Filed by Concho Resources Inc.

(Commission File No. 001-33615)

Pursuant to Rule 425 under the Securities Act of 1933, as amended

and deemed filed under Rule 14a-12 under the

Securities Exchange Act of 1934, as amended

Subject Company: RSP Permian, Inc.

(Commission File No. 001-36264)

1Q | 2018 Quarterly Update May 1, 2018

Forward-Looking Statements and Other Disclaimers No Offer or Solicitation This presentation relates to a proposed business combination transaction (the ?Transaction?) between RSP Permian, Inc. (?RSP? or ?RSPP?) and Concho Resources Inc. (?Concho? or ?CXO?). This communication is for informational purposes only and 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, in any jurisdiction, pursuant to the Transaction or otherwise, 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. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. Additional Information and Where to Find It In connection with the Transaction, Concho filed with the U.S. Securities and Exchange Commission (?SEC?) a registration statement on Form S-4 on April 20, 2018, that includes a preliminary joint proxy statement of RSP and Concho that also constitutes a preliminary prospectus of Concho. RSP and Concho will also file other documents with the SEC regarding the Transaction, including the definitive joint proxy statement/prospectus. The information in the preliminary joint proxy statement/prospectus is not complete and may be changed. The definitive joint proxy statement/prospectus will be sent to the stockholders of Concho and RSP. This document is not a substitute for the registration statement and preliminary joint proxy statement/prospectus filed with the SEC, including any amendments thereto, or any other documents that Concho or RSP may file with the SEC or send to stockholders of Concho or RSP in connection with the Transaction. INVESTORS AND SECURITY HOLDERS OF RSP AND CONCHO ARE URGED TO READ THE REGISTRATION STATEMENT, THE PRELIMINARY JOINT PROXY STATEMENT/PROSPECTUS, THE DEFINITIVE JOINT PROXY STATEMENT/PROSPECTUS WHEN IT BECOMES AVAILABLE, AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY CONTAIN OR WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS. Investors and security holders are able to obtain free copies of the registration statement and the preliminary joint proxy statement/prospectus and all other documents filed or that will be filed with the SEC by Concho or RSP, including the definitive joint proxy statement/prospectus when it becomes available, through the website maintained by the SEC at www.sec.gov. Copies of documents filed with the SEC by RSP will be made available free of charge on RSP?s website at www.rsppermian.com, under the heading ?SEC Filings,? or by contacting RSP?s Investor Relations Department by phone at 214-252-2700. Copies of documents filed with the SEC by Concho will be made available free of charge on Concho?s website at www.concho.com, under the heading ?Investors,? or by contacting Concho?s Investor Relations Department by phone at 432-221-0477. Participants in Solicitation Concho, RSP and their respective directors and executive officers may be deemed to be participants in the solicitation of proxies from the holders of Concho?s common stock and RSP?s common stock in respect to the Transaction. Information regarding RSP?s directors and executive officers is contained in the Form 10-K/A filed with the SEC on April 30, 2018 and in the other documents filed after the date thereof by RSP with the SEC. You can obtain a free copy of this document at the SEC?s website at www.sec.gov or by accessing RSP?s website at www.rsppermian.com. Information regarding Concho?s executive officers and directors is contained in the proxy statement for Concho?s 2018 Annual Meeting of Stockholders filed with the SEC on April 5, 2018 and in the other documents filed after the date thereof by Concho with the SEC. You can obtain a free copy of this document at the SEC?s website at www.sec.gov or by accessing Concho?s website at www.concho.com under the heading ?Investors.? Investors may obtain additional information regarding the interests of those persons and other persons who may be deemed participants in the Transaction by reading the preliminary joint proxy statement/prospectus, including any amendments thereto, as well as the definitive joint proxy statement/prospectus when it becomes available. You may obtain free copies of these documents as described above. Forward-Looking Statements and Cautionary Statements The foregoing contains ?forward-looking statements? within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this communication that address activities, events or developments that Concho or RSP expects, believes or anticipates will or may occur in the future are forward-looking statements. Words such as ?estimate,? ?project,? ?predict,? ?believe,? ?expect,? ?anticipate,? ?potential,? ?create,? ?intend,? ?could,? ?may,? ?foresee,? ?plan,? ?will,? ?guidance,? ?look,? ?outlook,? ?goal,? ?future,? ?assume,? ?forecast,? ?build,? ?focus,? ?work,? ?continue? or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. These forward-looking statements include, but are not limited to, statements regarding the Transaction, pro forma descriptions of the combined company and its operations, integration and transition plans, synergies, opportunities and anticipated future performance. There are a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements included in this communication. These include the expected timing and likelihood of completion of the Transaction, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Transaction that could reduce anticipated benefits or cause the parties to abandon the Transaction; the ability to successfully integrate the businesses; the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement; the possibility that stockholders of Concho may not approve the issuance of new shares of common stock in the Transaction or that stockholders of RSP may not approve the merger agreement; the risk that the parties may not be able to satisfy the conditions to the Transaction in a timely manner or at all; risks related to disruption of management time from ongoing business operations due to the Transaction; the risk that any announcements relating to the Transaction could have adverse effects on the market price of Concho?s common stock or RSP?s common stock; the risk that the Transaction and its announcement could have an adverse effect on the ability of Concho and RSP to retain customers and retain and hire key personnel and maintain relationships with their suppliers and customers and on their operating results and businesses generally; the risk the pending Transaction could distract management of both entities and they will incur substantial costs; the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; the risk that the combined company may be unable to achieve synergies or it may take longer than expected to achieve those synergies and other important factors that could cause actual results to differ materially from those projected. 2

