CONCHO RESOURCES INC.d18rn0p25nwr6d.cloudfront.net/CIK-0001358071/7981f5f6-b... · 2018. 12....

UNITED STATESSECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A(Amendment No. 1)

CURRENT REPORTPursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934Date of report (Date of earliest event reported): December 28, 2018 (July 19, 2018)

Concho Resources Inc.(Exact Name of Registrant as Specified in Its Charter)

Delaware 001-33615 76-0818600

(State or Other Jurisdictionof Incorporation)

(CommissionFile Number)

(I.R.S. EmployerIdentification No.)

One Concho Center

600 W. Illinois Avenue Midland, Texas 79701

(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code: (432) 683-7443

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of thefollowing provisions (see General Instruction A.2. below):

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405) orRule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Introductory Note.

As reported in the Current Report on Form 8-K filed with the Securities and Exchange Commission by Concho Resources Inc. (the “Company”) on July 19,2018 (the “Original Form 8-K”), on July 19, 2018, the Company completed the acquisition of RSP Permian, Inc. (“RSP”), whereby Green Merger Sub Inc.,a wholly-owned subsidiary of the Company, merged with and into RSP, with RSP continuing as the surviving corporation and a wholly-owned subsidiary ofthe Company (the “Merger”).

This Current Report on Form 8-K/A (this “Amendment”) amends and supplements the Original Form 8-K to provide the following:

• the unaudited consolidated financial statements of RSP for the period described in Item 9.01(a) below and the notes related thereto; and

• the unaudited pro forma consolidated and combined financial information described in Item 9.01(b) below.

No other modifications to the Original Form 8-K are being made by this Amendment. This Amendment should be read in connection with the OriginalForm 8-K, which provides a more complete description of the Merger.

Item 9.01 Financial Statements and Exhibits.

(a)FinancialStatements

The unaudited consolidated balance sheets of RSP as of June 30, 2018 and December 31, 2017, the consolidated statements of operations and consolidatedstatements of changes in stockholders’ equity of RSP for the three and six months ended June 30, 2018 and 2017 and the consolidated statements of cashflows of RSP for the six months ended June 30, 2018 and 2017, and the notes related thereto, are included as Exhibit 99.1 to this Current Report and areincorporated by reference into this Item 9.01(a).

(b)ProFormaFinancialInformation

The unaudited pro forma combined statements of operations of the Company for the year ended December 31, 2017 and the six months ended June 30, 2018gives effect to the Merger as if it had been consummated on January 1, 2017. The unaudited pro forma combined balance sheet of the Company as ofJune 30, 2018 gives effect to the Merger as if it had been consummated on June 30, 2018. These statements, and the notes related thereto, are included asExhibit 99.2 to this Current Report and are incorporated by reference into this Item 9.01(b).

(d)Exhibits Exhibit Number Description

99.1

The unaudited consolidated balance sheets of RSP as of June 30, 2018 and December 31, 2017 and the consolidated statements ofoperations and consolidated statements of changes in stockholders’ equity of RSP for the three and six months ended June 30, 2018 and2017 and the consolidated statements of cash flows of RSP for the six months ended June 30, 2018 and 2017, and the notes related thereto.

99.2

The unaudited pro forma combined statements of operations of the Company for the year ended December 31, 2017 and six months endedJune 30, 2018, and the unaudited pro forma combined balance sheet of the Company as of June 30, 2018.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersignedhereunto duly authorized.

CONCHO RESOURCES INC.

Date: December 28, 2018 By: /s/ Brenda R. Schroer Name: Brenda R. Schroer

Title:

Senior Vice President, Chief Accounting Officer andTreasurer

Exhibit 99.1

RSP PERMIAN, INC.CONSOLIDATED BALANCE SHEETS

(Unaudited) (in thousands, except share data) June 30, 2018 December 31, 2017

ASSETS CURRENT ASSETS Cash and cash equivalents $ 86,944 $ 38,102 Accounts receivable 115,906 111,157 Derivative instruments 81,915 64

Total current assets 284,765 149,323 PROPERTY, PLANT AND EQUIPMENT Oil and natural gas properties, successful efforts method 7,326,310 6,802,517 Accumulated depletion (940,083) (778,596)

Total oil and natural gas properties, net 6,386,227 6,023,921 Other property and equipment, net 55,644 56,798

Total property, plant and equipment 6,441,871 6,080,719 OTHER LONG-TERM ASSETS Derivative instruments 9,240 37 Other long-term assets 40,409 40,107

Total other long-term assets 49,649 40,144

TOTAL ASSETS $ 6,776,285 $ 6,270,186

LIABILITIES AND STOCKHOLDERS’ EQUITY CURRENT LIABILITIES Accounts payable $ 28,759 $ 26,758 Accrued expenses 148,553 119,439 Interest payable 24,171 23,798 Derivative instruments 90,898 36,566

Total current liabilities 292,381 206,561 LONG-TERM LIABILITIES Derivative instruments 20,109 5,722 Long-term debt 1,675,392 1,509,128 Deferred taxes 258,072 210,568 Other long-term liabilities 17,549 15,849

Total long-term liabilities 1,971,122 1,741,267

Total liabilities 2,263,503 1,947,828 STOCKHOLDERS ’ EQUITY Common stock, $.01 par value; 300,000,000 shares authorized, 159,358,890 shares issued and outstanding atJune 30, 2018; 158,596,324 shares issued and outstanding at December 31, 2017 1,594 1,586

Additional paid-in capital 4,133,172 4,128,659 Accumulated earnings 378,016 192,113

Total stockholders’ equity 4,512,782 4,322,358

TOTAL LIABILITIES AND STOCKHOLDERS ’ EQUITY $ 6,776,285 $ 6,270,186

Theaccompanyingnotesareanintegralpartoftheseconsolidatedfinancialstatements.

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RSP PERMIAN, INC.CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited) Three Months Ended June 30, Six Months Ended June 30, (in thousands, except per share data) 2018 2017 2018 2017 REVENUES Oil sales $ 289,596 $ 160,395 $ 541,573 $ 312,032 Natural gas sales 3,896 9,859 12,327 17,237 NGLs sales 19,362 12,846 35,275 23,762

Total revenues 312,854 183,100 589,175 353,031 OPERATING EXPENSES Lease operating expenses 34,832 28,892 66,968 54,303 Production and ad valorem taxes 19,561 10,142 35,822 19,611 Depreciation, depletion and amortization 87,444 68,104 163,566 129,144 Asset retirement obligation accretion 204 150 409 303 Impairments of oil and natural gas properties 4,468 5,312 8,668 5,437 Exploration expenses 1,159 2,869 1,405 5,449 General and administrative expenses 13,788 12,343 28,122 24,055 Merger and acquisition costs 695 401 3,452 4,453

Total operating expenses 162,151 128,213 308,412 242,755

OPERATING INCOME 150,703 54,887 280,763 110,276 OTHER INCOME (EXPENSE) Other income, net 614 589 1,654 1,309 Net gain (loss) on derivative instruments (5,356) 12,194 (2,449) 29,315 Interest expense (24,059) (19,508) (46,561) (38,732)

Total other expense (28,801) (6,725) (47,356) (8,108)

INCOME BEFORE TAXES 121,902 48,162 233,407 102,168 INCOME TAX EXPENSE (25,572) (17,072) (47,504) (32,144)

NET INCOME $ 96,330 $ 31,090 $ 185,903 $ 70,024

Earnings per common share: Basic $ 0.61 $ 0.20 $ 1.18 $ 0.46 Diluted $ 0.61 $ 0.20 $ 1.18 $ 0.46

Weighted average shares outstanding: Basic 157,267 156,856 157,193 151,455 Diluted 158,499 157,827 158,444 152,443


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RSP PERMIAN, INC.CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited) Common Stock

Additional Capital

AccumulatedEarnings (Deficit)

Total Stockholders’

