35,000 per Boe/d and $12.5 million for facilities and infrastructure, which reflects mid-point of range.

Delaware Basin Acquisition: Outstanding Offset Well Results Jim Ed 2H Centennial IP30: 2,134 Boepd (84% oil) Autobahn 34-117 4H Cimarex IP30: 1,180 Boepd (86% oil) Pitzer 8 2H Cimarex IP30: 1,182 Boepd (82% oil) Pitzer-Lasater State 1H Cimarex IP30: 2,011 Boepd (86% oil) Lasater 3 Chevron IP30: 2,008 Boepd (84% oil) Barstow 33-35 2H Concho IP30: 1,160 Boepd (76% oil) Trinity 15-33 1H Unit Jagged Peak IP30: 1,070 Boepd (83% oil) Graham 33-35 1H Concho IP30: 1,117 Boepd (72% oil) Whiskey River 0927-7 1H Jagged Peak IP30: 982 Boepd (86% oil) Graham Unit 33-34 1H Concho IP30: 1,100 Boepd (69% oil) Coopersmith 34-139 2HR Anadarko IP30: 1,678 Boepd (80% oil) s Cilantro 2524-C3 1H Jagged Peak IP30: 1,159 Boepd (86% oil) Walking O C3-28 4H Parsley IP30: 934 Boepd (89% oil) Rogers 6 Unit 2H Luxe IP30: 995 Boepd (84% oil) Arco State 33-28 2H Concho IP30: 781 Boepd (82% oil) Evergreen Unit 12 P 1H Apache IP30: 1,267 Boepd (85% oil) Caribou 10 2H Patriot IP30: 1,344 Boepd (78% oil) Eland State 14 11H Occidental IP30: 764 Boepd (85% oil) Acquisition acreage 3 rd Bone Spring Wolfcamp A Wolfcamp B Three Zones De-risked with Upside From Additional Intervals 7 Source: IHS. Note: All 30-day rates are two-stream. IPs are FANG s interpretation of data normalized for a 7,500 foot lateral. Zone designation is based on s interpretation of available geologic data, which may be different than other operators interpretation. Individual offset well results not intended to be representative of prospective well results in acquisition acreage.

Geology Comparison to Top Value Midland Basin Assets N. Midland Basin (Spanish Trail) Delaware Acquisition Acreage Upside Development 120 MMBO/SEC EASTERN SHELF Upside Development 200 MMBO/SEC Core Development 100 MMBO/SEC NMB Total Potential OIP 220 MMBO/SEC Midland Basin Core Development (Wolfcamp A&B, Lower Spraberry Shale) Delaware Total Potential OIP 310 MMBO/SEC Core Development 110 MMBO/SEC Delaware Basin Core Development (Wolfcamp A&B, 3 rd Bone Spring) Core development zones in Delaware Basin compare or beat core development zones in Northern Midland Basin (NMB) Acquisition cost much lower in Delaware for same to better quality rock (offsets higher current D&C cost) Higher pressure coupled with better porosity and permeability translate to higher ultimate recoveries from fewer wells 880 spacing in Delaware compared to 660 in NMB Greater Thickness in the Delaware Basin; Contains More Oil in Place 8 Source: Company filings, management data and estimates.

Core Southern Delaware Basin Trend Area High Productivity and Oil Content Wolfcamp and Bone Spring Heat Map (1) Cumulative Percent Oil Map (2) Delaware Heat data 3 Month Boe/d 1000 200+ 200 150 100 <50 Acquisition acreage Oil Percentage 0% 50% 100% Acquisition acreage Gas Weighted Area Oil Weighted Area 9 Source: IHS Performance Evaluator, investor presentations. (1) Horizontal wells with a first production date between 1/1/2012-12/31/2015 with at least three months of production. Data shown using an 20:1 gas to oil conversion ratio. Includes wells reported as producing from Wolfcamp and Bone Spring horizons. (2) Horizontal wells with a first production date between 1/1/2012 9/30/2015. Data shown using an 6:1 gas to oil conversion ratio. Includes wells reported as producing from Wolfcamp, Spraberry and Bone Spring horizons.