Forward-Looking Statements and Other Disclaimers (cont.) Forward-Looking Statements and Cautionary Statements (cont.) All such factors are difficult to predict and are beyond Concho?s or RSP?s control, including those detailed in Concho?s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on its website at http://www.concho.com and on the SEC?s website at http://www.sec.gov, and those detailed in RSP?s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on RSP?s website at http://www.rsppermian.com and on the SEC?s website at http://www.sec.gov. All forward-looking statements are based on assumptions that Concho or RSP believe to be reasonable but that may not prove to be accurate. Any forward-looking statement speaks only as of the date on which such statement is made, and Concho and RSP undertake 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. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (?GAAP?), including adjusted net income, adjusted earnings per share (?EPS?) and EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such measures and reconciliations of adjusted net income, adjusted EPS and EBITDAX to the nearest comparable measures in accordance with GAAP, please see the appendix. The SEC requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible?from a given date forward, from known reservoirs and under existing economic conditions (using the trailing 12-month average first-day-of-the-month prices), operating methods and government regulations?prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, the Company currently does not disclose probable or possible reserves in its SEC filings. In this presentation, proved reserves attributable to the Company at December 31, 2017 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $47.79 per Bbl of oil and $2.98 per MMBtu of natural gas. The Company?s estimate of its total proved reserves at December 31, 2017 is based on reports prepared by Cawley, Gillespie & Associates, Inc. and Netherland, Sewell & Associates, Inc., independent petroleum engineers. The Company may use the terms ?unproved reserves,? ?resources? and similar phrases to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These are based on analogy to the Company?s existing models applied to additional acres, additional zones and tighter spacing and are the Company?s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute ?reserves? within the meaning of the Society of Petroleum Engineer?s Petroleum Resource Management System or SEC rules. Such estimates and identified drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from the Company?s interests could differ substantially from these estimates. There is no commitment by the Company to drill all of the drilling locations that have been attributed to these quantities. Factors affecting ultimate recovery include the scope of the Company?s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. Such estimates may change significantly as development of the Company?s oil and natural gas assets provide additional data. The Company?s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases or other factors that are beyond the Company?s control. Cautionary Statements Regarding Resource Concho may use the term ?resource potential? and similar phrases to describe estimates of potentially recoverable hydrocarbons that SEC rules prohibit from being included in filings with the SEC. These are based on analogy to Concho?s existing models applied to additional acres, additional zones and tighter spacing and are Concho?s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute ?reserves? within the meaning of the Society of Petroleum Engineer?s Petroleum Resource Management System or SEC rules. Such estimates and identified drilling locations have not been fully risked by Concho management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that may be ultimately recovered from Concho?s interests could differ substantially from these estimates. There is no commitment by Concho to drill all of the drilling locations that have been attributed to these quantities. Factors affecting ultimate recovery include the scope of Concho?s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. Such estimates may change significantly as development of Concho?s oil and natural gas assets provide additional data. Concho?s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases or other factors that are beyond Concho?s control. Concho?s use of the term ?premium resource? refers to assets with the capacity to produce at an internal rate of return that is greater than thirty-five percent based on fifty-five dollar oil and three dollar gas. 3

