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Filed by Diamondback Energy, Inc. Pursuant to Rule 425 under the Securities Act of 1933, as amended and deemed filed pursuant to Rule 14a-12 under the Securities Exchange Act of 1934, as amended Subject Company: QEP Resources, Inc. Commission File No.: 001-34778 Date: February 22, 2021 The following investor presentation was posted to Diamondback Energy, Inc.’s website on February 22, 2021. The presentation can be found at www.diamondbackenergy.com under the “Events & Presentations” section on the “Investors” page.
1 Investor Presentation February 2021
2 Forward Looking Statement and Non-GAAP Financial Measures 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. (“we”, 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, environmental targets, 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, the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing coronavirus (“COVID-19”) pandemic, or any government response to such threat, occurrence or pandemic; 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 impact of the recent U.S. presidential and congressional elections on energy and environmental policies and regulations, any other potential regulatory actions (including those that may impose production limits in the Permian Basin), current macroeconomic conditions, demand for oil and natural gas, impact of impairment charges, effects of hedging arrangements, availability of drilling equipment and personnel, levels of production; severe weather conditions (including the impact of the recent severe winter storms on production volume), impact of reduced drilling activity, availability of sufficient capital to execute the Company’s business plan, 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, including the pending merger with QEP Resources, Inc. (“QEP”) and acquisition of certain assets from Guidon Operating LLC (“Guidon”), 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 and certain forward-looking information with respect to 2021. The actual levels of production, capital expenditures, expenses and other estimates 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 and Free Cash Flow are supplemental non-GAAP financial measures 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 our earnings release furnished to, and other filings we make with the SEC. Free Cash Flow is cash flow from operating activities before changes in working capital in excess of cash capital expenditures. Management believes that Free Cash Flow is useful to investors as it provides a measure to compare both cash flow from operating activities and additions to oil and natural gas properties across periods on a consistent basis. These measures should not be considered as an alternative to, or more meaningful than, net cash provided by operating activities as an indicator of operating performance. Our computation of operating cash flow before working capital changes and Free Cash Flow may not be comparable to other similarly titled measures of other companies. For a reconciliation of net cash provided by operating activities to operating cash flow before working capital changes and to Free Cash Flow, please refer to our earnings release furnished to, and other 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, 2020 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.
3 Important Information for Investors and Stockholders IMPORTANT INFORMATION FOR INVESTORS AND STOCKHOLDERS; ADDITIONAL INFORMATION AND WHERE TO FIND IT As previously announced, on December 20, 2020, the Company, QEP and Bohemia Merger Sub, Inc., the Company’s wholly owned subsidiary (“Merger Sub”), entered into an Agreement and Plan of Merger, as may be amended from time to time, under which, Merger Sub will be merged with and into QEP, with QEP surviving as the Company’s direct, wholly owned subsidiary (the “Pending Merger”). This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. In connection with the Pending Merger, the Company previously filed with the Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4, as amended, which was declared effective by the SEC on February 10, 2021 (the “Registration Statement”). The Registration Statement includes a proxy statement of QEP that also constitutes a prospectus of the Company. Each of the Company and QEP have filed and may continue to file other relevant documents with the SEC regarding the Pending Merger. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act. A definitive proxy statement of QEP was mailed to stockholders of QEP on or about February 10, 2021. INVESTORS AND SECURITY HOLDERS OF THE COMPANY AND QEP ARE URGED TO READ THE REGISTRATION STATEMENT, PROXY STATEMENT/PROSPECTUS AND OTHER DOCUMENTS THAT HAVE BEEN, AND MAY IN THE FUTURE BE, FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PENDING MERGER. Investors and security holders will be able to obtain free copies of these documents and other documents containing important information about the Company and QEP, once such documents are filed with the SEC through the website maintained by the SEC at http://www.sec.gov. Copies of the documents filed with the SEC by the Company are available free of charge on the Company’s website at https://www.diamondbackenergy.com/home/default.aspx under the tab “Investors” and then under the heading “Financial Information.” Copies of the documents filed with the SEC by QEP are available free of charge on QEP’s website at https://www.qepres.com under the tab “Investors” and then under the heading “Financial Information.” PARTICIPANTS IN THE SOLICITATION The Company, QEP and certain of their respective directors, executive officers and other persons may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding the directors and executive officers of the Company is available in its definitive proxy statement for its 2020 annual meeting, filed with the SEC on April 24, 2020, and information regarding the directors and executive officers of QEP is available in its definitive proxy statement for its 2020 annual meeting, filed with the SEC on April 2, 2020. Other information regarding the participants in the proxy solicitations and a description of their direct and indirect interests, by security holdings or otherwise, is contained in the Rule 424(b)(3) prospectus filed with the SEC on February 10, 2021. Investors should read the prospectus carefully before making any voting or investment decisions. You may obtain free copies of these documents from the Company or QEP using the sources indicated above.
