Investor Presentation

August 2020

Forward Looking Statement

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, dispositions, 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, relating to financial performance and results, the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by the Organization of Petroleum Exporting Countries ("OPEC") members and other oil exporting nations, the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the recent outbreak of a novel strain of coronavirus ("COVID-19"), or any government response to such occurrence or threat, conditions of U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies, U.S. and global economic conditions and political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies, current economic, business or industry conditions and resulting capital restraints, prices and demand for oil and natural gas, impact of impairment charges, effects of hedging arrangements, availability of drilling equipment and personnel, impact of reduced drilling activity, 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 Diamondback undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof.

The presentation also contains the Company's updated capital expenditure and production guidance for 2020. 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 2020. 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 2020 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.

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, loss from equity method investments, loss on damaged assets, gain (loss) on revaluation of investment, loss on extinguishment of debt and income tax (benefit) adjusted for 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 the measure 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. Our computation of Consolidated Adjusted EBITDA may not be comparable to other similarly titled measures of other companies or to such 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.

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 (including those of its consolidated subsidiaries) as of December 31, 2019 referenced 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.

2

Diamondback Energy: Leading Pure-play Permian Operator

Large Cap Permian pure-play E&P:

  • ~348,000 net Midland and Delaware basin acres(1)
  • >12,300 gross (>8,100 net) horizontal locations(1)

Low Cost Structure and Capital Flexibility:

  • Q2 2020 cash operating costs of $6.44 per boe, including industry-leading G&A of $0.41 per boe
  • Reduced original 2020 capital budget by ~$1.1 billion; >35% reduction versus original plan
  • Worked down operated rig count as contracts expired, leading to large build of drilled but uncompleted ("DUC") wells; provides enhanced capital efficiency and flexibility in 2H 2020 and 2021
  • Can maintain expected Q4 2020 oil production with 25% - 35% less capital than 2020 budget
  • Flexibility to reduce capital further should commodity prices weaken

Significant Liquidity and Capital Return:

  • ~$1.9 billion of standalone liquidity as of June 30, 2020
  • ~$2.9 billion of consolidated pro forma liquidity(2)
  • $191 million maturity in September 2021; no other material term debt maturities until 2024
  • Maintaining $1.50 per share annual dividend(3)

Source: Company data, public filings, and Bloomberg. Financial data as of 6/30/2020. Market data as of 7/31/2020.

3 (1)

Net acreage excludes exploratory, conventional and Quinn Ranch. Net locations internal company estimates as of 12/31/2019.

  1. Consolidated liquidity as of 6/30/2020, pro forma for Rattler's high yield debt offering completed in July 2020.
  2. Yield based on 7/31/2020 closing price. Future dividends subject to the discretion and approval of the Board of Directors.

Diamondback Acreage Map

Diamondback

Diamondback Market Snapshot

NASDAQ Symbol: FANG

Market Cap: $6,291 million

Net Debt: $5,933 million

Enterprise Value: $13,345 million

Share Count: 158 million

2020 Annual Dividend: $1.50 (3.8% current yield)(3)

Diamondback: Investment Highlights

Q2 2020 Highlights

Updated 2020 Guidance

Response to Commodity

Price Volatility

Significant Liquidity

  • Q2 2020 oil production of 176.3 Mbo/d; voluntarily curtailed 9.0 Mbo/d during Q2 2020
  • Drilled 58 gross operated horizontal wells and turned 15 wells to production in Q2 2020; nine wells turned to production in April, six in May and zero in June
  • Q2 2020 cash operating costs of $6.44 per boe; including cash G&A of $0.41 per boe
  • Q2 2020 dividend of $0.375 / share; payable August 20, 2020
  • Full year 2020 production guidance of 178.0 - 182.0 Mbo/d (290 - 305 Mboe/d)
  • Full year 2020 CAPEX guidance of $1.8 - $1.9 billion, down over 35% from original 2020 plan and 2019 actual CAPEX at the midpoint
  • Lowering LOE / G&A unit guidance by a combined $0.35 per boe at the midpoint
  • Q4 2020 exit rate production guidance of 170 - 175 Mbo/d (280 - 290 Mboe/d)
  • Cut operated rig count from 20 rigs entering the year to six rigs currently
  • Current per foot well costs down ~25% from 2019 costs
  • Added oil hedges covering >95% of estimated 2H 2020 oil production and removed all three-way collars; added 2021 hedges to cover ~50% of expected 2021 oil production(1)
  • Voluntarily curtailed 9.0 Mbo/d (16.1 Mboe/d) of production in Q2 2020; nearly all curtailed production back online after electing to return this curtailed production in June
  • Expect to exit 2020 with 110 - 140 drilled but uncompleted ("DUC") wells; can maintain estimated Q4 2020 oil production with 25% - 35% less capital than 2020 budget
  • Standalone liquidity of ~$1.9 billion as of June 30, 2020
  • $191 million of Senior Notes maturing September 2021; no other maturities before 2024
  • Total annual interest expense of ~$245 million; weighted average cost of debt of ~4.1%(2)
  • CAPEX cash outflow headwind in the first half of 2020 turns to free cash flow benefit in the second half of 2020 as activity reductions run through cash flow statement

Source: Company data and filings. Financial data as of 6/30/2020 unless otherwise noted.