Concho Resources Strong Track Record of Creating Profitable Growth The Permian Basin Competitive Advantages The Permian Basin: Our home for 30+ years Execution strength & Home-field advantage with HQ in Midland, Texas scale Superior capital efficiency Our strategy focuses on: Depth of premium drilling NEW MEXICO inventory SHELF Building a great team Peer-leading balance MIDLAND BASIN Investing in high-margin assets sheet Generating high-quality returns DELAWARE BASIN Maintaining a strong balance sheet Our key levers for efficient growth are: Driving strong, consistent execution Prioritizing capital discipline Actively managing the portfolio Maintaining a strong financial position Executing our strategy has created a high-quality portfolio, sustainable competitive advantages and consistent outperformance 4

1Q18 Update

1Q18 Performance Concho Delivered Record Performance in 1Q18 1Q18 Highlights High-Margin Growth Production (MBoepd) Delivering Strong, Consistent Execution Oil Gas Added a record 14 MBopd quarter-over-quarter, driving an 11% increase in crude oil 228 211 production to 144 MBopd 185 193 181 Total production of 228 MBoepd exceeded 1Q18 guidance range Achieved record well performance in the Delaware Basin Prioritizing Capital Discipline and Financial Performance Net income of $835mm, or $5.58 per diluted share; adjusted net income of $149mm, or $1.00 per diluted share1 1Q17 2Q17 3Q17 4Q17 1Q18 EBITDAX of $570mm1 2018 Outlook2 Actively Managing Our Portfolio Increasing FY18 annual Announced acquisition of RSPP production growth Non-core asset sales accelerate value outlook to 18%-20% Strategic asset trades increase exposure to existing core areas Maintained FY18 capital program guidance Maintaining a Strong Balance Sheet 2Q18 production Reduced total debt by ~$320mm quarter-over-quarter guidance 226 to 230 Maintain investment grade credit ratings MBoepd At March 31, 2018, 1.2x debt-to-TTM EBITDAX1 1Adjusted net income, adjusted EPS, EBITDAX and trailing-twelve-months EBITDAX are non-GAAP measures. See appendix for reconciliation to GAAP measures. 2Outlook excludes RSPP acquisition 6

2018 Is Off to a Great Start Executing on Efficient Growth While Building for the Future Leadership Position in the Permian Basin New Mexico Shelf Consolidating the Permian Entered into agreement to acquire RSPP Enhancing Core Positions with Asset Trades Midland Basin Completed key trade with large integrated oil company to enhance Midland Basin position Executed 5 trades in 1Q18 Monetizing Non-Core Leasehold Delaware Basin Divested non-core leasehold in Ward & Reeves Counties, Texas for ~$280mm $1.4bn in divestiture proceeds to date since January 2016 Realizing Value from Strategic Midstream Investment CXO Acreage 2018 Acreage $157mm cash distribution from equity investment in Oryx Additions / Trades Oryx System Note: Concho acreage as of December 31, 2017 pro forma for transactions announced to date other than RSPP acquisition; RSPP acreage as of December 31, 2017. 7

1Q18 Operational Highlights Scaling Development to Maximize Returns & Recoveries Northern Delaware Basin Southern Delaware Basin New Mexico Shelf Added 12 horizontal wells Added 21 horizontal wells (avg. lateral length Northern Record avg. lateral length 8,544? 9,204?) 3 Delaware Midland Record avg. 30-day peak rate: 2,070 Boepd Basin Basin Record avg. 30-day peak rate: 1,993 Boepd 4 (74% oil) (73% oil) 2 1 Avg. 60-day peak rate: 1,900 Boepd Avg. 60-day peak rate: 1,787 Boepd (73% oil) (73% oil) Delineating lower 2nd Bone Spring in Eddy 5 Southern County, NM; added two wells with an avg. 30-Delaware day peak rate of 2,457 Boepd (74% oil) per well Basin 6 CXO Acreage Midland Basin Midstream Infrastructure RSPP Acreage Added 20 horizontal wells (avg. lateral length 85%+ crude oil production transported via Key Projects ? 2018 & 2019 10,156?) pipe to key intra-basin markets and primary Avg. 30-day peak rate: 1,156 Boepd long-haul lines 1 Dominator 20+ well 4 Mabee 240A 10+ well (85% oil) Strategic investments in regional gathering multi-zone project multi-zone project Avg. 60-day peak rate: 1,114 Boepd systems ensure operational continuity and (84% oil) maximize market optionality 2 Eider 10+ well 5 Windham TXL 10+ Avalon project well multi-zone project Financial risk mitigation through Midland/Cushing basis hedges through 2020 3 Little Bear 8+ well 6 Whatcha Want 6+ multi-zone project well multi-zone project Note: Concho acreage as of December 31, 2017 pro forma for transactions announced to date other than RSPP acquisition; RSPP acreage as of December 31, 2017. Note: Well results represent wells with >30 days of production data in 1Q18. 8