4 Diamondback Pro Forma Acreage Map(5) Diamondback Energy: Leading Pure-play Permian Operator Large Cap Permian pure-play E&P: >347,000 net Midland and Delaware basin acres(1) Pending Guidon acquisition expected to close 2/26/2021; adds ~32,500 net acres in the Northern Midland Basin Shareholder vote for previously announced all-stock acquisition of QEP Resources (“QEP”) scheduled for 3/16/2021; assuming a successful close, will provide updated FY 2021 guidance giving effect to QEP thereafter Low Cost Structure and Capital Flexibility: Generated >$240 million of Free Cash Flow (“FCF”) in Q4 2020, with cash operating costs of $6.87 per boe(2) Expect to maintain expected pro forma Q4 2020 oil production with 22% less capital than standalone 2020 Targeting 2021 reinvestment rate of ~70% assuming WTI oil prices of $40/Bbl with significant Free Cash Flow(2) Significant Liquidity and Capital Return: $1.60 per share annual dividend, up 7% from $1.50 per share previously(4) >$2.0 billion of standalone liquidity as of YE 2020(3) $191 million maturity in September 2021; no other material term debt maturities until 2024 NASDAQ Symbol: FANG Market Cap: $10,359 million Net Debt: $5,751 million Enterprise Value: $17,120 million Share Count: 158 million 2021 Annual Dividend: $1.60 (2.4% current yield)(4) Diamondback Market Snapshot Source: Company data, public filings, and Bloomberg. Financial data as of 12/31/2020. Market data as of 2/19/2021. (1) Net acreage excludes exploratory and conventional Diamondback acreage, as well as acreage from the pending Guidon and QEP transactions. (2) FCF defined as operating cash flow before changes in working capital less cash CAPEX. Reinvestment rate calculated as cash CAPEX divided by pre-dividend operating cash flow before changes in working capital. See slides 8-9 for more detail. (3) Excludes Viper and Rattler. (4) Yield based on 2/19/2021 closing price. Future dividends subject to the discretion and approval of the Board of Directors. (5) Includes ~81,500 net surface acres in the Midland Basin from the pending Guidon and QEP transactions. FANG Guidon QEP
5 ◆ Generated $242 million of FCF in Q4 2020(1) ◆ Q4 2020 oil production of 175.8 Mbo/d (299.0 Mboe/d); up 3% over Q3 2020 ◆ Q4 2020 cash operating costs of $6.87 per boe; including cash G&A of $0.51 per boe ◆ Q4 2020 dividend of $0.40 / share; payable March 11, 2021 ◆ Reduced flaring to 0.9% of gross gas production in Q4 2020, down >80% from 2019 Diamondback: Investment Highlights 2021 Guidance: Pro Forma for Guidon Transaction ◆ FY 2021 production guidance of 178 – 185 Mbo/d (308 – 325 Mboe/d) ◆ FY 2021 cash CAPEX guidance of $1.35 - $1.55 billion; implies 22% reduction from 2020 ◆ Expect to drill 180 – 200 gross wells and complete 215 – 235 gross horizontal wells in 2021 with an average lateral of ~10,100 feet (75% Midland Basin / 25% Delaware Basin) ◆ Midland Basin D,C&E cost guidance of $520 - $580 per lateral foot(2) ◆ Delaware Basin D,C&E cost guidance of $720 - $800 per lateral foot(2) Source: Company data and filings. Financial data as of 12/31/2020 unless otherwise noted. (1) Free Cash Flow (“FCF”) defined as operating cash flow before changes in working capital less cash CAPEX. Reinvestment rate defined as cash CAPEX divided by pre-dividend cash flow from operations before changes in working capital. See slides 8-9 for more detail. (2) Well costs assume gross Rattler costs. Please see note 4 on slide 6 for more detail. Q4 2020 Highlights 2021 Investment Framework ◆ Current plan focused on maintaining pro forma Q4 2020 oil production through 2021; implies 3% increase to Q4 2020 run-rate oil production for 22% less capital than standalone 2020 plan ◆ Expect to generate over $625 million of pre-dividend Free Cash Flow in 2021, with a reinvestment rate of ~70%, assuming $40/Bbl WTI oil prices(1) ◆ Increased annual cash dividend to $1.60 / share; up 7% from $1.50 / share previously ◆ Free Cash Flow in excess of dividend expected to be used for debt reduction ◆ Committed to reducing Scope 1 GHG intensity by at least 50% from 2019 levels by 2024 ◆ Committed to reducing methane intensity by at least 70% from 2019 levels by 2024 ◆ "Net Zero Now": As of January 1, 2021, every hydrocarbon molecule produced by Diamondback is anticipated to be produced with zero net Scope 1 emissions ESG Initiatives
6 $4.28 $3.89 $153 $242 $0.375 $0.400 $281 $226 400 421 170 176 $1,093 $930 - $1,030 $700 - $850 FY 2019A FY 2020 Guidance 2H 2020 FY 2021 Guidance $738 $600 - $670 $510 - $530 FY 2019A FY 2020 Guidance 2H 2020 FY 2021 Guidance Net Lateral Feet TIL Net Ft. (1,000’s) Oil Production Net Mbo/d Fourth Quarter 2020 Execution Source: Company data, filings and estimates. (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) Free cash flow calculated as operating cash flow before changes in working capital and dividends, less cash CAPEX for D,C&E, non-operated properties and workovers, midstream, infrastructure and environmental; excludes long-haul pipeline investments. (3) Controllable cash casts defined as the sum of lease operating expense and cash G&A expenses. (4) 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. Q4 2020 Execution Quarterly Dividend $ / Share Free Cash Flow $MM(2) Cash CAPEX $MM(1) Controllable Cash Costs $ / Boe(3) Q3 2020 Q4 2020 Gross Midland Basin D,C&E Well Costs ($ / Ft.)(4) Gross Delaware Basin D,C&E Well Costs ($ / Ft.)(4) 2021 Guidance: $720 - $800 / Ft. 2021 Guidance: $520 - $580 / Ft.