Equity (in thousands) Shares Amount BALANCE AT DECEMBER 31, 2016 141,924 $ 1,419 $ 3,455,916 $ (40,023) $ 3,417,312Shares of common stock issued for acquisition 16,020 160 663,694 — 663,854 Equity issuance costs — — (80) — (80) Repurchase and retirement of common stock (172) (1) (7,515) — (7,516) Equity-based compensation 819 8 3,915 — 3,923 Net income — — — 38,934 38,934

BALANCE AT MARCH 31, 2017 158,591 $ 1,586 $ 4,115,930 $ (1,089) $ 4,116,427 Equity issuance costs — — (269) — (269) Repurchase and retirement of common stock (5) — (145) — (145) Equity-based compensation 3 — 4,444 — 4,444 Net income — — — 31,090 31,090

BALANCE AT JUNE 30, 2017 158,589 $ 1,586 $ 4,119,960 $ 30,001 $ 4,151,547

Common Stock

Additional Capital

AccumulatedEarnings (Deficit)

Total Stockholders’

Equity (in thousands) Shares Amount BALANCE AT DECEMBER 31, 2017 158,596 $ 1,586 $ 4,128,659 $ 192,113 $ 4,322,358 Repurchase and retirement of common stock (171) (2) (6,459) — (6,461) Equity-based compensation 998 10 5,317 — 5,327 Net income — — — 89,573 89,573

BALANCE AT MARCH 31, 2018 159,423 $ 1,594 $ 4,127,517 $ 281,686 $ 4,410,797 Repurchase and retirement of common stock (1) — (66) — (66) Equity-based compensation (63) — 5,721 — 5,721 Net income — — — 96,330 96,330

BALANCE AT JUNE 30, 2018 159,359 $ 1,594 $ 4,133,172 $ 378,016 $ 4,512,782


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RSP PERMIAN, INC.CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited) Six Months Ended June 30, (in thousands) 2018 2017 OPERATING ACTIVITIES: Net income $ 185,903 $ 70,024 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion and amortization 163,566 129,144 Asset retirement obligation accretion 409 303 Impairments of oil and natural gas properties 8,668 5,437 Equity-based compensation 11,048 8,367 Amortization of loan fees and discount on debt issuance 2,157 2,072 Deferred income taxes 47,504 32,144 Other (386) (308) Net (gain) loss on derivative instruments 2,449 (29,315) Net cash payments from settled derivatives (22,628) (4,078)

Changes in operating assets and liabilities: Accounts receivable (3,815) 669 Other assets (649) (8,134) Accounts payable (1,088) 6,089 Accrued expenses (7,613) 3,200 Interest payable 373 12,227

Net cash provided by operating activities 385,898 227,841 INVESTING ACTIVITIES:

Development of oil and natural gas properties (484,827) (268,205) Acquisitions of oil and natural gas properties (10,394) (622,280) Acquisition deposit held in escrow — (24,601) Acquisition of infrastructure assets — (19,156) Proceeds from sale of assets — 1,527 Other (308) (1,627)

Net cash used in investing activities (495,529) (934,342) FINANCING ACTIVITIES:

Payment of deferred loan costs — (490) Borrowings under long-term debt 165,000 58,000 Payments of equity issuance costs — (349) Repurchase and retirement of common stock (6,527) (7,661)

Net cash provided by financing activities 158,473 49,500

NET CHANGE IN CASH 48,842 (657,001)

CASH AT BEGINNING OF PERIOD 38,102 690,776

CASH AT END OF PERIOD $ 86,944 $ 33,775

SUPPLEMENTAL CASH FLOW INFORMATION Cash paid for interest $ 44,032 $ 24,434 Cash paid for taxes $ — $ —

NON-CASH ACTIVITIES Common stock issued for oil and gas properties $ — $ 663,854 Release of deposit held in escrow for oil and gas properties $ — $ 64,122


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NOTE 1—NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Organization and Description of the Business

RSP Permian, Inc., a Delaware corporation (“RSP Inc.,” the “Company,” “we,” “our,” or “us”), was an independent oil and natural gas companyengaged in the acquisition, exploration, exploitation, development and production of unconventional oil and associated liquids-rich natural gas reserves inthe Permian Basin of West Texas. The vast majority of the Company’s acreage is located on large, contiguous acreage blocks in the core of the MidlandBasin and the Delaware Basin, both sub-basins of the Permian Basin. The Midland Basin properties are primarily in the adjacent counties of Midland,Martin, Andrews, Ector and Glasscock. The Delaware Basin properties are in Loving and Winkler counties.

Merger with Concho Resources Inc.

On March 27, 2018, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Concho Resources Inc., a Delawarecorporation (“Concho”), and Green Merger Sub Inc., a Delaware corporation and wholly owned subsidiary of Concho (“Merger Sub”), pursuant to whichMerger Sub merged with and into RSP Inc. (the “Merger”), with RSP Inc. surviving the Merger as a wholly owned subsidiary of Concho. The Mergerclosed on July 19, 2018.

Upon consummation of the Merger, each share of RSP Inc. common stock, par value $0.01 per share, issued and outstanding immediately prior to theeffective time of the Merger was converted into the right to receive from Concho 0.320 of a fully paid and nonassessable share of common stock, par value$0.001 per share, of Concho. Concho issued approximately 51 million shares of common stock at a price of $148.27 per share, resulting in totalconsideration paid by Concho to the former RSP Inc. shareholders of approximately $7.5 billion.

Basis of Presentation

These consolidated financial statements have been prepared by the Company pursuant to the rules and regulations of the U.S. Securities and ExchangeCommission (“SEC”) and are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). They reflect alladjustments that are, in the opinion of management, necessary for a fair presentation. All such adjustments are of a normal, recurring nature. Theconsolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. All intercompany balances andtransactions have been eliminated in consolidation.

Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with GAAP havebeen omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented notmisleading. These financial statements should be read together with the financial statements and notes thereto included in the Company’s Annual Report onForm 10-K for the year ended December 31, 2017, which contains a complete summary of the Company’s significant accounting policies and disclosures.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts ofassets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. The moresignificant estimates pertain to proved oil, natural gas liquids (“NGLs”) and natural gas reserves, asset retirement obligations (“AROs”), equity-basedcompensation, estimates relating to oil, NGLs and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilitiesacquired in business combinations, derivatives and income taxes. Although management believes these estimates are reasonable, actual results could differfrom these estimates. Changes in estimates are recorded prospectively.

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Significant assumptions are required in the valuation of proved oil, NGLs and natural gas reserves that may affect the amount at which oil and naturalgas properties are recorded. Depletion of oil and natural gas properties are determined using estimates of proved oil, NGLs and natural gas reserves. Thereare numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing ofdevelopment expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerousuncertainties including, among others, estimates of future recoverable reserves and commodity price estimates. It is possible that these estimates could berevised at future dates and such revisions could be material.

Revenue from Contracts with Customers (Topic 606) - ASU 2014-09

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contractswith Customers (Topic 606) (“ASC 606”). ASC 606 provides a comprehensive revenue recognition standard for contracts with customers that supersedescurrent revenue recognition guidance including industry specific guidance and includes a five-step revenue recognition model to depict the transfer of goodsor services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. We adoptedASC 606 in the first quarter of 2018 using the modified retrospective method. The adoption of ASC 606 did not result in a cumulative effect adjustment onour opening accumulated earnings balance in our consolidated balance sheet. Results for reporting periods beginning after January 1, 2018 are presentedunder ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historical accounting under ASC 605,Revenue Recognition (“ASC 605”).