Prioritizing Capital Discipline Differentiated Production Growth & Free Cash Flow 228 Operating Cash Flow vs. D&C Capital ($mm) High-Quality Assets & 211 Disciplined Reinvestment Drives $70.00 Cumulative free 193 185 Free Cash Flow cash flow >$0.5bn 181 $60.00 164 153 149 144 139 145 $510 $50.00 $488 $471 $450 /Bbl) $436 ( $ $427 $407 $398 $40.00 $393 Price $370 $383 $380 $343 $351 $365 WTI $326 $306 $30.00 $301 $253 $272 $274 $236 $20.00 $10.00 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 Drilling & Completion Capital1 Cash Flow from Operations Production (MBoepd) WTI Price ($/Bbl) 1D&C capital represents exploration and development costs incurred for oil and natural gas producing activities for each quarter shown. See appendix for a summary of costs incurred. 9

2018 Capital Program Excludes RSPP 2018 Capital Program & Activity Overview CXO Long-Term Outlook Targeting midpoint of $1.9bn—$2.1bn capital program guidance1 2017-2020 ~93% for D&C activity and ~7% for other 20% total production CAGR Expect to generate 20% crude oil growth and 18%-20% total production growth within cash flow Timing of large-scale projects to drive quarterly growth trajectory Rigs and completion crews in place to execute on 2018 program Key considerations Delivers free cash flow at low-to-mid $50/Bbl WTI oil 5% 1 Efficiencies Cost inflation assumed; productivity gains 5 ~80% multi-well pads not assumed 30% D&C 40% Avg. ~65% large-scale projects Secured sand volumes and last-mile Capital FY18 Rig 10 Expect to drill ~260 gross wells logistics Allocation Count Expect to complete ~11,000 gross 6 stages ~50% of 2018 sand 25% volumes to be sourced from local Permian mines Northern Delaware Basin Midland Basin Southern Delaware Basin New Mexico Shelf Note: Large-scale projects include 4 or more wells. 1The Company?s capital program guidance excludes acquisitions and is subject to change without notice depending upon a number of factors, including commodity prices and industry conditions. 10

Strengthening Financial Position Fortified Balance Sheet Provides Significant Flexibility Long-Term Debt Profile ($mm) Key Highlights $3,350 Investment grade credit ratings Reduced total debt by ~$950mm since 2Q16 $600 7.0% due Lowered annual interest expense by ~$90mm since 2Q16 2021 $2,722 Prioritizing low leverage ratio of 1.0x-1.5x1 $322 $600 $2,400 At March 31, 2018, 1.2x debt-to-TTM EBITDAX Credit Facility 6.5% due 2022 $600 $600 4.375% due 4.375% due $600 2025 2025 5.5% due 2022 $1,000 $1,000 $320mm 3.75% due 3.75% due $1,550 2027 2027 5.5% due Reduction in total debt 2023 since 4Q17 $800 $800 4.875% due 4.875% due 2047 2047 2Q16 4Q17 1Q18 1Leverage ratio determined using total long-term debt and the non-GAAP measure EBITDAX. Trailing-twelve-months EBITDAX is a non-GAAP measure. See appendix for definition and reconciliation to GAAP measure. 11