4 (1)

As of 7/31/2020. Calculated as the average hedged volumes divided by the 2H 2020 average production implied from the midpoint of full year guidance range and 1H 2020 actual production; excludes basis and roll hedges.

  1. Interest includes both expensed and capitalized amounts. Cost of debt based on consolidated notes and outstanding revolver borrowings as of 6/30/2020, pro forma for Rattler's high yield debt offering completed in July 2020; revolver interest rates based on weighted average interest rates for 1H 2020.

Overview of 2020 Guidance and Capital Budget

2020 Activity and Guidance Midpoints vs 2019

2019A

Original 2020

Current 2020

Guidance

Guidance

Oil Production

210

Net Mbo/d

188

180

Net Lateral Feet

TIL Net Ft. (1,000's)

2,774

2,968

1,665

Capital Budget

$MM(1)

$2,921

$2,900

$1,850

LOE

$4.74

$ / Boe

$4.60

$4.40

Midland Basin

D,C&E Well Costs

$738

$735

$635

$ / TIL Lateral Ft.(2)

Delaware Basin

D,C&E Well Costs

$1,093

$1,100

$980

$ / TIL Lateral Ft.(2)

2020 Production and Activity Outlook

283.0

290 - 305

280 - 290

Mboe/d

Mboe/d

Voluntary

Mboe/d

205 - 215

Curtailments

Divested

Gross operated wells drilled

170 - 200

187.7

178 - 182

170 - 175

Gross operated wells TIL

Mbo/d

Mbo/d

Mbo/d

110 - 140

2019A

2020

Q4 2020

Gross DUC's at YE 2020

Guidance

Guidance

Mboe/d

2020 Gross Operated Activity Summary (Guidance Midpoint)

Drilled Wells

Completed Wells

331 317

210

185

151

9590

59

FY 2019

1H 2020

2H 2020E

FY 2020E

Source: Company data, filings and estimates. Note: 2019 production included ~6.5 Mboe/d divested on 7/1/2019; estimated 2020 production net of ~16.1 Mboe/d of voluntary curtailments during Q2 2020.

5

(1)

Capital budget includes spending for operated drill, complete and equip ("D,C&E"), non-operated properties and capital workovers, midstream and infrastructure; excludes long-haul pipeline investments and acquisitions.

(2)

Well costs assume gross Rattler costs. See note 1 on slide 6 for additional detail.

Significant Reduction to Capital Costs

  • Diamondback has realized significant capital cost savings through a combination of internal optimization and service cost concessions:
    Midland Basin: ~$170 / Ft. savings versus 2019; Delaware Basin: ~$290 / Ft. savings versus 2019
  • Current Midland Basin D,C&E costs between $530 - $600 per lateral foot ($450 - $500 per foot D&C)
  • Current Delaware Basin D,C&E costs between $750 - $850 per lateral foot ($650 - $700 per foot D&C)
  • Continue to aggressively pursue additional cost reductions

Gross Midland Basin D,C&E Well Costs ($ / Ft.)(1)

Gross Delaware Basin D,C&E Well Costs ($ / Ft.)(1)

$756

Drill ($/Ft.)

Complete ($/Ft.)

Equip ($/Ft.)

$1,132

Drill ($/Ft.)

Complete ($/Ft.)

Equip ($/Ft.)

$725

$738

$1,053

$1,093

$635

$980

$565

$800

Current Costs:

$530 - $600 / Ft.

Current Costs:

$750 - $850 / Ft.

1H 2019

2H 2019

FY 2019A

FY 2020

Current

1H 2019

2H 2019

FY 2019A

FY 2020

Current

Guidance

D,C&E Costs

Guidance

D,C&E Costs

FANG continues to make significant reductions to capital costs per lateral foot while increasing

development efficiencies across its acreage

Source: Company filings, management data and estimates.

6 (1)

Well costs assume gross Rattler costs. Net benefit of Rattler margins would result in approximately $25/Ft. of extra savings in the Midland Basin and approximately $40/Ft. of extra savings in the Delaware Basin.