7 1,968 1,656 $1,859 $1,450 Capital Budget $MM(1) $1.50 $1.60 $162 $625+ 181 182 ~flat 93 58 32 25 208 190 80 15 41 35 171 225 Q1 2020 Q2 2020 Q3 2020 Q4 2020 FY 2020 FY 2021E Drilled Wells Completed Wells 1,668 2,081 180.8 Mbo/d 175.8 Mbo/d 170 - 175 Mbo/d Guidon 178 – 185 Mbo/d TIL Lateral Feet Net Ft. (1,000’s) 2021 Production and Activity Outlook Oil Production Net Mbo/d Overview of 2021 Guidance and Capital Budget Source: Company data, filings and estimates. (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) Free cash flow calculated as operating cash flow before changes in working capital and dividends, less cash CAPEX for D,C&E, non-operated properties and workovers, midstream, infrastructure and environmental; excludes long-haul pipeline investments. See slides 8-9 for more detail. 215 – 235 Gross operated wells TIL 180 – 200 Gross operated wells drilled 75% Midland Basin net lateral ft. 2021 Activity and Guidance Midpoints vs 2020 2021 Gross Operated Activity Summary (Guidance Midpoint) Free Cash Flow $40 / Bbl WTI; $MM(2) FY 2021 Guidance Mbo/d 2020A Q4 2020A 2020A Initial 2021 Guidance 2021 plan focused on maintaining pro forma Q4 2020 oil production Annual Dividend $ / Share Drilled Lateral Feet Net Ft. (1,000’s)
8 $625+ $850+ $975+ $1,075+ $1,175+ 0.0% 4.0% 8.0% 12.0% 16.0% 20.0% $0 $250 $500 $750 $1,000 $1,250 $40 / Bbl $45 / Bbl $50 / Bbl $55 / Bbl $60 / Bbl F C F Y ie ld ( % )( 3 ) F re e C a sh F lo w ( $ M M ) Base Dividend Debt Reduction / Minority Interest Distributions FCF Yield (EV) FCF Yield (Market Cap) Source: Company data, filings and estimates. Note: All 2021E scenarios incorporate identical activity levels, capital spending, production, respectively; assumes current cash operating costs, well costs and incorporate current hedges. (1) Free cash flow defined as operating cash flow before changes in working capital less cash CAPEX (defined below). (2) Defined as capital spending for operated D,C&E, non-operated properties and capital workovers, midstream and infrastructure; excludes long-haul pipeline investments and acquisitions. (3) Free cash flow yield calculated as free cash flow divided by FANG’s enterprise value (“EV”) and FANG’s market capitalization (“Market Cap”) as of 2/19/2021, respectively. 2021 Free Cash Flow Sensitivity Illustrative 2021E Consolidated Free Cash Flow at Various WTI Oil Prices ($MM)(1) ◆ Diamondback believes it can maintain Q4 2020 oil production (pro forma for the pending Guidon acquisition) with estimated cash CAPEX of $1.35 - $1.55 billion in 2021; implies 22% decrease relative to standalone CAPEX for 2020 ◆ Diamondback expects to generate over $625 million of pre-dividend free cash flow at $40/Bbl WTI ◆ Protecting dividend and maintenance capital with forward expected cash flow remains capital allocation priority, with any potential tailwinds from increasing commodity prices to be used for debt reduction ~95% % of WTI Realized ($/Bbl) $1.35 - $1.55 billion Cash CAPEX(2) 178 - 185 Mbo/d Oil Production $11/Bbl / $2/Mcf Unhedged NGL / Gas Prices FY 2021 Assumptions $1.60 / Share Annual Shareholder Dividend
9 105% 92% 107% 101% 92% 48% 2016 2017 2018 2019 2020 Q4 2020 R e in v e st m e n t R a te ( % ) $55/Bbl $50/Bbl $45/Bbl $40/Bbl $35/Bbl Source: Company data, filings and estimates. Note: All 2021E scenarios incorporate identical activity levels, capital spending, production, respectively; assumes current cash operating costs, well costs and incorporate current hedges. (1) Reinvestment rate calculated as cash CAPEX (defined below) divided by pre-dividend cash flow from operations before changes in working capital. See slide 8 for additional detail. Diamondback Investment Framework ◆ Diamondback has the size, scale, balance sheet, asset quality and cost structure to weather a prolonged downturn and thrive in the inevitable upcycle ◆ Diamondback's investment framework and capital allocation philosophy at current oil prices remains very simple: protect and consistently grow our base dividend, spend maintenance capital to hold oil production flat, and use excess Free Cash Flow to pay down debt ◆ Recent commodity price strengthening does not change this capital allocation framework Historical and Future Reinvestment Rates (%)(1) $55 / Bbl $35 / Bbl Protect Dividend Debt Reduction Dividend Growth Additional Return of Capital Investment Framework WTI Oil Price: ~55% ~70% ~80% 2021E