Permian Consolidation RSP Permian Acquisition

Announced Acquisition of RSP Permian Creating the Largest Unconventional Shale Producer in the Permian Basin Transaction Overview Combined Position ~640,000 Net Acres Transaction Timing Acquiring RSPP in All-Stock Transaction for $9.5bn, Update Inclusive of RSPP?s $1.5bn of Net Debt ? CXO filed Form S-4, 0.320 shares of CXO stock per RSPP share which includes Subject to CXO and RSPP shareholder approval & regulatory preliminary proxy approvals statements for both companies, April 20, Pro Forma Ownership and Governance Delaware 2018 CXO shareholders will own ~74.5% of the combined company Basin CXO?s board will be expanded to 11 directors, including 1 ? Early termination of Hart-Scott-Rodino member of RSPP?s board granted April 27, 2018 ? SEC review Form S-4 Track Record of Consolidating Core Acreage Midland Basin ? Shareholder votes Contiguous Bolt-On to Existing Core Positions ? Anticipate transaction High working interest, operated assets closing 3Q18 Excellent reservoir quality with multiple benches Amenable to long-lateral, multi-well project development Pro Forma 4Q17 Production1 Immediately Accretive Before Synergies 211 56 267 (MBoepd) Key Value Levers Potentially Unlock ~$2bn in Synergies Net Permian Basin 550,000 92,000 642,000 Large-scale, multi-well projects Acreage Long-lateral development Gross Locations 21,000 5,000 26,000 Shared infrastructure Corporate level savings Net Resource1 (BBoe) 10.0 2.2 12.2 Note: Concho acreage as of December 31, 2017 pro forma for transactions announced to date other than RSPP acquisition; RSPP acreage as of December 31, 2017. 14Q17 production and net resource presented on a two-stream basis. 13

Increased Scale Creates Long-Term Competitive Advantage Solidified and Strengthened Leading Position in the Permian Basin Permian Rig Count 27 22 21 20 15 15 13 10 9 8 7 Market share enhances supply chain and logistics Pro rma PXD EOG CXO APA PE FANG XEC DVN APC RSPP advantages Permian Production (MBoepd)1 Financial capacity and execution strength to 267 252 maximize value across a broader portfolio 211 177 154 112 93 80 77 60 56 Pro rma PXD CXO APA EOG XEC FANG PE APC DVN RSPP Note: Rig count sourced from public filings and RigData as of 3/23/2018. Note: RSPP?s 4Q17 production presented on a two-stream basis (production sourced from public filings). 14 1Includes only Permian Basin production for 4Q17 or average quarterly production based on FY17 if 4Q17 volumes were not disclosed.

Northern Midland Basin Building a Super Block Executing our Consolidation Playbook has Built a Super Block in the Core of the Midland Basin October 2016 July 2017 February 2018 March 2018 CXO Acreage CXO Acreage CXO Acreage CXO Acreage Reliance Acquired Acquired RSPP Acreage ANDREWS ANDREWS ANDREWS ANDREWS MARTIN MARTIN MARTIN MARTIN MIDLAND MIDLAND MIDLAND MIDLAND Acquired assets from Strategically acquired Added assets in trade Announced Acquisition a private-operator bolt-on leasehold with a major integrated 120,000 gross (100,000 net)-acre block pro forma position Scalable platform for efficient manufacturing-style development Complementary leasehold drives growth synergies Note: Concho acreage as of December 31, 2017 pro forma for transactions announced to date; RSPP acreage as of December 31, 2017. 15

Operational Value Levers Expands Value Proposition for All Shareholders Key Value Levers Single-Zone Development Comparison Long-lateral development Large-scale, multi-zone Small-Scale Development Large-Scale, Long-Lateral Development projects 16 wells (8, 2-well pads); 1-mile laterals 8 wells (2, 4-well pads); 2-mile laterals Shared infrastructure 1-rig program2-rig program Unlock Significant Value Lowers capital intensity Optimizes well performance & increases resource recovery Minimizes downtime Accelerates payout Increases NPV per drilling unit 6% decrease in net investment Accelerates payout to 1.7 years from 2.8 years 75% ROR vs. 67% ROR in small-scale scenario Increases NPV by 45% Combination of large-scale, long-lateral development and corporate level savings drive $2bn of estimated transaction synergies 16

Large-Scale Development Full-Field Development Generates Strong Economic Benefits Accelerating innovation High-grading lateral Zipper completions result Shared facilities and across assets with new placement in more stages completed infrastructure reduce technology and data Walking rigs and per day above-ground costs analytics concentrated Maximizing cluster Managed flowback Benefiting from robust development reduces efficiency to promote optimizes facilities design real-time feedback loop drilling days near-wellbore complexity and investment and optimize long-term well performance 17

Key Investment Thesis Concho?s Value Proposition Executing Clear, Disciplined Capital Industry-Leading Scale Cycle-Tested Strategy Allocation and Execution Hire the best Capital spending on Drive productivity gains high-return projects Develop the best asset base Control costs Differentiated growth Rate of return driven Leverage new technology within cash flow Prioritize financial strength Mitigate efficiency risks Robust long-term outlook Capital-Efficient Platform to Deliver Long-Term Growth & Value Creation 18