Peer-Leading Cash Margins and Operating Costs

Diamondback Cash Operating Costs Including Interest Over Time ($ / Boe)(1)

$15

$12.51

$12.76

$11.63

LOE

Prod. taxes

G&T

Cash G&A

Interest

Mboe/d

$11.51

$12

$10.66

$10.50

$10.34

$10.36

$10.59

$/Boe

$8.84

$8.85

$9.55

$9.90

$9.95

$10.14

$10.17

$10.16

$9

$8.16

$6

$3

$0

1Q16

2Q16

3Q16

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

4Q18

1Q19

2Q19

3Q19

4Q19

1Q20

2Q20

325

260

195

130

65

0

Production (Mboe/d)

Cash Operating Costs Including Interest versus Extended Peer Group ($ / Boe)(1)

$/Boe

$20

LOE

Prod. taxes

G&T

Cash G&A

Interest

$14.16

$14.38

$14.68

$15.45

$15

$12.53

$12.98

$13.10

$12.29

$9.27

$10.36

$10.52

$10.65

$10.94

$10

$8.16

$5

$0

FANG

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

Peer 7

Peer 8

Peer 9

Peer 10

Peer 11

Peer 12

Peer 13

Peer leading cash operating costs and a low interest burden allow Diamondback to maintain high

cash margins in a weak commodity price environment

Source: Company data and latest peer filings as of 7/31/2020. Extended peers include PXD, CLR, XEC, CXO, PE, APA, NBL, MRO, OVV, WPX, EOG, DVN and HES.

7 (1)

Cash operating costs including interest calculated as the sum of LOE, G&T, production taxes, cash G&A expense and interest expense per boe.

Track Record of Aligning Development with Commodity Prices

  • FANG has a track record of achieving robust production growth while spending within cash flow, with a willingness and demonstrated ability to adjust activity levels quickly to react to challenging market conditions
  • Current 2020 plan implies >35% reduction to operated activity versus original 2020 plan; >70% of remaining activity focused on lower cost development in the Midland Basin
  • Short-termservice contracts provide flexibility to reduce plan further if needed

Gross Lateral Footage Completed by Quarter

TIL Lateral Footage

900k'

Delaware Basin TIL Lateral Ft.

Midland Basin TIL Lateral Ft.

Average Completed Lateral Length

840k'

791k'

780k'

750k'

733k'

WTI Oil ($/Bbl)

678k'

600k'

465k'

447k'

2020

451k'

450k'

414k'

383k'

activity cut

FANG

FANG

315k'

activity cut

270k'

300k'

activity cut

220k'

230k'

206k'

143k'

169k'

55%

52%

169k'

44%

113k'

37%

150k'

95k'

100k'

91k'

50%

32%

62k'

31%

<30%

29%

24%

0k'

4%

14%

9%

17%

31%

12,500'

10,000'

7,500'

LengthLateral

5,000'

Average

2,500'

0'

Source: Company data, filings and estimates.

8

The Multiple Definitions of "Free Cash Flow"

  • Recent investor focus has been towards a sustainable free cash flow ("FCF") model that consistently returns capital to shareholders
  • However, the industry calculates FCF differently and inconsistently between reporting periods, with numbers that do not tie to a financial statement. Accrued CAPEX, in particular, is grossly misused, and does not tie to a cash flow statement for nearly all peers

Diamondback's Q2 2020 Free Cash Flow Reconciliation using Various Industry Definitions

No Cash Flow Statement Reconciliation

Some Peers

Adjusted EBITDA

$441 MM

Interest Expense

$46 MM

(+ cash taxes if applicable)

Accrued CAPEX

$348 MM

Free Cash Flow

+$47 MM

Some Cash Flow Statement Reconciliation

Most Peers

Operating Cash Flow

$390 MM

(Before Working Capital Changes)

Accrued CAPEX

$348 MM

Activity-BasedEstimates:Operated D,C&E non-operated properties, midstream and infrastructure

Free Cash Flow

+$42 MM

Full Cash Flow Statement Reconciliation

FANG Definition

Operating Cash Flow

$390 MM

(Before Working Capital Changes)

Cash Flow CAPEX

$562 MM

Actual Cash Spend for Current / Prior Activity:

  • $488MM - Additions to Oil & Gas Properties + $24MM - Additions to Infrastructure
    + $50MM - Additions to Midstream

Free Cash Flow

-$172 MM

Diamondback believes that however the investment community looks at FCF, it must apply the definition consistently between reporting periods and numbers need to tie to financial statements.

Source: Company filings, management data and estimates.