Disaggregationofrevenue

In accordance with ASC 606, the Company disaggregates revenues from contracts with customers by product type. All of the Company’s revenue isrecognized at a point in time when the customer obtains control of the delivered product, which for the Company is primarily at the wellhead. The followingtable presents our revenues disaggregated by product type and the impact of applying ASC 606 on our current period results: Three Months Ended Six Months Ended June 30, 2018 June 30, 2018 As reported Historical Effect of As reported Historical Effect of (in thousands) (ASC 606) (ASC 605) Change (ASC 606) (ASC 605) Change REVENUES

Oil sales $ 289,596 $289,596 $ — $ 541,573 $541,573 $ — Natural gas sales 3,896 6,681 (2,785) 12,327 16,281 (3,954) NGLs sales 19,362 23,339 (3,977) 35,275 41,413 (6,138)

Total revenues 312,854 319,616 (6,762) 589,175 599,267 (10,092) OPERATING EXPENSES — —

Lease operating expenses 34,832 41,594 (6,762) 66,968 77,060 (10,092)

OPERATING INCOME 150,703 150,703 — 280,763 280,763 —

NET INCOME $ 96,330 $ 96,330 $ — $ 185,903 $185,903 $ —

Changes to revenues and lease operating expenses shown in the table above are due to the conclusion under ASC 606 that the Company meets thedefinition of an agent for certain of its gas processing and purchase contracts, thus the fees paid to these service providers are recorded as a deduction torevenues. In contracts where the Company meets the definition of a principal under the control model defined in ASC 606, the fees paid to these serviceproviders are recorded as lease operating expenses.

Oil,naturalgasandNGLssales

We generally sell oil production at the wellhead for a contractually specified index price plus or minus a differential, less transportation costs, andrecognize revenue at the net price received.

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Under our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processingentity’s system. For those contracts where we have concluded we are the agent and the midstream processing entity is our customer, we recognize naturalgas and NGLs revenues based on the net amount of the proceeds received from the midstream processing entity. Alternatively, for those contracts where wehave concluded we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with transportation, gathering,processing and compression fees presented as a component of lease operating expenses in our consolidated statements of operations.

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGLs salesare typically not received for 30 to 90 days after the date production is delivered. At the end of each month, we estimate the amount of production that wasdelivered to the purchaser and the price that will be received. Variances between our estimates and the actual amounts received, if any, are recorded in themonth payment is received. During the first half of 2018, revenue recognized in the reporting period related to performance obligations satisfied in priorreporting periods were not significant.

Practicalexpedientsandexemptions

We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and(ii) contracts for which the variable consideration is allocated entirely to a wholly unsatisfied performance obligation, as allowed under ASC 606. Under oursales contracts, each barrel of oil and NGLs, or MMBtu of natural gas represents a separate performance obligation; therefore future volumes are whollyunsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Accounts Receivable

(in thousands) As of June 30, 2018 As of December 31, 2017 Sale of oil, natural gas and NGLs $ 103,598 $ 95,942 Joint interest owners and other 11,973 14,880 Federal income tax receivable 335 335

Total accounts receivable $ 115,906 $ 111,157

Accounts receivable, which are primarily from the sale of oil, NGLs and natural gas, are accrued based on estimates of the volumetric sales and pricesthe Company believes it will receive. In addition, settled but uncollected derivative contracts, receivables related to joint interest billings and income taxreceivables are included in accounts receivable. The Company routinely reviews outstanding balances, assesses the financial strength of its customers andrecords a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts,historical losses, existing economic conditions and other pertinent factors. Bad debt expense was zero for the three and six months ended June 30, 2018 and2017, respectively.

Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by theCompany related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells arecapitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful.

The Company may capitalize interest on expenditures for significant exploration and development projects that last more than six months, whileactivities are in progress to bring the assets to their intended use. The Company has not capitalized any interest as projects generally lasted less than sixmonths. Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are expensed as incurred.

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Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted using the unit-of-production methodbased on proved reserves. Capitalized exploration well costs and development costs, including AROs, are depleted using the unit-of-production methodbased on proved developed reserves. For the three months ended June 30, 2018 and 2017, depletion expense for oil and natural gas producing property was$86.7 million and $67.4 million, respectively. For the six months ended June 30, 2018 and 2017, depletion expense for oil and natural gas producingproperty was $162.1 million and $127.8 million, respectively. Depletion expense is included in depreciation, depletion and amortization in theaccompanying consolidated statements of operations.

The Company’s oil and natural gas properties as of June 30, 2018 and December 31, 2017 consisted of the following:

(in thousands) June 30, 2018 December 31, 2017 Proved oil and natural gas properties $ 4,497,203 $ 3,936,565 Unproved oil and natural gas properties 2,829,107 2,865,952

Total oil and natural gas properties 7,326,310 6,802,517 Less: Accumulated depletion (940,083) (778,596)

Total oil and natural gas properties, net $ 6,386,227 $ 6,023,921

In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Suchexploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well andsufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of June 30, 2018 and December 31,2017, there were no costs capitalized in connection with exploratory wells in progress.

Proved oil and natural gas properties are evaluated for impairment annually or whenever events or changes in circumstances indicate that an asset’scarrying amount may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flowsavailable, which is the level at which depletion is calculated. To determine if an asset is impaired, the Company compares the carrying value of the asset tothe undiscounted future net cash flows by applying estimates of future oil, NGLs and natural gas prices to the estimated future production of oil, NGLs andnatural gas reserves over the economic life of the asset and deducting future costs. Future net cash flows are based upon our reservoir engineers’ estimatesof proved reserves and risk-adjusted probable reserves.

For a property determined to be impaired, an impairment loss equal to the difference between the asset’s carrying value and its estimated fair value isrecognized. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Each part of this calculation is subject to alarge degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. No impairment ofproved property was recorded for the six months ended June 30, 2018 or 2017. The calculation of expected future net cash flows in impairment evaluationsis primarily based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of futureproduction and capital costs associated with our proved and risk-adjusted probable reserves. The Company’s estimates for future oil and natural gas pricesused in the impairment evaluations are based on observable prices for the next three years, and then held constant for the remaining lives of the properties.

Unproved property costs and related leasehold expirations are assessed quarterly for potential impairment and when industry conditions dictate animpairment may be possible. For the six months ended June 30, 2018 and 2017, we impaired approximately $8.7 million and $5.4 million, respectively, ofunproved oil and natural gas properties, which primarily related to management’s expectation that certain leasehold interests would expire and not berenewed.

Proceeds from the sales of individual oil and natural gas properties that are part of a depletion base are credited to accumulated depletion with noimmediate impact on income until the entire depletion base is sold. However, gain or loss is recognized if the disposition is significant enough to materiallyimpact the depletion rate of the remaining properties in the depletion base. Gains and losses arising from the sale of properties are generally included inoperating income.

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Accrued Expenses

Accrued expenses consist of the following:

(in thousands) June 30, 2018 December 31, 2017 Accrued capital expenditures $ 117,981 $ 82,748 Other accrued expenses 30,572 36,691

Accrued expenses $ 148,553 $ 119,439

Asset Retirement Obligation

The Company records AROs related to the retirement of long-lived assets at the time a legal obligation is incurred and the liability can be reasonablyestimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, theasset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability dueto passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of the surface acreage to a conditionsimilar to that existing before oil and natural gas extraction began.

In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using currentprices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonmentobligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO liability and thelong-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in theestimated timing of abandonment.

After recording these amounts, the ARO liability is accreted to its future estimated value using the same assumed credit adjusted rate and theassociated capitalized costs are depreciated on a unit-of-production basis.

The following is a reconciliation of our ARO liability for the six months ended June 30, 2018:

(in thousands) Asset retirement obligation at beginning of period $15,849 Liabilities incurred 1,807 Liabilities settled (516) Accretion expense 409

Asset retirement obligation at end of period $17,549

Income Taxes

The following is an analysis of the Company’s consolidated income tax expense for the periods indicated:

Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Current $ — $ 638 $ — $ 2,136 Deferred 25,572 16,434 47,504 30,008

Income Tax Expense $ 25,572 $ 17,072 $ 47,504 $ 32,144

Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement carrying amounts and tax basisof assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, andthose tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimatesettlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating touncertain tax positions in income tax expense. We have not recognized any interest and penalties relating to unrecognized tax benefits in our consolidatedfinancial statements.