Appendix

Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings per Share (Unaudited) The Company?s presentation of adjusted net income and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted earnings per share represent earnings and diluted earnings per share determined under GAAP without regard to certain non-cash and unusual items. The Company believes these measures provide useful information to analysts and investors for analysis of its operating results on a recurring, comparable basis from period to period. Adjusted net income and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with GAAP and may not be comparable to other similarly titled measures of other companies. The following table provides a reconciliation from the GAAP measure of net income to adjusted net income (non-GAAP), both in total and on a per diluted share basis, for the periods indicated: Three Months Ended March 31, (in millions, except per share amounts) 2018 2017 Net income—as reported $ 835 $ 650 Adjustments for certain non-cash and unusual items: (Gain) loss on derivatives 35 (286) Net cash receipts from (payments on) derivatives (112) 28 Leasehold abandonments 10 6 Gain on disposition of assets and other (719) (654) Gain on equity method investment distribution (103) -Tax impact 205 336 Excess tax benefit (2) (8) Adjusted net income $ 149 $ 72 Net income per diluted share—as reported $ 5.58 $ 4.37 Adjustments for certain non-cash and unusual items per diluted share: (Gain) loss on derivatives 0.23 (1.92) Net cash receipts from (payments on) derivatives (0.75) 0.18 Leasehold abandonments 0.07 0.04 Gain on disposition of assets and other (4.80) (4.40) Gain on equity method investment distribution (0.69) -Tax impact 1.37 2.27 Excess tax benefit (0.01) (0.05) Adjusted net income per diluted share $ 1.00 $ 0.49 Adjusted earnings per share: Basic net income $ 1.00 $ 0.49 Diluted net income $ 1.00 $ 0.49 20

Reconciliation of Net Income to EBITDAX (Unaudited) EBITDAX (as defined below) is presented herein and reconciled from the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator. The Company defines EBITDAX as net income, plus (1) exploration and abandonments expense, (2) depreciation, depletion and amortization expense, (3) accretion of discount on asset retirement obligations expense, (4) non-cash stock-based compensation expense, (5) (gain) loss on derivatives, (6) net cash receipts from (payments on) derivatives, (7) gain on disposition of assets, net, (8) interest expense, (9) gain on equity method investment distribution and (10) federal and state income tax expense (benefit). EBITDAX is not a measure of net income or cash flows as determined by GAAP. The Company?s EBITDAX measure provides additional information which may be used to better understand the Company?s operations. EBITDAX is one of several metrics that the Company uses as a supplemental financial measurement in the evaluation of its business and should not be considered as an alternative to, or more meaningful than, net income as an indicator of operating performance. Certain items excluded from EBITDAX 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 cost of depreciable and depletable assets. EBITDAX, as used by the Company, may not be comparable to similarly titled measures reported by other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and is one of many metrics used by the Company?s management team and by other users of the Company?s consolidated financial statements. For example, EBITDAX can be used to assess the Company?s operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure, and to assess the financial performance of the Company?s assets and the Company without regard to capital structure or historical cost basis. The following table provides a reconciliation of the GAAP measure of net income to EBITDAX (non-GAAP) for the periods indicated: Three Months Ended Twelve Months Ended March 31, March 31, (in millions) 2018 2017 2018 Net Income $ 835 $ 650 $ 1,141 Exploration and abandonments 18 15 62 Depreciation, depletion and amortization 317 283 1,180 Accretion of discount on asset retirement obligations 2 2 8 Non-cash stock-based compensation 17 12 65 (Gain) loss on derivatives 35 (286) 447 Net cash receipts from (payments on) derivatives (112) 28 (61) Gain on disposition of assets, net (723) (654) (747) Interest expense 30 40 136 Loss on extinguishment of debt — —66 Gain on equity method investment distribution (103) —(103) Income tax expense (benefit) 254 371 (192) EBITDAX $ 570 $ 461 $ 2,002 21