9

Midland Basin Inventory and Development Strategy

Diamondback Midland Basin Inventory:

  • >7,000 gross (~4,970 net) horizontal locations with an average lateral length of ~8,300 feet
  • Primary zones:>3,300 net locations (MS, LS, WCA and WCB); total net lateral footage up 19% from YE 2018(1)
  • Diamondback has moved to co-development of more economic zones together, particularly in the Midland Basin, but has not changed inter-lateral spacing assumptions within each zone
  • Average inter-lateral spacing assumptions within each zone unchanged since 2014

Midland Basin Development Strategy:

  • Development has moved to incorporate more economic zones completed simultaneously, or co-development
  • As acreage position has grown and zones such as the MS and WCB have been successfully tested, more activity has been added to the development plan
  • 2020 activity plan focused on simultaneous development of

economic zones that meet return thresholds

(2)

  • If co-development is not necessary, Diamondback will develop the highest rate of return zone first

Midland Basin Economic Locations at Various Oil Prices(2)

Oil Price

Gross Economic

Locations

$35 / Bbl

3,258

$40 / Bbl

4,772

$45 / Bbl

5,667

$50 / Bbl

6,219

Gross (Net) Midland Basin Locations by Zone / Lateral

5,000'+

7,500'+

10,000'+

Total

Avg. Lateral

MS

212 (89)

341

(252)

598

(479)

1,151 (820)

8,500'

LS

305 (137)

346

(243)

580

(473)

1,231 (853)

8,200'

WCA

296 (128)

338

(239)

571

(459)

1,205 (826)

8,200'

WCB

286 (121)

342

(247)

585

(469)

1,213 (837)

8,200'

Other(3)

472 (219)

571

(430)

1,194 (985)

2,237 (1,635)

8,400'

Total

1,571 (694)

1,938

(1,411)

3,528

(2,865)

7,037 (4,971)

8,300'

Diamondback has consistently maintained conservative spacing assumptions, preferring an "at least" strategy to a

"best case scenario" strategy

Source:

10 (1)(2)

(3)

Company data, filings and estimates. Note: locations based on internal company estimates as of 12/31/2019; excludes Quinn Ranch. Primary zones include Jo Mill / Middle Spraberry ("MS"), Lower Spraberry ("LS"), Wolfcamp A ("WCA") and Wolfcamp B ("WCB").

Defined as gross locations that can generate at least a 10% rate of return. Assumes current well costs, 25% of WTI NGL pricing and $0/Mcf gas prices. Other zones comprised of Wolfcamp D, Wolfcamp C, Clearfork and Barnett intervals.

Delaware Basin Inventory and Development Strategy

Diamondback Delaware Basin Inventory:

  • >5,200 gross (3,170 net) horizontal locations with an average lateral length of ~7,600 feet
  • Primary zones:>2,500 net locations (2BS, 3BS, WCA and WCB); total net lateral footage up 5% from YE 2018(1)
  • Successfully traded majority of operated New Mexico acreage in the Northern Delaware Basin for operated Texas acreage in both Midland / Delaware basin; <0.1% of current net acreage exposed to federal land
  • Average inter-lateral spacing assumptions within each zone unchanged since entering the basin in 2016

Delaware Basin Development Strategy:

  • Primarily focused on WCA development, which remains highest rate of return zone in the Delaware Basin
  • Other zones continue to attract some capital, such as the 2BS in Pecos County, 3BS in ReWard and WCB in Vermejo
  • 2020 activity plan focused primarily on WCA and simultaneous development of economic zones that meet

return thresholds

(1)

Delaware Basin Economic Locations at Various Oil Prices(2)

Oil Price

Gross Economic

Locations

$35 / Bbl

1,666

$40 / Bbl

2,408

$45 / Bbl

2,842

$50 / Bbl

3,452

Gross (Net) Delaware Basin Locations by Zone / Lateral

5,000'+

7,500'+

10,000'+

Total

Avg. Lateral

2BS

340

(219)

253 (175)

364

(235)

957

(629)

7,600'

3BS

420

(257)

290 (178)

467

(287)

1,177 (722)

7,700'

WCA

343

(194)

254 (157)

347

(215)

944

(566)

7,600'

WCB

346

(189)

274 (186)

430

(284)

1,050 (659)

7,800'

Other(3)

510

(241)

310 (151)

325

(201)

1,145 (594)

7,100'

Total

1,959

(1,101)

1,381 (846)

1,933

(1,223)

5,273

(3,170)

7,600'

Diamondback has consistently maintained conservative spacing assumptions, preferring an "at least" strategy to a

"best case scenario" strategy

Source:

11 (1)(2)

(3)

Company data, filings and estimates. Note: locations based on internal company estimates as of 12/31/2019.

Primary zones include Second Bone Spring ("2BS"), Third Bone Spring ("3BS"), Wolfcamp A ("WCA") and Wolfcamp B ("WCB")

Defined as gross locations that can generate at least a 10% rate of return. Assumes current well costs, 25% of WTI NGL pricing and $0/Mcf gas prices. Other zones primarily comprised of the 1st Bone Spring and Wolfcamp C intervals.