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New Accounting Pronouncements

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). ASU 2016-02 generally requires all lease transactions (withexpected lease terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to applyASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. We do not plan to early adopt thestandard. We are currently evaluating the impact of ASU 2016-02 on our consolidated financial statements.

On August 17, 2018, the SEC issued a final rule that amends certain of its disclosure requirements that have become redundant, duplicative,overlapping, outdated or superseded, in light of other disclosure requirements, GAAP or changes in the information environment. The amendments areintended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information providedto investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes instockholders’ equity. The final rule extends to interim periods the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changesin stockholders’ equity. The registrants are required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter andyear-to-date interim periods and comparative periods in the prior year. The final rule became effective for all filings submitted on or after November 5,2018.

NOTE 3—ACQUISITIONS OF OIL AND NATURAL GAS PROPERTY INTERESTS

During the first quarter of 2018, we closed on bolt-on acquisitions of undeveloped acreage in the Delaware Basin for an aggregate total purchase priceof $8.7 million.

NOTE 4—DERIVATIVE INSTRUMENTS

Commodity Derivative Instruments

The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its crude oil andnatural gas production. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized incurrent period earnings.

Our commodity derivatives are comprised of the following instruments:

Collars: Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put as well. When thesettlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference betweenthe settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by thesecollars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedgedcontract volume. When the settlement price is below the short put price, the Company pays its counterparty an amount equal to the difference between thesettlement price and the short put price multiplied by the hedged contract volume.

Swaps: Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterpartyan amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price isbelow the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied bythe hedged contract volume.

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The following table summarizes all commodity derivative positions as of June 30, 2018:

Contracts expiring in the period ending:

September 30,

2018 December 31,

2018 Full year 2019 Oil Three-Way Collars (1):

Notional volume (Bbl) 1,319,000 1,277,000 — Weighted average ceiling price ($/Bbl) $ 60.56 $ 60.96 $ — Weighted average floor price ($/Bbl) $ 47.79 $ 48.00 $ — Weighted average short put price ($/Bbl) $ 37.79 $ 38.00 $ —

Oil Costless Collars (1): Notional volume (Bbl) 1,212,000 1,058,000 4,741,988 Weighted average ceiling price ($/Bbl) $ 60.10 $ 60.11 $ 63.83 Weighted average floor price ($/Bbl) $ 46.33 $ 46.52 $ 55.96

Oil Swaps (1): Notional volume (Bbl) 1,167,000 843,000 4,741,988 Weighted average swap price ($/Bbl) $ 66.48 $ 64.91 $ 60.47

Mid-Cush Differential (Basis) Swaps (2): Notional volume (Bbl) 2,760,000 2,760,000 2,555,000 Weighted average swap price ($/Bbl) $ (0.42) $ (0.42) $ (0.29)

(1) The oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of

West Texas Intermediate Light Sweet Crude.(2) The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS

and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period.

Derivative Fair Values and Gains

The following table presents the fair value of our derivative instruments. Our derivatives are presented as separate line items in our consolidatedbalance sheets as current and noncurrent derivative instrument assets and liabilities based on the expected settlement dates of the instruments. The Companyhas agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement orin the event of a default under the agreements. However, the fair value amounts are presented on a gross basis in our consolidated balance sheets and do notreflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements. See Note 5 for further discussionrelated to the fair value of the Company’s derivatives.

Assets Liabilities (in thousands) June 30, 2018 December 31, 2017 June 30, 2018 December 31, 2017 Derivative Instruments:

Current amounts $ 81,915 $ 64 $ 90,898 $ 36,566 Noncurrent amounts 9,240 37 20,109 5,722

Total derivative instruments $ 91,155 $ 101 $ 111,007 $ 42,288

Gains and losses on derivatives are reported in the consolidated statements of operations.

The following table represents the Company’s reported gains on derivative instruments for the periods presented:

Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2018 2017 2018 2017 Net gain (loss) on derivative instruments $ (5,356) $ 12,194 $ (2,449) $ 29,315

Credit-Risk Related Contingent Features in Derivatives

None of the Company’s derivative instruments contain credit-risk related contingent features. No amounts of collateral were posted by the Companyrelated to net positions as of June 30, 2018 and December 31, 2017.

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NOTE 5—FAIR VALUE MEASUREMENTS

We value our derivatives and other financial instruments according to FASB ASC 820, Fair Value Measurements and Disclosures, which defines fairvalue as the exchange price that would be received for an asset or paid to transfer a liability (“exit price”) in the principal or most advantageous market forthe asset or liability in an orderly transaction between market participants on the measurement date.

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) andthe lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the inputs to the valuation techniques asfollows:

• Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in

an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets orliabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputsthat are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs areobservable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data orsupported by observable levels at which transactions are executed in the marketplace.

• Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are

both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data and mayreflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowestpriority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurementrequires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Reclassifications of fair value among Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. Therewere no transfers among Level 1, Level 2 or Level 3 during the six months ended June 30, 2018.

Fair Value Measurement on a Recurring Basis

Fairvalueofcommodityderivativeinstruments

The fair value of derivative financial instruments is determined utilizing industry standard models incorporating assumptions and inputs, most ofwhich are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms andprices, credit risk adjustments, implied market volatility and discount factors.

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The following table presents a summary of the estimated net fair value of our commodity derivative instruments as of June 30, 2018 and December31, 2017:

As of June 30, 2018 (in thousands) Level 1 Level 2 Level 3 Total fair value Commodity derivative instruments $ — $ (19,852) $ — $ (19,852)

As of December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total fair value Commodity derivative instruments $ — $ (42,187) $ — $ (42,187)

Fairvalueofotherfinancialinstruments

Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued expenses. The carrying amount of theseinstruments approximates fair value because of their short-term nature. The carrying value of our borrowings under our revolving credit facility (“RevolvingCredit Facility”) approximates fair value as these are subject to short-term floating interest rates that approximate the rates available to us for thoseperiods. The estimated fair values of our senior notes are presented below. The estimated fair value of our 5.25% senior unsecured notes due January 15,2025 (“2025 Senior Notes”) and 6.625% senior unsecured notes due October 1, 2022 (“2022 Senior Notes”) have been calculated based on quoted prices inactive markets and are classified as Level 1. In connection with the closing of the Merger, on July 19, 2018, Concho repaid the outstanding principalbalance under the Revolving Credit Facility and redeemed and canceled the 2022 Senior Notes and the 2025 Senior Notes.

The following table presents a summary of the estimated fair value of our senior notes as of June 30, 2018 and December 31, 2017:

As of June 30, 2018 (in thousands) Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $481,275 $ — $ — $ 481,275 2022 Senior Notes 732,585 — — 732,585

As of December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $464,022 $ — $ — $ 464,022 2022 Senior Notes 734,706 — — 734,706

Nonfinancial Assets and Liabilities

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptionsassociated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’sestimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data.Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily basedupon assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs. Ourestimated abandonment costs are obtained primarily from independent third parties for costs that would be incurred to restore leased property to thecontractually stipulated condition or costs incurred historically for similar work. Additions to the Company’s AROs represent a nonrecurring Level 3measurement.

The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows ata producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used inthe impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discountrates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3measurement.