Reconciliation of Net Cash Provided by Operating Activities to EBITDAX (Unaudited) EBITDAX is presented herein and reconciled to the GAAP measure of net cash provided by operating activities because the Company believes EBITDAX is a widely accepted financial indicator of a company?s ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. EBITDAX should not be considered an alternative to net cash provided by operating activities, as defined by GAAP. The following table provides a reconciliation of the GAAP measure of net cash provided by operating activities to EBITDAX (non-GAAP) for the period presented: Twelve Months Ended March 31, (in millions) 2018 Net cash provided by operating activities $ 1,776 Exploration and abandonments 31 Cash income tax benefit (12) Interest expense 136 Changes in working capital 76 Other (5) EBITDAX $ 2,002

Costs Incurred (Unaudited) The following table summarizes costs incurred for oil and natural gas producing activities for the periods indicated: (in millions) Three Months Ended March 31, December 31, September 30, June 30, March 31, December 31, September 30, June 30, March 31, December 31, September 30, 2018 2017 2017 2017 2017 2016 2016 2016 2016 2015 2015 Property Acquisition Costs: Proved $ — $ 2 $ 162 $ 12 $ 127 $ 725 $ 1 $ 4 $ 252 $ (2) $ 57 Unproved 13 40 472 87 306 982 14 19 139 10 162 Exploration 243 296 252 238 235 189 177 165 170 149 202 Development 207 175 175 145 158 162 97 107 83 87 99 Total Costs Incurred $ 463 $ 513 $ 1,061 $ 482 $ 826 $ 2,058 $ 289 $ 295 $ 644 $ 244 $ 520 23

Hedge Position The table below provides data associated with the Company?s derivatives at May 1, 2018, for the periods indicated: REMAINING 2018 OIL HEDGES 2018 2019 2020 112 MBopd Second Third Fourth Total Total Total Oil Price Swaps1: Volume (Bbl) 11,453,170 10,155,318 9,075,007 30,683,495 30,011,500 10,228,000 Price per Bbl $ 54.50 $ 54.29 $ 53.73 $ 54.20 $ 53.49 $ 55.24 Oil Basis Swaps2: Volume (Bbl) 9,492,000 8,465,000 7,757,000 25,714,000 28,619,500 10,980,000 Price per Bbl $ (0. 81) $ (0. 85) $ (0. 89) $ (0. 85) $ (1. 17) $ (0. 08) Natural Gas Price Swaps3: Volume (MMBtu) 18,179,000 19,420,000 18,458,000 56,057,000 28,790,992 7,320,000 Price per MMBtu $ 3. 03 $ 3. 01 $ 3. 00 $ 3. 01 $ 2. 81 $ 2. 70 Updated as of May 1, 2018 1 The index prices for the oil price swaps are based on the New York Mercantile Exchange (NYMEX) ? West Texas Intermediate (WTI) monthly average futures price. 2 The basis differential price is between Midland ? WTI and Cushing ? WTI. 24 3 The index prices for the natural gas price swaps are based on the NYMEX ? Henry Hub last trading day futures price.

2018 Operational & Financial Outlook Excludes RSPP 2018 2Q18 Production Guidance Guidance Production 226 to 230 MBoepd Total production growth 18%—20% Crude oil production growth 20% Price realizations, excluding commodity derivatives Crude oil (per Bbl) (Relative to NYMEX—WTI) ($1.50)—($2.00) FY18 Crude Oil Price Realization Natural gas (per Mcf) (% of NYMEX—Henry Hub) 90%—100% Updated guidance of ($1.50) ? ($2.00) Operating costs and expenses ($ per Boe, unless noted) excludes regional Midland-Cushing price Lease operating expense and workover costs $6.00—$6.50 Gathering, processing and transportation differential $0.50—$0.60 Oil and natural gas taxes (% of oil & natural gas revenues) 7.75% Basis hedges protect against widening General and administrative (“G&A”) expense: of Midland-Cushing differential Cash G&A expense $2.50—$2.80 Balance of 2018: Midland-Cushing basis Non-cash stock-based compensation $0.80—$1.00 hedges cover 25.7 MMBo at ($0.85) per Bbl DD&A $15.00—$16.00 2019 & 2020 Midland-Cushing basis hedges Exploration and other $0.25—$0.75 summarized on page 24 Interest expense ($mm): Cash $110—$120 Non-cash $6 Income tax rate (%) 25% Capital program ($bn)1 $1.9—$2.1 2018 Operational & Financial Outlook Updated as of May 1, 2018 1 The Company?s capital program guidance for 2018 is subject to change without notice depending upon a number of factors, including commodity prices and industry conditions. 25