10 Diamondback Acquiring Tier-1 Assets in the Northern Midland Basin Source: Management estimates, Company filings and Bloomberg; market data as of 12/18/2020. (1) Expected to close shortly following the special meeting of QEP stockholders scheduled for 3/16/2021, subject to QEP stockholder approval. (2) Represents PV-10 over the life of QEP’s production as of 12/18/2020. ◆ Logical, disciplined Midland Basin consolidation of assets with a largely overlapping footprint ◆ Diamondback to deploy its low cost structure and investment grade balance sheet on Tier-1 assets ◆ Further enhances Diamondback’s value proposition of consistent free cash flow generation, balance sheet strength and return of capital to shareholders ◆ Accretive across all relevant cash flow and return metrics before synergies ($60 - $80 million per year; PV-10 value of ~$500 - $700MM)(2) ◊ G&A savings ◊ Cash savings on reduced interest expense on refinanced / repaid QEP debt ◊ Improved in-field operating costs ◊ Optimized development, longer laterals ◊ QEP’s significant midstream assets ◊ Potential divestment of Williston Basin, with potential sale proceeds to be used towards debt reduction, or harvest for cash flow Key HighlightsSummary of Transactions QEP ◆ 100% stock-for-stock merger ◆ 12.27 MM FANG shares issued to QEP shareholders (0.05x exchange ratio) ◆ Implied value of $2.29 per QEP share Consideration Transaction Size ◆ At least $60 - $80 million per year Announced Synergies ◆ $2.15 billion at announcement ◆ Expected to close in late Q1 2021(1)Timing Guidon ◆ 10.63 MM FANG shares issued to the seller ◆ $375 million cash ◆ Cash component expected to be funded through a combination of cash on hand and revolver borrowings Consideration Transaction Size ◆ $862 million at announcement ◆ Expected to close February 26, 2021Timing Diamondback has entered into definitive agreements to acquire QEP and assets from Guidon, adding over 81,500 net acres in the Northern Midland Basin
11 42% Increase in Midland Basin Acreage Net Permian Acres (‘000s)(1) Summary of QEP and Guidon Midland Basin Assets Source: Company data, filings, and estimates and Enverus. (1) Based on Q3 2020 actual production. (2) QEP total production includes Williston production. Midland Basin Acreage Overview FANG QEP GUIDON Midland 56% Delaware 44% Total Net Permian Acres: 347k Total Net Permian Acres: 429k Midland 64% Delaware 36% Status Quo Pro Forma Key Asset Statistics QEP Guidon Net Permian Acres 49,064 ~32,500 Permian Production (Mboe/d) (1) 48 18 Permian Oil Production (Mbo/d) (1) 30 12 Total Production (Mboe/d) (2) 77 18
12 Greenhouse Gas (“GHG”) Emissions Reduction Targets Short-term Incentive Compensation (“STI”) ◆ Diamondback recently announced significant changes to environmental, social and governance ("ESG") performance and disclosure, including Scope 1 and methane emissions intensity reduction targets as well as a commitment to Scope 1 carbon emission neutrality, or "Net Zero Now" ◆ Carbon emissions are seen as a “cost” at Diamondback, and we expect to become the low-cost carbon operator as well as the leader in operating and capital costs Environmental Strategy Update Source: Company data and filings. ◆ Reduce Scope 1 GHG intensity by at least 50% from 2019 levels by 2024 ◆ Reduce methane intensity by at least 70% from 2019 levels by 2024 ◆ Increase ESG component weighting to 20% from 15% currently ◊ Component to be determined by meeting or exceeding the same key environmental and safety metrics as 2020: flaring intensity, GHG intensity, recycled water percentage, fluid spill control and TRIR (safety) ◊ Thresholds will all meet or exceed 2020 actual performance Recent and Planned Changes to Environmental Strategy “Net Zero Now” ◆ As of January 1, 2021, every hydrocarbon produced by Diamondback is anticipated to be produced with zero net Scope 1 emissions ◊ Recognizing the Company will still have a carbon footprint, Diamondback will purchase carbon offset credits to offset remaining emissions ◊ Intend to eventually invest in income-generating projects that will more directly offset remaining Scope 1 emissions
13 Equipment Leaks 0% Gas Pneumatic Devices 7% Combustion Equipment 11% Atmospheric Storage Tanks 30% Flare Stacks 52% Diamondback is committed to reducing its Scope 1 GHG intensity by at least 50% from 2019 levels by 2024 Source: Company data, filings and estimates. (1) Represents flaring metric for YTD 2021 as of 2/12/2021. CO2e Emissions Breakdown and Strategic Reduction Initiatives Diamondback 2019 CO2e Emissions Detail and Strategic Initiatives: 2019 Scope 1 GHG Emissions: ~1.4 million tons of CO2e Intensity: 13.75 mt / net boe produced Flare Stacks: ~52% of CO2E emissions Drivers: flaring at the wellhead due to excess gas volumes or midstream constraints Initiatives: Minimize flaring; currently at ~0.5% of gross gas produced(1); down ~87% from ~5.7% in 2019 Gas Pneumatic Devices: ~7% of CO2e emissions Drivers: 883 tank batteries at FANG today; legacy batteries run off natural gas pneumatic systems Initiatives: Air pneumatics have been installed on new batteries for last four years; plan to spend ~$50-$70 million over next four years to retrofit all batteries with air pneumatics Atmospheric Storage Tanks: ~30% of CO2e emissions Drivers: encompasses tanks at all batteries; dependent on number of tanks and volume moving through facilities Initiatives: exploring tankless facility designs; minimize number of tanks Combustion Equipment: ~11% of CO2e emissions Drivers: encompasses all drilling rigs, completion crews, workover rigs, generators and compressors Initiatives: Electrification; minimize generator use and identify compressors to electrify, maximize electricity use for D&C operations Equipment Leaks: Negligible CO2e emissions Initiatives: Aerial monitoring and FLIR cameras; now conducting quarterly flyovers of all batteries and continuing to increase number of FLIR cameras, while implementing best practices to monitor methane leaks