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NOTE 6—LONG-TERM DEBT

Long-term debt consists of the following:

(in thousands) June 30, 2018 December 31, 2017 Revolving Credit Facility $ 540,000 $ 375,000 5.25% Senior Notes due 2025 450,000 450,000 6.625% Senior Notes due 2022 700,000 700,000 Less: Discount (850) (950) Less: Debt issuance costs (13,758) (14,922)

Total long-term debt $ 1,675,392 $ 1,509,128

Revolving Credit Facility

As of June 30, 2018, the borrowing base under our amended and restated credit agreement was $1.5 billion, with a Company-elected commitment of$900.0 million, and lender commitments of $2.5 billion. The maturity date of the Revolving Credit Facility was December 19, 2021. As of June 30, 2018,we had $540.0 million in borrowings, $1.9 million of letters of credit outstanding and $358.1 million of borrowing capacity under our Revolving CreditFacility. In connection with the closing of the Merger, on July 19, 2018, Concho repaid the outstanding principal balance under the Revolving CreditFacility.

The Company’s credit agreement required that we maintain the following two financial ratios:

• a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under its Revolving Credit Facility and

excludes restricted cash and derivative assets) to consolidated current liabilities (excluding the current portion of long-term debt under theRevolving Credit Facility and derivative liabilities), of not less than 1.0 to 1.0;

• a leverage ratio, which is the ratio of the sum of all of the Company’s debt to the consolidated EBITDAX (as defined in the credit agreement)for the four fiscal quarters then ended, of not greater than 4.25 to 1.0.

Our credit agreement also contained restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make loansto others, make investments, enter into mergers, make or declare dividends, enter into commodity hedges exceeding a specified percentage or our expectedproduction, enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness, incur liens, sell assets, enter into transactionswith affiliates or engage in certain other transactions without the prior consent of the lenders.

The Company was in compliance with such covenants and ratios as of June 30, 2018.

2025 Senior Notes

On December 27, 2016, the Company issued $450.0 million of 5.25% senior unsecured notes at par through a private placement. In November 2017,the Company exchanged these notes for registered notes with the same terms. The 2025 Senior Notes would have matured on January 15, 2025. Interest onthe 2025 Senior Notes was payable semi-annually on January 15 and July 15.

In connection with the closing of the Merger, on July 19, 2018, Concho redeemed and canceled the 2025 Senior Notes and paid approximately$33 million, in the aggregate, of make-whole call premiums to the holders of the 2025 Senior Notes.

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2022 Senior Notes

On September 26, 2014, the Company issued $500.0 million of 6.625% senior unsecured notes at par through a private placement. In June 2015, theCompany exchanged these notes for registered notes with the same terms. On August 10, 2015, the Company issued an additional $200.0 million of 6.625%senior unsecured notes at 99.25% of the principal amount through a private placement. In March 2016, the Company exchanged these additional notes forregistered notes with the same terms. The 2022 Senior Notes would have matured on October 1, 2022. Interest on the 2022 Senior Notes was payable semi-annually on April 1 and October 1.

In connection with the closing of the Merger, on July 19, 2018, Concho redeemed and canceled the 2022 Senior Notes and paid approximately$35 million, in the aggregate, of make-whole call premiums to the holders of the 2022 Senior Notes.

NOTE 7—COMMITMENTS AND CONTINGENCIES

Contractual Obligations

For the six months ended June 30, 2018, the Company had no material changes in its contractual commitments and obligations from amounts listed inNote 7 in the notes to our consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2017, other thanadditional borrowings of $165.0 million under the Revolving Credit Facility.

Legal and Regulatory Matters

The Company is party to proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Companybelieves that the amount of the liability, if any, ultimately incurred with respect to any such proceedings or claims will not have a material adverse effect,individually or in the aggregate, on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future results ofoperations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust anyreserves as appropriate to reflect its assessment of the then-current status of the matters.

As part of the due diligence process related to the Merger subsequent to closing, Concho identified approximately $22 million of certain regulatorymatters primarily related to additional equipment necessary to have facilities compliant with local, state and federal obligations. This amount is subject tochange as additional analysis is performed by Concho.

NOTE 8—EQUITY-BASED COMPENSATION

The Company’s 2014 Long Term Incentive Plan (“LTIP”) provides for granting restricted stock awards and performance-based restricted stockawards to employees, consultants and directors of the Company and its affiliates who perform services for the Company. Equity-based compensationexpense, which was recorded in general and administrative expenses, was $5.7 million and $4.4 million for the three months ended June 30, 2018 and 2017,respectively. Equity-based compensation expense, which was recorded in general and administrative expenses, was $11.0 million and $8.4 million for thesix months ended June 30, 2018 and 2017, respectively.

Restricted Stock Awards

The following table represents restricted stock award activity for the six months ended June 30, 2018:

Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 687,277 32.04 Restricted shares granted 438,812 35.98 Restricted shares canceled (770) 30.66 Restricted shares vested (325,680) 30.11

Restricted shares outstanding, end of period 799,639 $ 35.00

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Performance-Based Restricted Stock Awards

We granted performance-based restricted stock awards to certain officers of the Company. The payout of these awards varies depending on theCompany’s total shareholder return in comparison to an identified peer group.

The following table represents performance-based restricted stock award activity for the six months ended June 30, 2018:

Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 1,001,079 $ 21.14 Restricted shares granted (1) 496,537 23.96 Restricted shares vested (1) (143,824) 31.74

Restricted shares outstanding, end of period 1,353,792 $ 21.05

(1) Performance-based restricted shares granted or vested reflect the number of shares granted or vested at a 100% of the target payout. The actual payout

of the shares granted may be between 0% and 200% depending on the date of the grant and Company’s total shareholder return in comparison to anidentified peer group.

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NOTE 9—EARNINGS PER SHARE

The Company’s basic earnings per share amounts have been computed using the two-class method based on the weighted-average number of sharesof common stock outstanding for the period. A reconciliation of the components of basic and diluted earnings per common share is presented in the tablebelow:

Three Months Ended June 30, Six Months Ended June 30, (in thousands, except per share data) 2018 2017 2018 2017 Numerator:

Net income available to stockholders $ 96,330 $ 31,090 $ 185,903 $ 70,024 Basic net income allocable to participating securities (1) 482 155 930 350

Income available to stockholders $ 95,848 $ 30,935 $ 184,973 $ 69,674

Denominator: Weighted average number of common shares outstanding - basic 157,267 156,856 157,193 151,455 Effect of dilutive securities:

Restricted stock 1,232 971 1,251 988

Weighted average number of common shares outstanding - diluted 158,499 157,827 158,444 152,443

Net earnings per share: Basic $ 0.61 $ 0.20 $ 1.18 $ 0.46 Diluted $ 0.61 $ 0.20 $ 1.18 $ 0.46

(1) Restricted share awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings

using the two-class method. Participating securities, however, do not participate in undistributed net losses.

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Exhibit 99.2

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

On July 19, 2018, Concho Resources Inc. (“Concho”) completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transactionin which each share of RSP common stock was converted into 0.320 of a share of Concho’s common stock. Concho issued approximately 51 million sharesof common stock at a price of $148.27 per share, resulting in total consideration paid to the former RSP shareholders of approximately $7.5 billion.

The following unaudited pro forma combined financial statements (which we refer to as the “unaudited pro forma financial statements”) presentthe combination of the historical consolidated financial statements of Concho and RSP adjusted to give effect to the merger and related transactions. Theunaudited pro forma combined statements of operations (which we refer to as the “unaudited pro forma combined statements of operations”) for the yearended December 31, 2017, and for the six months ended June 30, 2018, combine the historical statements of consolidated operations of Concho and RSP,giving effect to the merger and related transactions as if they had been consummated on January 1, 2017, the beginning of the earliest period presented. Theunaudited pro forma combined balance sheet (which we refer to as the “unaudited pro forma combined balance sheet”) combines the historical consolidatedbalance sheets of Concho and RSP as of June 30, 2018, giving effect to the merger as if it had been consummated on June 30, 2018. The historicalconsolidated financial statements of RSP have been adjusted to reflect certain reclassifications in order to conform to Concho’s financial statementpresentation.