5,200 Delaware Basin Stacked Pay Provides Extensive Development Potential Delaware Basin Peers Acquisition Reeves County Ward County Northern Delaware (1) 1st Bone Spring 2nd Bone Spring (59 net locations) 3rd Bone Spring (59 net locations) Upper Wolfcamp A Lower Wolfcamp A Wolfcamp B (88 net locations) (84 net locations) Wolfcamp C Wolfcamp D Developing Delineating Upside Target Indicates Most Active Zone Operator activity rapidly improving well performance and reducing costs 10 Source: Latest investor presentations, Wall Street research and Texas Railroad Commission. (1) Northern Delaware encompasses Eddy, Lea, Loving, Culberson and Northern Reeves counties.

Viper Overview Pro forma 5,357 net royalty acres (1) in core of Permian Basin Viper Execution Post June 2014 IPO: Asset Overview ~70% growth in net royalty acreage ~200% growth in gross hz. locations ~185% growth in production $0.189 / unit 2Q16 distribution Variable MLP structure with no maintenance capex, direct operating expense, IDRs, subordinated units, hedges or MQDs Unique production growth and yield vehicle volumes increased 185% since IPO in June 2014, including 135% organic growth Rig Location Recent Acquisition Acreage VNOM Acreage FANG Acreage ~5 Rigs Currently Operating on Viper s Acreage 11 Source: Company data and filings. (1) Data as of June 30, 2016, pro forma for Viper s recently completed and pending acquisitions.

Viper s Attractive Mineral Interest Acquisitions Recently signed agreements to acquire mineral interests underlying 8,137 gross acres in Midland and Delaware Basins for total price of ~$111 million Accretive on net asset value, yield and acreage valuation metrics Midland Basin Mineral Interest Acquisition Delaware Basin Mineral Interest Acquisition Wolfcamp B Wolfcamp A Rig location Wolfcamp Bone Springs Rig location Solid lines represent current wells Dashed lines represent upcoming wells Solid lines represent current wells Dashed lines represent upcoming wells Description 601 net royalty acres (7,487 gross) ~300 Boe/d production (1) 1.0 MMboe proved reserves (2) Primarily operated by Pioneer Prospective Zones Wolfcamp A Wolfcamp B Lower Spraberry Middle Spraberry Description 142 net royalty acres (650 gross) ~200 Boe/d production (1) 0.6 MMboe proved reserves (2) Operated by FANG & private operator Prospective Zones Wolfcamp Bone Springs Avalon Shale Brushy Canyon Development Plan Assumptions Pioneer currently operating 1 rig 8 Wolfcamp permits filed with TX RRC 8 wells to be drilled in 2017 Peak IP30 rates Wolfcamp B wells: 930 Boe/d (80% oil) Development Plan Assumptions Private operator currently operating 1 rig 6 horizontal well permits filed with TX RRC 180 day continuous development clause 2+ wells to be drilled in 2017 Peak IP30 rates Zuma 3 W201AP: 1,170 Boe/d (42% oil) Zuma 3 B201AP: 975 Boe/d (74% oil) 12 Source: Company data and filings. (1) Production relating to these acquisitions are August 2016 estimates based on data provided by sellers and have not been verified by the Company. Actual production from acquired wells may vary. (2) Reserve estimates relating to these acquisitions are based solely on management s internal evaluation and interpretation of reserve information and of other information provided to management in the course of due diligence review of the acquired properties.