Current Hedges Maximize Downside Protection For Remainder 2020

2H 2020 Crude Oil Hedges

>95%

~100% Hedged

120,000 Bo/d

2H 2020 Hedge Protection(1)

Midland / WTL Basis Exposure

WTI Roll Hedges

2021 Crude Oil Hedges

~50%

~98% of Hedges

~70% of Hedges

FY 2021 Hedge Protection(1)

Swaps / 2-Way Collars (FY 2021)

Upside Participation (FY 2021)(2)

Consolidated Oil Hedges (Mbo/d)(3)

Hedged (Mbo/d)

250

Brent

WTI

MEH

Downside Protection Price

Upside Participation Price

Strip

$60

201

187

Price ($/Bbl)

200

$54

167

162

$46.40

$46.43

Consolidated Volumes

150

$45.12

$45.45

$48

Weighted Average Hedge

100

91

80

$42

$39.96

$40.20

50

$38.25

$38.29

$36

0

$30

Q1 2020

Q2 2020

Q3 2020

Q4 2020

1H 2021

2H 2021

Diamondback proactively restructured hedges, with downside protection on over 95% of expected remaining 2020 oil production and nearly 50% of expected 2021 oil production(1)

Source: Company data, filings and estimates and Bloomberg as of 7/31/2020.

12 (1) Based on management expectations and remaining 2020 oil production implied by FY 2020 oil production guidance and 1H 2020 actual production.

(2) Based on consolidated 2021 oil hedges relative to NYMEX strip pricing as of 7/31/2020.

  1. Excludes basis / roll swaps and calls. See slides 16-17 for additional detail.

Oil Takeaway Solutions

Oil Purchase Contracts:

  • Diamondback's oil production is purchased under long term purchase agreements with four large, well-funded counterparties
  • Every major operating area has a long term oil purchase agreement and is dedicated to a long haul pipeline
  • Long-termagreements and associated physical pipeline space provide insurance in times of uncertainty

Obligations and Pricing Exposure:

  • Take or pay obligations to pipelines and firm sales in 2020 cover 125,000 gross bo/d
    • Increases to 175,000 gross bo/d in 2021 with the in-service date of the Wink to Webster pipeline
  • Expects to receive Brent pricing for ~60% of 2H20 production; Brent (~60%) and MEH (~40%) in 2021

Unhedged Oil Exposure by Purchaser and Price

Purchaser 3

MEH

Purchaser 4

WTL

Purchaser 2

Other

WTI

Brent

Midland

Purchaser 1

Oil Takeaway Solutions

Gatherer: OMOG (RTLR JV)

Purchaser: Vitol

Gatherer: Plains

Long Haul: EPIC

Purchaser: Plains

API Gravity: 38° - 40°

Long Haul: WTW

API Gravity: 44°- 47°

Gatherer: Plains

Gatherer: Nustar

Purchaser: Plains

Purchaser: Shell

Long Haul: WTW

Long Haul: EPIC

API Gravity: 38°- 40°

API Gravity: 38°- 40°

Gatherers: Rattler, EPD, Plains, Reliance

Purchasers: Trafigura, Vitol

Long Haul: Cactus II and EPIC

API Gravity: 38°- 40°

Gatherers: Rattler, Plains

Purchaser: Plains

Gatherers: Rattler, Oryx

Long Haul: WTW

Purchaser: Vitol

API Gravity: 38°- 41°

Long Haul: Gray Oak

API Gravity: 40°- 43°

Diamondback's oil marketing agreements provide long-term flow assurance to the most liquid markets as well as

minimize local basis exposure

Source: Company filings, management data and estimates.

13

Capital Structure and Liquidity

  • Standalone liquidity of ~$1.9 billion as of June 30, 2020(1)
  • Consolidated pro forma liquidity of ~$2.9 billion(2)
  • In May 2020, Diamondback issued $500 million of 4.75% senior notes due 2025; proceeds used to tender for 2021 notes and increase liquidity
  • Completed tender offer for ~55% of $400 million senior notes maturing in September 2021; no other material term debt maturities until 2024
  • Future free cash flow in excess of the dividend will be used to reduce debt

FANG's Liquidity and Capitalization ($MM)

FANG's Consolidated Capitalization

6/30/2020

Cash and cash equivalents

$51

FANG's Revolving Credit Facility

$119

VNOM's Revolving Credit Facility

154

RTLR's Revolving Credit Facility

523

Senior Notes

5,107

DrillCo Agreement

82

Total Debt

$5,984

Net Debt

$5,933

FANG's Standalone Liquidity

6/30/2020

Cash

(1)

$30

Elected commitment amount

2,000

Liquidity

$1,911

FANG's Pro Forma Debt Maturity Profile ($MM)(2)

$2,500

$139

$1,800

$2,000

$1,500

Rattler Notes

$1,200

$1,000

5.625%

$1,000

$500

$800

FANG Credit

Elected

4.750%

$496

$500

Facility

Commitment

3.500%

$191

2.875%

$800

3.250%

Viper Notes

$100

$0

4.625%

5.375%

5.375%

7.130%

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

Source: Company Filings, Management data and Estimates.