The unaudited pro forma financial statements reflect the following merger-related pro forma adjustments, based on available information andcertain assumptions that Concho believes are reasonable:

• Concho’s merger with RSP using the acquisition method of accounting;

• adjustments to convert RSP’s historical presentation of reserves and revenues from three stream to Concho’s historical presentation of twostream based on dry natural gas residue sold and the shrink factor related to NGL content, resulting in wet gas volumes produced;

• adjustments to conform the classification of expenses in RSP’s historical statements of operations to Concho’s classification for similarexpenses;

• adjustments to conform the classification of certain assets and liabilities in RSP’s historical balance sheet to Concho’s classification for similarassets and liabilities;

• the assumption of liabilities for transaction-related expenses; and

• estimated tax impact of pro forma adjustments.

The pro forma adjustments are preliminary and are subject to change as additional information becomes available and as additional analysis isperformed. The preliminary pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma financial statementspresented below. Any increases or decreases in the fair value of assets acquired and liabilities assumed upon completion of the final valuations will result inadjustments to the unaudited pro forma combined balance sheet and/or statements of operations. The final purchase price allocation may be materiallydifferent than that reflected in the pro forma purchase price allocation presented herein.

Assumptions and estimates underlying the adjustments to the unaudited pro forma combined financial statements (which we refer to as the “proforma adjustments”) are described in the accompanying notes. The historical consolidated financial statements have been adjusted in the unaudited proforma combined financial statements to give effect to the items that are directly attributable to the merger, factually supportable and, with respect to theunaudited pro forma combined statements of operations, expected to have a continuing impact on the combined results of Concho and RSP following themerger. The unaudited pro forma combined financial statements have been presented for illustrative purposes only and are not necessarily indicative of theoperating results and financial position that would have been achieved had the merger occurred on the dates indicated. Further, the unaudited pro formafinancial statements do not purport to project the future operating results or financial position of the combined company following the merger.

1

The unaudited pro forma combined financial statements, although helpful in illustrating the financial characteristics of the combined companyunder one set of assumptions, do not reflect the benefits of expected cost savings (or associated costs to achieve such savings), opportunities to earnadditional revenue or other factors that may result as a consequence of the merger and, accordingly, do not attempt to predict or suggest future results.Specifically, the unaudited pro forma combined statements of operations exclude projected synergies expected to be achieved as a result of the merger ,nordo they include any associated costs that may be required to be incurred to achieve the identified synergies. The unaudited pro forma combined statementsof operations also exclude the effects of transaction costs associated with the merger, costs associated with any restructuring, integration activities or assetdispositions resulting from the merger and to the extent they occur, are expected to be non-recurring and will not have been incurred at the closing date ofthe merger. However, such costs could affect the combined company following the merger in the period the costs are incurred or recorded. Further, theunaudited pro forma combined financial statements do not reflect the effect of any regulatory actions that may impact the results of the combined companyfollowing the merger.

The unaudited pro forma combined financial statements have been developed from and should be read in conjunction with:

• the accompanying notes to the unaudited pro forma combined financial statements;

• the historical audited consolidated financial statements of Concho for the year ended December 31, 2017, included in Concho’s Annual Reporton Form 10-K for the year ended December 31, 2017;

• the historical unaudited condensed consolidated financial statements of Concho as of and for the six months ended June 30, 2018, included inConcho’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018;

• the historical audited consolidated financial statements of RSP for the year ended December 31, 2017, included in RSP’s Annual Report onForm 10-K for the year ended December 31, 2017; and

• the historical unaudited consolidated financial statements of RSP as of and for the six months ended June 30, 2018, included as Exhibit 99.1 inConcho’s Current Report on Form 8-K filed December 28, 2018.

2

Concho Resources Inc.Unaudited Pro Forma Combined Balance Sheet

As of June 30, 2018(in millions)

Concho Historical

RSP Historical

Pro Forma Adjustments

Concho Pro FormaCombined

Assets Current assets:

Cash and cash equivalents $ 55 $ 87 $ — $ 142 Accounts receivable, net of allowance for doubtful accounts:

Oil and natural gas 410 104 — 514 Joint operations and other 245 12 — 257

Inventory 17 — 11(a) 28 Derivative instruments 173 82 (30)(a) 225 Prepaid costs and other 50 — — 50

Total current assets 950 285 (19) 1,216

Property and equipment: Oil and natural gas properties, successful efforts method 22,518 7,326 240(b) 30,135

51(a) Accumulated depletion and depreciation (8,962) (940) 940(c) (8,962)

Total oil and natural gas properties, net 13,556 6,386 1,231 21,173 Other property and equipment, net 235 56 (51)(a) 240

Total property and equipment, net 13,791 6,442 1,180 21,413

Deferred loan costs, net 12 — — 12 Goodwill — — 2,225(b) 2,225 Intangible assets, net 21 — — 21 Noncurrent derivative instruments — 9 (5)(a) 4 Other assets 19 40 (11)(a) 42

(6)(d)

Total assets $ 14,793 $ 6,776 $ 3,364 $ 24,933

Liabilities and Stockholders’ Equity Current liabilities:

Accounts payable - trade $ 51 $ 29 $ — $ 80 Revenue payable 226 — 226 Accrued drilling costs 354 — 118(a) 472 Accrued expenses — 148 (148)(a) — Interest payable — 24 (24)(a) — Derivative instruments 358 91 (30)(a) 419 Other current liabilities 257 — 30(a) 410

24(a) 22(b) 77(e)

Total current liabilities 1,246 292 69 1,607

Long-term debt 2,371 1,675 83(f) 4,129 540(d) (540)(d)

Deferred income taxes 981 258 260(b) 1,499 Noncurrent derivative instruments 168 20 (5)(a) 183 Asset retirement obligations and other long-term liabilities 136 18 (2)(b) 152 Commitments and contingencies Stockholders’ equity:

Common stock — 2 (2)(g) — Additional paid-in capital 7,177 4,133 (4,133)(g) 14,726

7,549(h) Retained earnings 2,812 378 (378)(g) 2,735

(77) (e) Treasury stock, at cost (98) — — (98)

Total stockholders’ equity 9,891 4,513 2,959 17,363

Total liabilities and stockholders’ equity $ 14,793 $ 6,776 $ 3,364 $ 24,933

Theaccompanyingnotesareanintegralpartoftheseunauditedproformacombinedfinancialstatements.

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Concho Resources Inc.Unaudited Pro Forma Combined Statement of Operations

For the Six Months Ended June 30, 2018(in millions, except per share amounts)

Concho Concho RSP Pro Forma Pro Forma Historical Historical Adjustments Combined Operating revenues:

Oil sales $ 1,588 $ 542 $ 1(a) $ 2,131 Natural gas sales 304 12 35(a) 357

6(a) NGL sales — 35 (35)(a) —

Total operating revenues 1,892 589 7 2,488

Operating costs and expenses: Oil and natural gas production 260 67 (2)(a) 325 Production and ad valorem taxes 140 36 — 176 Gathering, processing and transportation 20 — 7(a) 29

2(a) Exploration and abandonments 26 1 9(a) 36 Depreciation, depletion and amortization 627 164 8(i) 799 Accretion of discount on asset retirement obligations 4 — — 4 Impairments of long-lived assets — 9 (9)(a) — General and administrative 137 28 — 165 Loss on derivatives 168 — 2(a) 170 Gain on disposition of assets, net (724) — — (724) Acquisition costs — 3 (3)(m) —

Total operating costs and expenses 658 308 14 980

Income from operations 1,234 281 (7) 1,508

Other income (expense): Interest expense (57) (47) 9(j) (95) Net loss on derivative instruments — (2) 2(a) — Other, net 89 2 10(m) 101

Total other income (expense) 32 (47) 21 6

Income before income taxes 1,266 234 14 1,514 Income tax expense (294) (48) (3)(k) (345)

Net income $ 972 $ 186 $ 11 $ 1,169

Earnings per share: Basic net income $ 6.52 $ 5.85 Diluted net income $ 6.50 $ 5.85