14 Gas Pneumatic Devices 50%Flare Stacks 38% Equipment Leaks 7% Atmospheric Storage Tanks 5% Diamondback is committed to reducing its methane intensity by at least 70% from 2019 levels by 2024 Methane Emissions and Strategic Reduction Initiatives Diamondback 2019 Methane Emissions Detail and Strategic Initiatives: Atmospheric Storage Tanks: ~5% of methane emissions Drivers: encompasses tanks at all batteries; dependent on number of tanks and volume moving through facilities Initiatives: exploring tankless facility designs; minimize number of tanks 2019 Methane Emissions: 7,145 tons of methane 0.25% methane intensity Source: Company data, filings and estimates. (1) Represents flaring metric for YTD 2021 as of 2/12/2021. Flare Stacks: ~38% of methane emissions Drivers: flaring at the wellhead due to excess gas volumes or midstream constraints Initiatives: Minimize flaring; currently at ~0.5% of gross gas produced(1); down ~87% from ~5.7% in 2019 Flare stacks rated to 98% destruction efficiency; reducing flaring directly reduces methane emissions from flaring Gas Pneumatic Devices: ~50% of methane emissions Drivers: 883 tank batteries at FANG currently; legacy batteries run off gas pneumatic systems Initiatives: Air pneumatics have been installed on new batteries for last four years; plan to spend ~$50-$70 million over next four years to retrofit all batteries with air pneumatics Equipment Leaks: ~7% of methane emissions Initiatives: Aerial monitoring and FLIR cameras; now conducting quarterly flyovers of all batteries and continuing to increase number of FLIR cameras, while implementing best practices to monitor methane leaks
15 68% 67% 59% 55% 55% 52% 51% 47% 44% 42% 0% 20% 40% 60% 80% 100% FANG 4Q20 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 % o f R e a li ze d P ri ce (% ) Cash Margin LOE Prod. taxes G&T Cash G&A Interest $12.51 $12.76 $11.63 $10.66 $11.51 $8.84 $8.85 $9.55 $9.90 $10.50 $10.34 $10.36 $9.95 $10.59 $10.14 $10.17 $10.16 $8.16 $9.62 $8.69 0 65 130 195 260 325 $0 $3 $6 $9 $12 $15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 3Q20 4Q20 P ro d u ct io n ( M b o e /d ) $ /B o e LOE Prod. taxes G&T Cash G&A Interest Mboe/d Peer-Leading Cash Margins and Operating Costs Source: Company data and latest peer filings as of 2/19/2021. Extended peers include PXD, CLR, EOG, XEC, APA, OVV, MRO, DVN and HES. (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. (2) Unhedged cash margins calculated as the sum of unhedged realized price per boe less cash operating costs including interest divided by unhedged realized price per boe. Peer leading cash operating costs and a low interest burden allow Diamondback to maintain high cash margins in any commodity price environment Diamondback Cash Operating Costs Including Interest Over Time ($ / Boe)(1) Cash Margins and Operating Costs versus Extended Peer Group (% of Unhedged Realized Price)(1)(2)
16 53 94 131 174 297 929 1,039 1,217 64 113 157 205 335 992 1,128 1,316 YE13 YE14 YE15 YE16 YE17 YE18 YE19 YE20 FANG Standalone VNOM Oil 58% NGL 22% Natural Gas 20% PD 62% PUD 38% ($/Boe) 2017 2018 2019 2020 Proved Developed F&D(1) $9.09 $10.44 $10.87 $9.65 Drill Bit F&D(2) $7.22 $7.28 $11.11 $5.00 Reserve Replacement(3) 549% 1,479% 231% 272% Organic Reserve Replacement(4) 443% 457% 250% 269% 2020 Reserves Update Total Reserve Growth (MMBoe) 1,316 MMBOE ◆ YE20 proved reserves increased 17% y/y to 1,316 MMBoe (759 MMBo, 62% PDP) ◆ PDP reserves of 817 MMBoe; PDP oil reserves of 443 MMBo ◆ Oil comprised 58% of total proved reserves on 3- stream basis; ~64% of total on 2-stream basis ◆ Consolidated proved developed F&D for 2020 was $9.65/boe with drill bit F&D of $5.00 1P Reserves – By Commodity 1P Reserves – By Category 1,316 MMBOE F&D Costs Source: Company Filings, Management Data and Estimates. (1) PD F&D costs defined as exploration and development costs divided by the sum of reserves associated with transfers from proved undeveloped reserves at YE2019 including any associated revisions in 2020 and extensions and discoveries placed on production during 2020. (2) Drill bit F&D costs defined as the exploration and development costs divided by the sum of extensions, discoveries and recoveries. (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.