Early Howard County Rates Confirm Productivity Encouraging first results in Howard County: Howard County Activity Normalized for 7,500 Lateral (1) Recently completed first three-well pad targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B Wolfcamp A and Wolfcamp B wells had average peak 30-day IP rates of 179 boe/d per 1,000 of lateral: Confirms two distinct Wolfcamp development zones Third well exhibiting similar production profile to offset Lower Spraberry wells and has not yet reached peak production Plan to begin frac operations on a second three-well pad with 10,000 foot laterals this month, with a third pad scheduled to be drilled during Q4 2016 Reed 1A 1LS Lateral Length: 10,000 Waiting On Completion Reed 1A 1WA Lateral Length: 10,000 Waiting On Completion Reed 1A 1WB Lateral Length: 10,000 Waiting On Completion Wilbanks SN 16-15 #504H Energen EUR: 1,101 MBOE Lateral Length: 7,000 Phillips-Hodnett Unit 1WA IP30: 1,387 boe/d (89% oil) Lateral Length: 7,430 On ESP Phillips-Hodnett Unit 1WB IP30: 1,295 boe/d (83% oil) Lateral Length: 7,093 On ESP Phillips-Hodnett Unit 1LS Lateral Length: 7,296 On ESP Production Increasing Adams 4231WA Occidental IP30: 1,432 boe/d (89% oil) Lateral Length: 9,639 Adams 4201WA Occidental IP30: 1,178 boe/d (90% oil) Lateral Length: 9,522 Wright 41-32 1SH Element IP30: 940 boe/d (92% oil) Lateral Length: 7,551 Smith SN 48-37 501H Energen IP30 (3-stream): 980 boe/d (79% oil) EUR: 979 MBOE Lateral Length: 6,848 Gratis 32 R 1HB Crownquest IP30: 1,012 boe/d (86% oil) Lateral Length: 9,953 Lower Spraberry Wolfcamp A Wolfcamp B 13 Source: DrillingInfo, Company Information. Note: All EURs and 30-day rates are two-stream unless otherwise noted. (1) EURs are FANG s interpretation of data normalized for a 7,500 foot lateral. IPs are FANG s interpretation of data normalized for a 7,500 foot lateral. Target formations are based on s estimates if not provided by the operator.

Glasscock County Wells Continue to Impress Average well tracking near 1,000 Mboe type curve Glasscock County Activity Normalized for 7,500 Lateral (1) Testing various landing depths and completion types to optimize productivity and recovery, maximize returns Glasscock County Results Riley B 1807WA IP30: 1,309 boe/d (85% oil) Lateral Length: 7,173 On ESP Saxon C 1101WB IP30: 1,270 boe/d (68% oil) Lateral Length: 7,651 On ESP Saxon B 1101WA IP30: 1,304 boe/d (74% oil) Lateral Length: 7,229 On ESP Saxon A 1101LS IP30: 1,124 boe/d (83% oil) Lateral Length: 7,279 On ESP Riley C 1807WB IP30: 1,025 boe/d (83% oil) Lateral Length: 7,756 On ESP Riley 1819 4WB / 5WB Completing Ray 3427 A 4WA / B 5WA Waiting On Completion Target 3904WB / 3905WB Flowing Back Calverley #1H RSP Permian IP30: 1,322 boe/d (83% oil) Lateral Length: 9,968 Calverley #2H RSP Permian IP30: 1,432 boe/d (83% oil) Lateral Length: 9,830 Shackelton 31W 3HM Apache IP30: 1,886 boe/d (83% oil) Lateral Length: 4,426 Tomahawk 2425 A5LS / B6LS Waiting On Completion 14 Source: DrillingInfo, Company Information. Note: All EURs and 30-day rates are two-stream unless otherwise noted. (1) EURs are FANG s interpretation of data normalized for a 7,500 foot lateral. IPs are FANG s interpretation of data normalized for a 7,500 foot lateral. Target formations are based on s estimates if not provided by the operator.

Robust, Multi-year Inventory in the Midland Basin WTI ($/bbl) Northern Midland Basin Scenario Analysis (1) # of Gross Locations # of Rigs Years of Drilling (at Midpoint) (2) Midland Basin Acreage Position $35 - $45 ~1,500 2 3 30 $45 - $55 ~2,200 3 4 31 $55 - $65 ~2,400 4 6 24 $65 - $75 ~2,600 6 8 19 Poised to respond to varying oil prices Peer leading leverage allows continued capital flexibility Under each scenario, balance sheet remains strong Upside exists to 300,000+ net effective horizontal acres (3) from delineation of additional intervals 15 Source: Company filings, management data and estimates. (1) Assumes midpoint of WTI range presented, 10% rate of return and EUR assumptions are based on either Ryder Scott or internal company estimates. Assumes 7,500 lateral well costs of $5.2 mm at ~$30 WTI, $5.4 mm at ~$40 WTI, $5.6 mm at ~$50 WTI, $6.0 mm at ~$60 WTI and $6.4 mm at ~$70 WTI. (2) Assumes 20 wells per rig per year at the midpoint of rig range. (3) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone.