Weighted average common shares outstanding: Basic 148 51(l) 199 Diluted 148 51(l) 199


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Concho Resources Inc.Unaudited Pro Forma Combined Statement of Operations

For the Year Ended December 31, 2017(in millions, except per share amounts)

Concho Concho RSP Pro Forma Pro Forma Historical Historical Adjustments Combined Operating revenues:

Oil sales $ 2,092 $ 705 $ — $ 2,797 Natural gas sales 494 36 63(a) 593 NGL sales — 63 (63)(a) —

Total operating revenues 2,586 804 — 3,390

Operating costs and expenses: Oil and natural gas production 408 123 — 531 Production and ad valorem taxes 199 49 — 248 Exploration and abandonments 59 8 59(a) 126 Depreciation, depletion and amortization 1,146 280 2(i) 1,428 Accretion of discount on asset retirement obligations 8 1 — 9 Impairments of long-lived assets — 59 (59)(a) — General and administrative 244 47 — 291 Loss on derivatives 126 — 39(a) 165 Gain on disposition of assets, net (678) — — (678) Acquisition costs — 4 (4)(a) —

Total operating costs and expenses 1,512 571 37 2,120

Income from operations 1,074 233 (37) 1,270

Other income (expense): Interest expense (146) (82) 17(j) (211) Loss on extinguishment of debt (66) — — (66) Net loss on derivative instruments — (39) 39(a) — Other, net 19 3 (4)(a) 18

Total other expense (193) (118) 52 (259)

Income before income taxes 881 115 15 1,011 Income tax benefit 75 117 (6)(k) 186

Net income $ 956 $ 232 $ 9 $ 1,197

Earnings per share: Basic net income $ 6.44 $ 6.02 Diluted net income $ 6.41 $ 5.99

Weighted average common shares outstanding: Basic 147 51(l) 198 Diluted 148 51(l) 199


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NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Note 1. Basis of Presentation

On July 19, 2018, Concho completed the acquisition of RSP through an all-stock transaction in which each share of RSP common stock wasconverted into 0.320 of a share of Concho’s common stock. Concho issued approximately 51 million shares of common stock at a price of $148.27 pershare, resulting in total consideration paid to the former RSP shareholders of approximately $7.5 billion.

The unaudited pro forma combined financial information has been derived from the historical consolidated financial statements of Concho andRSP. Certain of RSP’s historical amounts have been reclassified to conform to Concho’s financial statement presentation. The unaudited pro formacombined balance sheet as of June 30, 2018 gives effect to the merger as if the merger had been completed on June 30, 2018. The unaudited pro formacombined statement of operations for the year ended December 31, 2017, and the six months ended June 30, 2018, give effect to the merger as if the mergerhad been completed on January 1, 2017.

The unaudited pro forma combined financial statements reflect pro forma adjustments that are described in the accompanying notes and arebased on available information and certain assumptions that Concho believes are reasonable; however, actual results may differ from those reflected in thesestatements. In Concho’s opinion, all adjustments that are necessary to present fairly the pro forma information have been made. The following unauditedpro forma combined statements do not purport to represent what the combined company’s financial position or results of operations would have been if thetransaction had actually occurred on the dates indicated above, nor are they indicative of Concho’s future financial position or results of operations. Theseunaudited pro forma combined financial statements should be read in conjunction with the historical consolidated financial statements and related notes ofConcho and RSP for the periods presented.

Note 2. Unaudited Pro Forma Combined Balance Sheet

The merger will be accounted for using the acquisition method of accounting for business combinations. The allocation of the preliminaryestimated purchase price is based upon management’s estimates of and assumptions related to the fair value of assets to be acquired and liabilities to beassumed as of June 30, 2018 using currently available information. Due to the fact that the unaudited pro forma combined financial information has beenprepared based on these preliminary estimates, the final purchase price allocation and the resulting effect on financial position and results of operations maydiffer significantly from the pro forma amounts included herein. Concho expects to finalize its allocation of the purchase consideration as soon aspracticable after completion of the merger.

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The preliminary consideration to be transferred, fair value of assets acquired and liabilities assumed and resulting goodwill expected to berecorded is as follows:

Preliminary Purchase Price Allocation (in millions) Total purchase price $ 7,549

Fair value of liabilities assumed: Accounts payable - trade 29 Accrued drilling costs 118 Current derivative instruments 61 Other current liabilities 76 Long-term debt 1,758 Deferred income taxes 518 Asset retirement obligations 16 Noncurrent derivative instruments 15

Total liabilities assumed $ 2,591

Total purchase price plus liabilities assumed $ 10,140

Fair value of assets acquired: Accounts receivable 116 Current derivative instruments 52 Other current assets 98 Oil and natural gas properties - Proved 4,052 Oil and natural gas properties - Unproved 3,565 Other property and equipment 5 Noncurrent derivative instruments 4 Other assets 23 Implied goodwill 2,225

Total assets acquired $ 10,140

Concho acquired RSP for approximately $7.5 billion with an exchange ratio of 0.320 per share of Concho common stock for each issued andoutstanding eligible share of RSP common stock.

Goodwill recognized is primarily attributable to the excess of the consideration transferred over the acquisition-date identifiable assets acquirednet of liabilities assumed, measured in accordance with generally accepted accounting principles in the United States. Because the merger is non-taxable,RSP’s tax basis in the assets and liabilities will carry over to Concho.

Note 3. Pro Forma Adjustments

The following adjustments have been made to the accompanying unaudited pro forma combined financial statements:

(a) The following reclassifications were made as a result of the transaction to conform to Concho’s presentation:

Pro Forma Combined Balance Sheet as of June 30, 2018:

• Reclassification of approximately $11 million for RSP’s inventory from Otherassetsto Inventory;

• Reclassification of approximately $30 million between currentassetsand currentliabilitiesto net RSP’s Derivativeinstrumentsbycounterparty in order to conform RSP’s gross presentation to Concho’s net presentation;

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• Reclassification of approximately $51 million for certain salt water disposal assets of RSP from Otherpropertyandequipmentto Oilandnaturalgasproperties;

• Reclassification of approximately $5 million between noncurrentassetsand noncurrentliabilitiesto net RSP’s Noncurrentderivativeinstrumentsby counterparty in order to conform RSP’s gross presentation to Concho’s net presentation;

• Reclassification of approximately $118 million of accrued drilling costs of RSP from Accruedexpensesto Accrueddrillingcosts;

• Reclassification of approximately $30 million for certain accrued liabilities of RSP from Accruedexpensesto Othercurrentliabilities;and

• Reclassification of approximately $24 million for RSP’s Interestpayableto Othercurrentliabilities.

Pro Forma Combined Statement of Operations for the six months ended June 30, 2018:

• Reclassification of approximately $1 million for RSP’s Oilsalesto Gathering,processingandtransportationto conform to Concho’spresentation;

• Reclassification of approximately $35 million for RSP’s NGLsalesto Naturalgassales;

• Reclassification of approximately $6 million for RSP’s Naturalgassalesto Gathering,processingandtransportationto conform toConcho’s presentation;

• Reclassification of approximately $2 million for RSP’s gathering, processing and transportation costs from Oilandnaturalgasproductionto Gathering,processingandtransportation;

• Reclassification of approximately $9 million for RSP’s Impairmentsoflong-livedassetsto Explorationandabandonments; and

• Reclassification of approximately $2 million for RSP’s Netlossonderivativeinstrumentsfrom OtherIncome(Expense)to Operatingcostsandexpenses.

Pro Forma Combined Statement of Operations for the year ended December 31, 2017:

• Reclassification of approximately $63 million for RSP’s NGLsalesto Naturalgassales;

• Reclassification of approximately $59 million for RSP’s Impairmentsoflong-livedassetsto Explorationandabandonments;

• Reclassification of approximately $4 million for RSP’s Acquisitioncoststo Otherexpenses; and

• Reclassification of approximately $39 million for RSP’s Netlossonderivativeinstrumentsfrom OtherIncome(Expense)to Operatingcostsandexpenses.