17 162 134 109 89 93 18$38.20 $38.69 $38.97 $39.23 $45.00 $46.82 $47.49 $47.46 $48.28 $61.35 $30 $40 $50 $60 $70 0 50 100 150 200 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021 Q1 2022 W e ig h te d A v e ra g e H e d g e P ri ce ( $ /B b l) C o n so li d a te d V o lu m e s H e d g e d ( M b o /d ) Brent WTI MEH Unhedged Oil Downside Protection Price Upside Participation Price Strip ◆ Current oil hedges provide downside protection on >55% of expected FY 2021 oil production(1), with percentage protected declining through Q1 2022 ◆ Strategy focused on maximizing downside protection and securing cash flow to protect dividend, spend maintenance capital and reduce debt ◆ Diamondback will continue to add hedges, primarily in the form of two-way collars, that have put prices that protect its dividend and keep leverage metrics manageable Source: Company data, filings and estimates and Bloomberg as of 2/19/2021. (1) Based on FY 2021 production guidance of 178 – 185 Mbo/d. (2) Excludes basis / roll swaps and short puts, and any hedges that may be assumed in the pending QEP transaction. See slides 23-24 for additional detail. Current Hedges Maximize Downside Protection Consolidated Oil Hedges (Mbo/d)(2)
18 Oil Takeaway Solutions Gatherers: Rattler, EPD, Plains, OMOG JV Purchasers: Trafigura, Vitol Long Haul: Cactus II and EPIC API Gravity: 38°-40° Gatherers: Rattler, Oryx Purchaser: Vitol Long Haul: Gray Oak API Gravity: 40°-43° Gatherer: OMOG (RTLR JV) Purchaser: Vitol Long Haul: EPIC API Gravity: 38° - 40° Gatherer: Plains Purchaser: Plains Long Haul: WTW API Gravity: 38°-40° Gatherer: Plains Purchaser: Plains Long Haul: WTW API Gravity: 44°-47° Gatherer: Nustar Purchaser: Shell Long Haul: EPIC API Gravity: 38°-40° Gatherers: Rattler, Plains Purchaser: Plains Long Haul: WTW API Gravity: 38°-41° 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-term agreements 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 with the in-service date of the Wink to Webster pipeline Oil Takeaway Solutions 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. Oil Exposure and Expected Differentials Diamondback Exposure (Benchmark) Estimated Deduct ($ / Bbl) 2021E Production (%) Brent $5.00 - $6.00 ~60% MEH $4.00 - $5.00 ~15% WTI Midland $1.00 - $2.00 ~25%
19 $800 $0 $500 $191 $43 $1,000 $1,800 $800 $480 $100 $1,200 $0 $500 $1,000 $1,500 $2,000 $2,500 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 FANG’s Debt Maturity Profile ($MM) ◆ As of December 31, 2020, FANG had ~$23 million of outstanding borrowings under its credit facility with standalone liquidity of over $2.0 billion(1) ◆ Diamondback intends to fund the remaining cash portion of the pending Guidon acquisition with cash on hand and borrowings under its credit facility ◆ Future Free Cash Flow in excess of the dividend expected to be used to reduce debt ◆ Expect to pay off $191 million of notes due September 2021 at par with expected cash on hand Capital Structure and Liquidity Source: Company Filings, Management data and Estimates. (1) Excludes Viper and Rattler. FANG Credit Facility Elected Commitment FANG’s Liquidity and Capitalization ($MM) Viper Notes 5.375%5.375% 3.250% 4.625% 3.500% 2.875% 7.130% 4.750% Rattler Notes 5.625% 12/31/2020 Cash and cash equivalents $104 FANG's Revolving Credit Facility $23 VNOM's Revolving Credit Facility 84 RTLR's Revolving Credit Facility 79 Senior Notes 5,591 DrillCo Agreement 78 Total Debt $5,855 Net Debt $5,751 12/31/2020 Cash(1) $61 Elected commitment amount 2,000 Liquidity $2,038 FANG's Consolidated Capitalization FANG's Standalone Liquidity