Best in Class Execution and Cost Control Drilling Cost Reductions Since Q4 2014 (1) FANG vs. Peer Estimated Well Costs ($/lateral ft) (2) $3.2 933 $2.5 $2.1 $1.9 $1.8 $1.7 653 673 693 693 700 733 Q4 2014 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 FANG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Overall drilling costs are down 46% from peak Q4 2014 levels Drilled two 10,000 ft lateral wells in Andrews and Glasscock counties in less than nine days from spud to total depth Leading edge well costs currently below $6.0 million for a 10,000 ft lateral well and below $5.0 million for a 7,500 ft lateral well Leading-edge drill, complete and equip costs are down ~35% from 2014 peak Drilled a 10,800 ft lateral well in Spanish Trail in less than 11 days from spud to total depth Roughly 30% to 40% of drilling cost decreases since Q4 2014 are associated with optimization 16 Source: Company and peer filings, management data and estimates and KeyBanc. (1) Assumes a standard Spanish Trail Lower Spraberry well with a 7,500 lateral. (2) Analysis by KeyBanc dated May 26, 2016. KeyBanc estimated budgeted costs in 2016 per lateral foot for a 7,500 lateral well. Peers include CPE, EGN, LPI, PE, PXD and RSPP.

Best in Class Cost Optimization & Conservative Financial Metrics Operating Expenses Below Peer Average (1) ($/boe) $20.91 Cash Margins Expected Peers to Lead Peers in 2017 (1)(2) $31.72 $15.37 $15.34 $26.06 $12.22 $12.38 $11.23 $10.84 PEERS FANG PEERS FANG PEERS FANG FANG FY2014 FY2015 Q1 2016 Q2 2016 Peers FANG Net Debt to Trailing Twelve Months Adjusted EBITDA (1)(3) 2015 Recycle Ratio (1)(4) Peer Avg: 1.9x 0.8x 1.1x 1.7x 2.1x 2.4x 2.7x 3.0x Peer Avg: 252% 449% 439% 318% 244% 237% 194% 193% 140% NM Peer 1 FANG Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 FANG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 17 Source: Company and peer filings, management data and estimates and Bloomberg. (1) Peers include CPE, CXO, EGN, LPI, PE, PXD and RSPP. (2) Calculated as Consensus 2017E EBITDA divided by total Consensus 2017E production. (3) Trailing Twelve Months Adjusted EBITDA is Adjusted EBITDA for the twelve months ended 3/31/16, which has been derived by adding the Adjusted EBITDA for the twelve months ended 12/31/15 to the Adjusted EBITDA for the three months ended 3/31/16 and subtracting the Adjusted EBITDA for the three months ended 3/31/15. For FANG, Trailing Twelve Months EBITDA is based on consolidated Adjusted EBITDA for the three months ended 6/30/16. Actual consolidated Adjusted EBITDA for 2016 will depend on many factors and may differ from Trailing Twelve Months Adjusted EBITDA. See the disclaimers at the beginning of this presentation. Net debt is as of 3/31/16 pro forma for public offerings and other subsequent activities disclosed through 8/1/2016. (4) Recycle ratio is calculated by dividing 2015 Adjusted EBITDA per BOE by 3-year average 1 year F&D costs per BOE for the years 2013, 2014 and 2015.