  1. Excludes Viper and Rattler.

14 (2) Pro forma for Rattler's $500 million senior note offering completed in July 2020.

Updated 2020 Guidance

  • Immediately responded to unprecedented decline in oil prices; updated 2020 plan implies >35% reduction in CAPEX and activity from original 2020 plan
  • D,C&E CAPEX budget of $1,565 - $1,630 million; expect to complete 170 - 200 gross horizontal wells with an average lateral length of ~10,000 feet
  • Anticipated total infrastructure and midstream capital expenditures of $235 - $270 million
  • Lowered LOE and G&A unit guidance by a combined $0.35 per boe at the midpoint of each guidance range; implies cash operating cost savings of over $38 million for 2020

Diamondback 2020 Capital Activity Guidance(2)

Gross (net) horizontal wells completed

170 - 200 (153 - 180)

Average completed lateral length (ft.)

~10,000'

Midland Basin net lateral feet (%)

~60%

Delaware Basin net lateral feet (%)

~40%

Gross horizontal D,C&E / ft. - Midland Basin

$600 - $670

Gross horizontal D,C&E / ft. - Delaware Basin

$930 - $1,030

2020 Guidance

Diamondback

Viper

Net Production - Mboe/d

290.0

- 305.0

25.25

- 26.25

Oil Production - Mbo/d

178.0

- 182.0

15.25

- 16.00

Unit Costs ($/boe)

Lease Operating Expenses

$4.20 - $4.60

Gathering & Transportation

$1.25

- $1.35

Cash G&A

$0.50

- $0.70

$0.60

- $0.80

Non-Cash Equity Based

$0.30

- $0.50

$0.10

- $0.25

Compensation

D,D&A

$12.00 - $14.00

$9.50 - $11.50

Interest Expense (net)

$1.75

$3.25 - $3.75

Production and Ad Valorem

7%

- 8%

7%

- 8%

Taxes (% of Revenue)(3)

Corporate Tax Rate

23%

(% of Pre-tax Income)

Diamondback Capex Budget ($MM)

D,C&E and Non-Operated Properties

$1,565 - $1,630

Midstream (ex. long-haul pipeline investments)

$125 - $150

Infrastructure

$110 - $120

Total 2020 Capital Budget

$1,800 - $1,900

Source: Company filings, management data and estimates. Note: Based on 2020 guidance provided on 8/3/2020, which is subject to numerous assumptions and risks. See the disclaimer at the beginning of this presentation.

15 (1) Gross D,C&E per foot guidance excludes Rattler cost savings.

(2) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.

Current Hedge Summary: Oil

Consolidated Crude Oil Hedges (Bbl/day, $/Bbl)

Crude Oil Hedges

Q3 2020

Q4 2020

1H 2021

2H 2021

Swaps - WTI

11,000

11,000

-

-

$43.47

$43.47

-

-

Swaps - MEH

4,000

4,000

5,000

5,000

$61.95

$61.95

$37.78

$37.78

Swaps - Brent(1)

24,200

24,200

10,000

5,000

$47.62

$47.62

$41.56

$41.62

Total Oil Swaps

39,200

39,200

15,000

10,000

Costless Collars - WTI

51,029

45,779

10,000

10,000

Floor / Ceiling

$35.56 / $41.54

$35.92 / $42.29

$30.00 / $43.05

$30.00 / $43.05

Costless Collars - MEH

4,000

4,000

-

-

Floor / Ceiling

$39.00 / $49.00

$39.00 / $49.00

-

-

Costless Collars - Brent

64,710

64,710

66,000

60,000

Floor / Ceiling

$37.59 / $45.63

$37.59 / $45.63

$39.03 / $48.29

$39.43 / $48.12

Total Costless Collars

119,739

114,489

76,000

70,000

Puts - WTI

4,700

4,700

-

-

$46.51

$46.51

-

-

Calls - WTI(2)

-

8,000

-

-

-

$45.00

-

-

Total Puts / Calls

4,700

12,700

--

--

Put Spreads - MEH

3,800

3,800

-

-

Short Put / Long Put

$25.00 / $50.00

$25.00 / $50.00

-

-

Total Put Spreads

3,800

3,800

--

--

Total Crude Oil Hedges

167,439

170,189

91,000

80,000

Source: Company data as of 8/3/2020.

16

(1)

1H 2021 Brent swaps include 5,000 Bo/d whereby the counterparty has the right to extend the hedge into the second half of 2021 at an average price of $41.50/Bbl.

(2)

Includes a deferred premium at a weighted-average price of $1.89/Bbl and a strike price of $45/Bbl.