20 Diamondback Capex Budget ($MM) Operated D,C&E $1,070 – $1,210 Non-Operated Properties / Capital Workovers $150 – $170 Midstream (ex. long-haul pipeline investments) $60 – $80 Infrastructure and Environmental $70 – $90 Total 2021 Capital Budget $1,350 – $1,550 Gross (net) horizontal wells drilled 180 – 200 (156 – 172) Gross (net) horizontal wells completed 215 – 235 (197 – 215) Average lateral length (ft.) ~10,100’ Midland Basin well costs per lateral foot(2) $520 – $580 Delaware Basin well costs per lateral foot(2) $720 – $800 Midland Basin net lateral feet (%) ~75% Delaware Basin net lateral feet (%) ~25% Full year 2021 oil production guidance of 178.0 – 185.0 Mbo/d; 2021 plan aimed at maintaining Q4 production levels, pro forma for Guidon Full year 2021 CAPEX budget of $1.35 - $1.55 billion; implies 22% reduction in 2020 CAPEX Expect to complete 215 – 235 gross horizontal wells with an average lateral length of ~10,100 feet Current guidance includes pending Guidon acquisition expected to close on 2/26/2021; excludes announced acquisition of QEP(1) Diamondback 2021 Capital Activity Guidance Diamondback Viper Net Production – Mboe/d 308.0 – 325.0 24.50 – 26.50 Oil Production – Mbo/d 178.0 – 185.0 14.75 – 16.00 Unit Costs ($/boe) Lease Operating Expenses $3.90 – $4.30 Gathering & Transportation $1.25 – $1.35 Cash G&A $0.45 – $0.55 $0.60 – $0.80 Non-Cash Equity Based Compensation $0.30 – $0.40 $0.10 – $0.25 D,D&A $8.75 – $10.75 $9.50 – $10.50 Interest Expense (net) $1.60 – $1.80 $3.00 – $3.50 Production and Ad Valorem Taxes (% of Revenue)(3) 7% 7% Corporate Tax Rate (% of Pre-tax Income) 23% Full Year 2021 Guidance: Pro Forma for Guidon Acquisition Source: Company filings, management data and estimates. (1) QEP stockholder vote scheduled for 3/16/2021. Assuming the transaction is closed, Diamondback will subsequently provide updated FY 2021 guidance, giving effect to the QEP transaction (2) Well costs assume gross Rattler costs. Please see note 4 on slide 6 for additional detail. (3) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes. Excludes QEP
21 Return On and Return Of Capital Conservative Financial Management Strategic Acquisitions and Execution Significant Resource Potential Efficient Conversion of Resource to Cash Flow Differential Per Share Metrics and Cost Structure
22 APPENDIX
23 Current Hedge Summary: Oil Source: Company data as of 2/19/2021. Note: Excludes any hedges that may be assumed in the pending QEP transaction. (1) 1H 2022 Brent two-way collars include 18,000 Bo/d in Q1 2022. Consolidated Crude Oil Hedges (Bbl/day, $/Bbl) Crude Oil Hedges Q1 2021 Q2 2021 Q3 2021 Q4 2021 1H 2022 2H 2022 5,000 2,000 – – – – $45.46 $47.35 – – – – 5,000 5,000 5,000 5,000 – – $37.78 $37.78 $37.78 $37.78 – – 5,000 5,000 5,000 5,000 – – $41.62 $41.62 $41.62 $41.62 – – Total Oil Swaps 15,000 12,000 10,000 10,000 -- -- Costless Collars - WTI 37,000 15,000 12,000 19,000 – – Floor / Ceiling $34.95 / $45.17 $33.00 / $45.33 $32.50 / $44.59 $37.11 / $50.71 – – Costless Collars - MEH – – 5,000 – – – Floor / Ceiling – – $45.00 / $57.90 – – – Costless Collars - Brent(1) 82,000 82,000 62,000 64,000 8,950 – Floor / Ceiling $39.04 / $48.51 $39.40 / $48.84 $39.61 / $48.42 $39.78 / $48.90 $45.00 / $61.35 – Total Costless Collars 119,000 97,000 79,000 83,000 8,950 -- – – – – 5,000 5,000 – – – – $35.00 $35.00 Total Short Puts -- -- -- -- 5,000 5,000 Total Crude Oil Hedges 134,000 109,000 89,000 93,000 13,950 5,000 21,278 23,000 18,000 18,000 – – $0.79 $0.80 $0.93 $0.93 – – Total Basis Swaps 21,278 23,000 18,000 18,000 -- -- 20,611 37,000 25,000 25,000 – – $0.09 $0.19 $0.32 $0.32 – – Total Roll Swaps 20,611 37,000 25,000 25,000 -- -- Basis Swaps - WTI Roll Swaps - WTI Swaps - WTI Swaps - MEH Swaps - Brent Short Puts - Brent
24 Current Hedge Summary: Natural Gas and Natural Gas Liquids Source: Company data as of 2/19/2021. Note: Excludes any hedges that may be assumed in the pending QEP transaction. Consolidated Natural Gas Liquids Hedges (Bbl/day, $/Bbl) Consolidated Natural Gas Hedges (Mmbtu/day, $/Mmbtu) Natural Gas Hedges Q1 2021 Q2 2021 Q3 2021 Q4 2021 1H 2022 2H 2022 206,889 220,000 220,000 220,000 – – $2.66 $2.67 $2.67 $2.67 – – Total Swaps 206,889 220,000 220,000 220,000 – – 230,000 250,000 250,000 250,000 130,000 130,000 ($0.69) ($0.66) ($0.66) ($0.66) ($0.40) ($0.40) Total Basis Swaps 230,000 250,000 250,000 250,000 130,000 130,000 Swaps - Henry Hub Basis Swaps - Waha Natural Gas Liquids Hedges Q1 2021 Q2 2021 Q3 2021 Q4 2021 1H 2022 2H 2022 1,311 2,000 2,000 2,000 – – $29.40 $29.40 $29.40 $29.40 – – Total Swaps 1,311 2,000 2,000 2,000 – – Swaps - Mont Belvieu Propane