Liquidity Strength Creates Capital Flexibility FANG s Liquidity and Capitalization FANG's Consolidated Capitalization as of 6/30/16 ($MM) Cash and cash equivalents $219 FANG's Revolving Credit Facility $0 VNOM's Revolving Credit Facility $52 7.625% Senior Notes Due 2021 $450 Total Debt $502 Net Debt $283 Net Debt to Trailing Twelve Months Adjusted EBITDA of 0.8x (2) Strong balance sheet with the ability to use its 84% ownership stake in Viper Energy Partners for non-debt, non-dilutive liquidity FANG s borrowing base set at $700 million in Spring 2016 redetermination, but elected to maintain its commitment amount of $500 million S&P recently raised issue-level rating on the Company s bonds to BB- and reaffirmed s corporate credit rating of B+ FANG's Liquidity as of 6/30/16 Cash (1) $213 Borrowing Base elected commitment $500 Less: Borrowings $0 Liquidity $713 Moody s recently reaffirmed s B1 corporate family rating with a positive outlook FANG s Debt Maturity Profile ($MM) $500 $450 $400 $350 $300 $250 $200 $150 $100 $50 $0 Undrawn FANG Credit Facility 2015 2016 2017 2018 2019 2020 2021 7.625% Senior Notes 18 Source: Company Filings, Management Data and Estimates. (1) Excludes cash from Viper. (2) Trailing Twelve Months Adjusted EBITDA is consolidated Adjusted EBITDA for the twelve months ended 6/30/16, which has been derived by adding the consolidated Adjusted EBITDA for the twelve months ended 12/31/15 to the consolidated Adjusted EBITDA for the six months ended 6/30/16 and subtracting the consolidated Adjusted EBITDA for the six months ended 6/30/15. Actual consolidated Adjusted EBITDA for 2016 will depend on many factors and may differ from Trailing Twelve Months Adjusted EBITDA. See the disclaimers at the beginning of this presentation.

Q2 2016 Operations and Guidance Update Increased full year 2016 production guidance range to 38.0 40.0 Mboe/d, up 11% from the midpoint of the February 2016 guidance range Average daily production during Q2 2016 was 36.8 Mboe/d (72% oil) Energy, Inc. Viper Energy Partners LP Net Production Mboe/d 38.0 40.0 6.0 6.5 Unit Costs ($/boe) Decreased full year 2016 LOE guidance range to $5.50 $6.25/boe Decreased full year 2016 D,D&A guidance range to $11.00 $13.00/boe Currently operating four horizontal rigs Lease Operating Expenses $5.50 $6.25 n/a Gathering & Transportation $0.50 $1.00 $0.25 $0.50 Cash G&A $1.00 $2.00 $0.50 $1.50 Capital Activity Gross Horizontal Wells Completed 60 75 Gross Horizontal Well Costs (1) $5.0 $5.5 mm Capex Budget ($ - million) Horizontal Drilling and Completion $305 $360 Infrastructure $30 $40 Non-op and Other $15 $25 2016 Capital Budget $350 $425 Non-Cash Equity Based Compensation $1.50 $2.50 $2.00 $3.00 DD&A $11.00 $13.00 $12.00 $14.00 Interest Expense (net) $2.50 $3.50 Production and Ad Valorem Taxes (% of Revenue) (2) 8.0% 8.0% 19 Source: Company filings, management data and estimates. Note: Based on 2016 updated guidance provided on 8/2/16, which guidance is subject to numerous assumptions and risks. See the disclaimer at the beginning of this presentation. (1) Assumes a 7,500 average lateral length. (2) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.

Viper s Yield and Financial Flexibility Pro forma liquidity of $126 million (1) after the closing of July equity offering and recent and pending acquisitions Pipeline of deal flow has increased significantly since Q1 2016 Focused on mineral acquisitions in oil-weighted basins with active development and competent operators Very low leverage, total debt / LTM EBITDA of 0.9x pro forma for July equity offering and recent and pending acquisitions Acquisitions and WTI Pricing Changes Viper Distribution History $0.30 $0.25 $0.20 $0.15 $0.10 $0.250 $0.250 $0.220 $0.230 $0.190 $0.200 $0.189 $0.149 $0.25/ Unit $0.19/ Unit $0.22/ Unit $0.20/ Unit $0.228/ Unit $0.149/ Unit $0.189/ Unit $0.05 $0.00 3Q'14 4Q'14 1Q'15 2Q'15 3Q'15 4Q'15 1Q'16 2Q'16 $/Unit 20 Source: Company data and filings. (1) As of 8/1/2016, pro forma for 7 million share July equity raise, announced and closed mineral interest acquisitions. Includes Viper cash balance as of 6/30/2016.