Current Hedge Summary: Oil Basis, NGL's and Natural Gas

Consolidated Oil Basis / Natural Gas Liquids Hedges (Bbl/day, $/Bbl)

Crude Oil Hedges

2H 2020

Natural Gas Liquids Hedges

2H 2020

45,087

7,000

Basis Swaps - WTI

Swaps - Mont Belvieu Ethane

($1.33)

$8.43

8,000

5,000

Basis Swaps - WTL

Swaps - Mont Belvieu Propane

($1.31)

$21.76

Total Basis Swaps

53,087

Total Swaps

12,000

120,000

Roll Swaps - WTI

($1.05)

Total Roll Swaps

120,000

Consolidated Natural Gas Hedges (Mmbtu/day, $/Mmbtu)

Natural Gas Hedges

Q3 2020

Q4 2020

1H 2021

2H 2021

FY 2022

60,000

60,000

170,000

170,000

-

Swaps - Henry Hub

$2.48

$2.48

$2.58

$2.58

-

Swaps - Waha(1)

90,000

90,000

-

-

-

Fixed Price

$1.58

$1.58

-

-

-

Total Swaps

150,000

150,000

170,000

170,000

-

145,000

145,000

230,000

230,000

60,000

Basis Swaps - Waha

($1.57)

($1.57)

($0.69)

($0.69)

($0.46)

Total Basis Swaps

145,000

145,000

230,000

230,000

60,000

Source: Company data as of 8/3/2020.

17

(1)

Remaining 2020 fixed price Waha swaps exclude additional 30,000 Mcf/d of hedges exercisable at $1.70/Mcf at option of counterparty.

Differential Per Share Metrics and Cost Structure

Return On and Return Of Capital

Significant Resource Potential

Conservative Financial Management

Strategic Acquisitions and Execution

Efficient Conversion of Resource to Cash Flow

APPENDIX

19

Environmental, Social and Governance ("ESG")

  • Diamondback is deeply committed to the safe and responsible development of its resources
  • As our organization has grown to be in a leadership position in the Permian Basin, we continue to believe we have a responsibility to minimize our environmental impact across our operating footprint
  • Corporate responsibility initiatives center on a dozen key areas: risk management, energy intensity, global climate change, emissions, waste and spills, water use, business ethics, compliance, diversity and inclusion, health and safety, training and education, and community engagement
  • 2019 Corporate Responsibility Report available atwww.diamondbackenergy.com/about/sustainability

Water Recycling (% of Produced)

Workplace Safety (TRIR / LTIR)

Flaring (% of Net Production)

Water recycling up 81% since 2018

Zero safety incidents in 1H 2020

Flaring down ~45% since 2019

19.4%

0.53

0.53

5.6%

16.9%

0.42

TRIR

2019

10.7%

0.28

LTIR

2.9%

1H 2020

1.9%

1.1%

0.7%

0.00

0.00

2017

2018

2019

1H 2020

2018

2019

1H 2020

% of Gross Gas

% of Net BOE

Source: Company data and filings.

20

Recent Changes to ESG and Compensation

  • Diamondback seeks to expand its best in class track record on both disclosure and performance as it relates to sustainable long-term development of its natural resources
  • 2020 Proxy Report available atwww.diamondbackenergy.com

Dedicated ESG Oversight

Proxy Access

Change of Control

Long-term Incentive Compensation

("LTI")

Short-term Incentive Compensation

("STI")

Recent Changes to ESG and Compensation

  • Formed Safety, Sustainability and Corporate Responsibility Committee of the Board of Directors in the fourth quarter of 2019
  • Adopted Proxy Access in Q4 2019
  • Replaced executive employment agreements with a severance and change of control plan consistent with current market practice
  • Added an absolute total shareholder return ("TSR") modifier to LTI:
    • Reduces payouts upon negative performance period TSR
    • No modification upon achieving a performance period annual TSR of 0-15%
    • Includes multiplier upon achieving a performance period annual TSR >15%
  • Updated annual metrics to include an ESG component with 15% weighting
  • ESG component to be determined by meeting or exceeding key environmental and safety metrics including flaring, GHG emissions, recycled water, oil spill control and Total Recordable Incident Rate
  • Existing metrics unchanged from 2019 (ROACE, D,C&E/Ft. well costs and per boe PD F&D costs, LOE and Cash G&A)

Source: Company data and filings.