25 0.37% 0.25% 2018 2019 11.1 14.4 12.2 13.8 2016 2017 2018 2019 0.53 0.42 0.42 0.53 0.28 0.00 2018 2019 2020 0.010% 0.006% 0.006% 0.005% 2018 2019 2020 Q4 2020 5.6% 1.9%2.0% 0.7%0.9% 0.3% % of Gross Gas % of Net BOE 2019 2020 Q4 2020 0.7% 10.7% 16.9% 18.1% 2017 2018 2019 2020 Environmental, Social and Governance (“ESG”) Source: Company data and filings. Workplace Safety (TRIR / LTIR)Water Recycling (% of Produced) Water recycling up ~70% since 2018 TRIR down ~20% since 2018 Oil Spill Rate (%) Oil spills down >50% since 2018 GHG Intensity (mt / Boe Produced)Flaring (% of Production) Flaring down >80% since 2019 Goal: reduce by 50% by 2024 Methane Intensity (%) Goal: reduce by 70% by 2024
26 Long-term Incentive Compensation (“LTI”) Short-term Incentive Compensation (“STI”) ◆ 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 ◆ Recent and planned initiatives to be discussed in its upcoming proxy; expected to be filed in Q2 2021 Recent Changes to Governance and Compensation Source: Company data and filings. ◆ Chief Executive Officer's Long Term Incentive ("LTI") compensation target amount reduced by 20% from 2020 ◆ Remainder of executive team 2021 LTI compensation target amount reduced by 10% from 2020 ◆ The Company plans to add both the S&P 500 and the XOP Index as peers to the 2021 peer group ◆ No upward salary adjustments or change to STI targets for all members of the executive team ◆ 2020 STI scorecard performance to be capped at 100% target for all executives despite actual scorecard performance of 160% of target ◆ Plan to update annual metrics to include a FCF per share metric with expected 20% weighting ◆ Plan to increase ESG component weighting to 20% from 15% previously ◆ 2021 scorecard metrics expected to also include: Capital costs per lateral foot, PDP F&D costs, controllable cash costs (LOE and G&A), ROACE and ESG Recent and Planned Changes to Governance and Compensation
27 Fee Stream Midland Delaware Produced Water – Bbl/d 1,810,000 1,310,000 Sourced Water – Bbl/d 455,000 120,000 Crude Oil – Bbl/d 65,000 210,000 Natural Gas – Mcf/d -- 170,000(2) Total >2,330,000 >1,810,000 Rattler Midstream: Publicly-traded midstream subsidiary (NASDAQ: RTLR) created by Diamondback Interests fully aligned with upstream operations: ◊ Assets located in all 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 Annual Distribution: $0.80 / unit (7.8% yield)(1) Build-out of Midstream Assets Through Rattler Midstream Rattler Midstream Asset Map Spanish Trail North: ⧫ Sourced Water ⧫ Produced Water Howard County: ⧫ Sourced Water ⧫ Produced Water Spanish Trail: ⧫ Sourced Water ⧫ Produced Water ⧫ Crude Gathering Reeves / Loving: ⧫ Produced Water 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. (1) Based on Rattler’s most recent quarterly distribution announced on 11/04/2020. Yield based on RTLR’s closing price as of 2/19/2021. (2) 151,000 Mcf/d compression capacity. Rattler Capacity Overview
28 Viper Energy Partners: Publicly-traded mineral 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 24,350 net royalty acres, ~52% of which are operated by Diamondback Diamondback incentivized to focus development on Viper’s acreage when possible due to improved consolidated returns ◊ 21 of Diamondback’s 35 Q4 2020 completions on Viper’s acreage, in which Viper owned a 5.6% average NRI Q4 2020 average oil production of 17.4 Mbo/d; generated $0.28 / 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 Update Viper Mineral and Royalty Assets 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 12/31/2020. VNOM royalty acreage FANG acreage
29 Diamondback Energy Corporate Headquarters 500 West Texas Ave., Suite 1200 Midland, TX 79701 www.diamondbackenergy.com Adam Lawlis, Vice President, Investor Relations (432) 221-7400 ir@diamondbackenergy.com