In Conclusion Energy is a low-cost operator in one of the highest return basins. Complementary acreage additions Permian Basin focused Maintain operations excellence Efficient capital allocation Debt/Adjusted EBITDA < 2X Viper units an additional liquidity source Switched focus to horizontal drilling in late 2012 History of accretive acquisitions Purchase of mineral acres Continued D&C cost reduction Continued focus on cost structure (LOE & G&A) Aggressive development of minerals 21

22 APPENDIX

Midland Reeves Weld Lea Loving Martin Blaine Mckenzie Reagan Dunn Grady Karnes Upton Canadian Eddy Oil Price ($ per Bbl) $38.35 $38.57 $38.94 $40.14 $40.17 $40.39 $40.64 $40.99 $44.04 $44.48 $44.82 $46.82 $47.33 $47.46 $48.39 $54.95 $55.75 $56.41 $56.85 $58.30 $64.88 $65.44 $70.39 $70.64 $82.45 $83.25 Top Tier Economics Driving Rig Activity Oil Breakevens by Basin (15% ATAX IRR) (1) $90 (Net Locations per area) (440) (118) (336) (339) (172) Permian $60 $30 $0 FANG has extensive inventory in 5 of the top Lower 48 oil plays US Total Hz Rig Count Top 15 Oil Counties (2) 32 Midland Delaware Cana / Woodford Bakken Niobrara Eagle Ford 23 16 15 13 12 11 11 9 8 8 8 8 7 7 Top 5 Oil Basins Total Hz Rig Count Midland 74 Delaware 69 Eagle Ford 33 Cana Woodford 29 Williston 27 FANG has acreage in the core of the most active counties in the US 23 Source: Wall Street Research, Baker Hughes. (1) Per Wall Street research. Assumes gas price of $2.50 per Mcf. (2) Rig count data per Baker Hughes as of 7/29/2016.

Robust Multi-year Undeveloped Inventory in the Midland Basin 532 660 Identified Gross Potential Drilling Locations PUD Locations 523 77 262 409 298 2,761 Wolfcamp B Lower Spraberry Middle Spraberry Clearfork Wolfcamp A Wolfcamp C Cline Total Horizontal Target Wolfcamp B Lower Spraberry Middle Spraberry Clearfork Wolfcamp A Wolfcamp C Cline Total Locations (gross / net) 532/339 660/440 409/273 262/207 523/336 77/53 298/204 2,761 / 1,852 EUR / Well (Mboe) (1) 550 650 750 850 550 650 400 450 650 750 400 500 500 600 600 700 Average Lateral Length (2) 7,760 7,611 7,613 7,231 7,817 7,073 7,344 7,600 Resource Potential (MMboe) 210 357 166 85 245 22 113 1,199 Net Effective Horizontal Acreage (3) ~61,000 ~65,000 ~51,000 ~30,000 ~48,000 ~7,000 ~44,000 ~306,000 Estimated EURs for potential drilling locations are normalized to 7,500 in lateral length. Actual lateral length varies depending on numerous factors, including the lease geometry, anticipated characteristics and permitted spacing. Estimated EUR ranges based on 115 Wolfcamp B, 61 Lower Spraberry, 4 Middle Spraberry, 10 Wolfcamp A, 2 Clearfork, and 3 Cline wells that and/or Viper own an interest in and are in the 2015 Ryder Scott PDP Report and various geological and engineering assumptions made by management using company and public data sources. Potential drilling locations and EUR ranges are management estimates and may change materially over time as the Company and offset operators drill initial and/or additional wells in each target zone. Lower Spraberry inventory assumes 500 spacing in Spanish Trail, 660 spacing in the rest of Midland, Martin, Howard, Glasscock and Northeast Andrews and 880 spacing in other areas. Wolfcamp B inventory assumes 660 spacing except in Upton, Andrews, NW Martin and Dawson where it is 880 spacing. Wolfcamp A inventory assumes 660 spacing in Howard and Glasscock counties, 880 spacing in Midland and SW Martin, and 1320 spacing in other areas. Middle Spraberry inventory assumes 880 spacing in Midland, Martin and NE Andrews and 1320 spacing in other areas. Clearfork inventory assumes 660 spacing in East Central Andrews and 1320 spacing in other areas. Cline and Wolfcamp C inventory assumes 1320 spacing in all counties. 24 Source: Company Filings, Management Data and Estimates. Management estimates as of 12/31/2015. (1) EURs normalized to 7,500 lateral. (2) Lateral lengths vary from ~5,000 to 10,000 depending on lease geometry and other considerations. (3) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone.