21

Build-out of Midstream Assets Through Rattler Midstream

Rattler Midstream:

  • Publicly-tradedmidstream subsidiary (NASDAQ: RTLR) created by Diamondback
  • Interests fully aligned with upstream operations:
  • Assets located in all seven core operating areas
  • Midstream services key to Diamondback's low-cost operations
  • Close coordination and development visibility allows efficient and timely midstream build-out
  • Vehicle for participation in non-upstream investment opportunities such as long-haul pipelines
  • 2020E Distribution:$1.16 / unit (14.7% yield)(1)

Rattler Capacity Overview

Fee Stream

Midland

Delaware

Produced Water - Bbl/d

1,842,000

1,482,000

Sourced Water - Bbl/d

455,000

120,000

Crude Oil - Bbl/d

56,000

180,000

Natural Gas - Mcf/d

--

150,000(2)

Total

>2,350,000

>1,930,000

Rattler Midstream Asset Map

Spanish Trail North:

Howard County:

Sourced Water

Sourced Water

Produced Water

Produced Water

Reeves / Loving:

Produced Water

Spanish Trail:

Sourced Water

Produced Water

Crude Gathering

Pecos / ReWard:

Sourced Water

Produced Water

Crude Gathering

Gas Gathering (Pecos)

Glasscock County:

Sourced Water

Produced Water

Crude Gathering

Rattler secures FANG's access to vital midstream services and supports FANG's low-cost operations

via improving realizations and lower LOE

Source: Company filings, management data and estimates.

22 (1) Based on Rattler's 2020 guidance provided on 5/6/2020. Yield based on RTLR's closing price as of 7/31/2020.

(2) 135,000 Mcf/d compression capacity.

Viper Update

Viper Energy Partners:

  • Publicly-tradedmineral and royalty subsidiary (NASDAQ: VNOM) created by Diamondback
  • Focused on owning and acquiring minerals and royalty interests in the Permian Basin, with a primary focus on Diamondback-operated acreage
  • 24,714 net royalty acres, 51% of which are operated by Diamondback
  • Diamondback incentivized to focus development on
    Viper's acreage when possible due to improved consolidated returns
  • 14 of Diamondback's 15 Q2 2020 completions on Viper's acreage, in which Viper owned a more than 8% average
    NRI
  • Q2 2020 average oil production of 14.5 Mbo/d; generated $0.12 / unit in distributable cash flow
  • Outside of Diamondback operating almost 60% of
    Viper's current oil production, Viper has diversified exposure to other competent operators within the Permian Basin and Eagle Ford Shale

Viper Mineral and Royalty Assets

VNOM royalty acreage

FANG acreage

Viper's Mineral and Royalty Interests Provide Perpetual Ownership Exposure to High Margin,

Largely Undeveloped Assets and Lower Diamondback's Consolidated Breakevens

Source: Partnership data and filings. Data as of 6/30/2020.

23

High Growth, Oil Weighted Reserves

  • YE19 proved reserves increased 14% y/y to 1,128 MMBoe (711 MMBo, 67% PDP)
  • PDP reserves of 760 MMBoe, up 18% y/y; PDP oil reserves of 457 MMBo, up 13% y/y
  • Oil comprised 63% of total proved reserves on 3- stream basis; ~69% of total on 2-stream basis
  • Consolidated proved developed F&D for 2019 was $10.87/boe with drill bit F&D of $11.11

F&D Costs

($/boe)

2017

2018

2019

Proved Developed

$9.09

$10.44

$10.87

F&D(2)

Drill Bit F&D(3)

$7.22

$7.28

$11.11

Reserve

549%

1,479%

231%

Replacement(4)

Organic Reserve

443%

457%

250%

Replacement(5)

Total Reserve Growth (MMBoe) (1)

FANG Standalone

VNOM

1,128

992

1,039

335

929

157

205

113

64

297

174

53

94

131

YE13

YE14

YE15

YE16

YE17

YE18

YE19

1P Reserves - By Commodity

1P Reserves - By Category

Natural

Gas

17%

PUD

NGL

33%

Oil

20%

PD

63%

67%

1,128 MMBOE

1,128 MMBOE

Source: Company Filings, Management Data and Estimates.

24 (1) Historical FANG reserves per independent reserve report prepared by Ryder Scott as of 12/31/2019.

  1. PD F&D costs are defined as exploration and development costs divided by the sum of reserves associated with transfers from proved undeveloped reserves at YE2018 including any associated revisions in 2019 and extensions and discoveries placed on production during 2019.
  1. Drill bit F&D costs are defined as the exploration and development costs divided by the sum of extensions, discoveries and recoveries.
  2. Defined as the sum of extensions, discoveries, revisions, and purchases, divided by annual production.
  3. Defined as the sum of extensions, discoveries, and revisions, divided by annual production.

Diamondback Energy Corporate Headquarters

Adam Lawlis, Vice President, Investor Relations

500 West Texas Ave., Suite 1200

(432) 221-7400

Midland, TX 79701

ir@diamondbackenergy.com

www.diamondbackenergy.com

25

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Diamondback Energy Inc. published this content on 03 August 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 03 August 2020 20:16:04 UTC