Well Cost $MM Lower Spraberry Type Curve & Economics at $50 Oil Midland County Type Curve Economics EUR, 2 Stream Mboe 990 Peak 30 day IP, boe/d 1,030 Oil %, 2 stream basis 79% D & C Cost, $MM $5.0 ROR, % 100% ROR,% with minerals 180% PV10, $MM $7.5 PV10 with minerals, $MM $10.8 (1) 44% Uplift ROR Sensitivity EUR Mboe 650 810 990 1,200 $4.5 47% 82% 128% 200% $5.0 36% 63% 100% 163% $5.5 28% 49% 78% 123% $6.0 23% 40% 63% 102% 25 Source: Company Filings, Management Data and Estimates. Note: Based on $50/BBL WTI ($46.50/BBL realized price). Realized gas and NGL pricing is $2.15/Mcf and $13.00/BBL. Daily production normalized for operational shut-ins. Type curves based on normalized 7,500 laterals; actual lateral lengths vary. PV10 Value based on 100% working interest. (1) Represents additional ROR related to 84% ownership of Viper which owns an average 21.4% royalty interest underlying acreage in Spanish Trail operated by FANG.

Rate of return Resilient Lower Spraberry Economics in Spanish Trail 350% 300% 250% Spanish Trail Lower Spraberry Economics 200% 150% 100% 50% 0% $30/bbl $40/bbl $50/bbl $60/bbl (1) (1) $5.0MM (excl. Viper) $5.5MM (excl. Viper) $5.0MM (incl. Viper) $5.5MM (incl. Viper) Ryder Scott s Lower Spraberry EUR at Spanish Trail is 990 Mboe Viper ownership significantly increases rates of return 26 Source: Company Filings, Management Data and Estimates. Note: Based on $40/BBL WTI ($36.50/BBL realized price). Realized gas and NGL pricing is $2.15/Mcf and 30% of WTI. Based on 7500 lateral and average EUR of 990 Mboe. Assumes well costs of $5.0 million and $5.5 million. (1) Represents additional ROR related to 84% ownership of Viper which owns an average 21.4% royalty interest underlying acreage operated by FANG.

Midland Basin Reserves Summary Total Reserves Growth (MMboe) (1) FANG Standalone VNOM 156.9 26.3 112.8 18.5 63.6 130.6 10.3 94.3 53.3 Proved Reserves Represent Nearly a Decade of Reserve Life (2) 2015 total proved reserves increased 39% y/y to 156.9 MMboe s standalone proved reserves increased 38% y/y to 130.6 MMboe No undrilled vertical PUD locations 59% proved developed 2013 2014 2015 1P Reserves By Commodity 1P Reserves By Category F&D Costs NGL 17% Natural Gas 16% Oil 67% PUD 41% PD 59% ($/boe) 2013 2014 2015 Drill Bit F&D (3) $14.46 $11.09 $5.51 Reserve Replacement (4) 975% 793% 465% 156.9 MMBOE 156.9 MMBOE Organic Reserve Replacement (5) 573% 626% 422% 27 Source: Company Filings, Management Data and Estimates. (1) Historical FANG reserves per independent reserve report prepared by Ryder Scott as of 12/31/2015. (2) Based on midpoint of 2016 production guidance. (3) Defined as exploration and development costs divided by the sum of extensions and discoveries and revisions. 2013 F&D excludes negative revisions of 7.9 MMboe for vertical PUD downgrades and 0.3 MMboe of positive revisions due to higher product pricing. 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. (4) Defined as the sum of extensions, discoveries, revisions, and purchases, divided by annual production. (5) Defined as the sum of extensions, discoveries, and revisions, divided by annual production.

Energy Corporate Headquarters 500 West Texas Ave., Suite 1200 Midland, TX 79701 www.diamondbackenergy.com Adam Lawlis, Investor Relations (432) 221-7400 ir@diamondbackenergy.com 28