(b) The allocation of the estimated fair value of consideration transferred to the estimated fair value of the assets acquired and liabilities assumed resultedin the following purchase price allocation adjustments:

• Approximately $240 million increase in RSP’s gross book basis of Oilandnaturalgaspropertiesto reflect them at fair value;

• Approximately $2,225 million in Goodwillassociated with the transaction;

• Approximately $260 million net increase in Deferredtaxliabilitiesassociated with the transaction;

• Approximately $22 million increase in Othercurrentliabilitiesprimarily related to certain regulatory obligations; and

• Approximately $2 million decrease in Assetretirementobligationsandotherlong-termliabilitiesto reflect asset retirement obligationsat fair value.

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(c) Reflects the elimination of RSP’s historical Accumulated depreciation, depletion and amortization (which we refer to as “DD&A”) balances.

(d) The following adjustments were made to eliminate RSP’s outstanding credit facility balance using borrowings under Concho’s credit facility:

• Approximately $540 million of borrowings under Concho’s existing credit facility to repay RSP’s remaining credit facility balance; and

• Approximately $6 million to eliminate deferred loan costs related to RSP’s credit facility.

(e) Reflects the impact of estimated transaction costs of $77 million related to the merger, including underwriting, severance, banking, legal andaccounting fees that are not capitalized as part of the transaction. The costs are not reflected in the historical June 30, 2018 consolidated balancesheets of Concho and RSP, but are reflected in the pro forma combined balance sheet as an increase to Othercurrentliabilitiesas they will beexpensed by Concho and RSP as incurred. These amounts and their corresponding tax effect have not been reflected in the pro forma combinedstatements of operations due to their nonrecurring nature.

(f) The following adjustments were made to reflect pro forma increases to Long-termdebt:

• Approximately $68 million to RSP’s senior notes to record them at fair value;

• Approximately $14 million to eliminate the deferred loan costs related to RSP’s senior notes; and

• Approximately $1 million to eliminate the discount on RSP’s senior notes.

(g) Reflects the elimination of RSP’s historical equity balances in accordance with the acquisition method of accounting.

(h) Reflects the estimated increase in Concho’s Commonstockand Additionalpaid-incapitalresulting from the issuance of Concho common shares toRSP stockholders to effect the transaction as follows (in millions, except share and per share amounts):

Shares of Concho common stock to be issued (in thousands) 50,915 Closing price per share of Concho common stock on July 19, 2018 $148.27 Total fair value of shares of Concho common stock to be issued $ 7,549 Increase in Concho common stock ($0.001 par value per share) as of June 30, 2018 —

Increase in Concho additional paid-in capital as of June 30, 2018 $ 7,549

(i) Reflects the pro forma adjustment of historical DD&A, which is calculated as the difference between historical DD&A and the adjusted RSP proforma DD&A. The pro forma DD&A expense for RSP is calculated using a stepped up basis from the preliminary purchase price allocation for oiland natural gas properties assuming the transaction was consummated as of January 1, 2017. The pro forma DD&A adjustments increase historicalDD&A for both the year ended December 31, 2017 and the six months ended June 30, 2018 mainly due to the increase in value of oil and natural gasproperties. The higher fair value of properties as compared to historical value is due to many factors, a primary factor being higher commodity pricesand continued improvement of well economics due to technology advances for undeveloped reserves.

(j) The following adjustments were made to reflect pro forma changes to Interestexpense:

Pro Forma Combined Statement of Operations for the six months ended June 30, 2018:

• Approximately $5 million decrease related to the amortization of the fair value adjustment on RSP’s senior notes;

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• Approximately $2 million decrease related to the elimination of deferred loan costs on RSP’s senior notes and RSP’s credit facility; and

• Approximately $2 million net decrease related to interest calculated on the borrowings under Concho’s existing credit facility after therepayment of RSP’s credit facility balance of $540 million.

Pro Forma Combined Statement of Operations for the year ended December 31, 2017:

• Approximately $9 million decrease related to the amortization of the fair value adjustment on RSP’s senior notes;

• Approximately $4 million decrease related to the elimination of deferred loan costs on RSP’s senior notes and RSP’s credit facility; and

• Approximately $4 million net decrease related to interest calculated on the borrowings under Concho’s existing credit facility after therepayment of RSP’s credit facility balance of $540 million.

(k) Reflects the income tax effect of pro forma adjustments presented. The tax rate applied was the estimated combined statutory rate of 22.7% for the sixmonths ended June 30, 2018 and 36.7% for the year ended December 31, 2017. The effective rate of the combined company could be significantlydifferent (either higher or lower) depending on post-merger activities.

(l) Reflects Concho common stock issued to RSP stockholders.

(m) Reflects the elimination of transaction costs related to the merger.

Note 4. Unusual events

For the year ended December 31, 2017

ACCdivestiture.In February 2017, Concho closed on the divestiture of its ownership interest in Alpha Crude Connector, LLC. After directtransaction costs, Concho recorded a pre-tax gain on disposition of assets of approximately $655 million, which is included in Gainondispositionofassets,neton the consolidated statement of operations.

Incometaxbenefit. Concho recorded an income tax benefit of $75 million, which included discrete provisional income tax benefits ofapproximately $398 million related to the enactment of the Tax Cuts and Jobs Act. For additional information, see Note 11 of the Notes to ConsolidatedFinancial Statements included in “Item 8. Financial Statements and Supplementary Data” of Concho’s Annual Report on Form 10-K for the year endedDecember 31, 2017 incorporated herein by reference.

For the six months ended June 30, 2018

Oryxdistribution. Concho owns a 23.75% membership interest in Oryx Southern Delaware Holdings, LLC, an entity that operates a crude oilgathering and transportation system in the Southern Delaware Basin. Concho received a distribution of approximately $157 million, of which approximately$103 million was recorded in Otherincome.

February2018acquisitionanddivestiture. In February 2018, Concho closed on an acquisition treated as a business combination where thebusiness acquired was valued at approximately $755 million as compared to the historical book value of the divested assets of approximately $180 million,which resulted in a non-cash gain of approximately $575 million, included in Gainondispositionofassets,net.

SouthernDelawareBasindivestitures. In January 2018, Concho closed on two asset sales transactions of certain non-core assets withcombined preliminary proceeds of approximately $280 million, which resulted in a pre-tax gain of $134 million included in Gainondispositionofassets,net.

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Note 5. Supplemental Pro Forma Oil and Natural Gas Reserves Information

The following tables present the estimated pro forma combined net proved developed and undeveloped oil, natural gas and NGL reserves as ofDecember 31, 2017, along with a summary of changes in the quantities of net remaining proved reserves during the year ended December 31, 2017. The proforma reserve information set forth below gives effect to the merger as if the merger had been completed on January 1, 2017.

Oil and Condensate (MMBbls)

Concho Historical RSP Historical


Balance—December 31, 2016 428 165 593 Purchases of minerals-in-place 22 35 57 Sales of minerals-in-place (2) — (2) Extensions and discoveries 115 65 180 Revisions of previous estimates (20) 11 (9) Production (43) (14) (57)

Balance—December 31, 2017 500 262 762

Proved Developed Reserves: December 31, 2016 267 65 332 December 31, 2017 336 107 443

Proved Undeveloped Reserves: December 31, 2016 161 100 261 December 31, 2017 164 155 319

Natural Gas (Bcf)

Concho Historical

RSP Historical


(a)


Balance—December 31, 2016 1,752 177 83 2,012 Purchases of minerals-in-place 72 34 16 122 Sales of minerals-in-place (9) — — (9) Extensions and discoveries 351 73 34 458 Revisions of previous estimates 38 26 12 76 Production (161) (15) (7) (183)

Balance—December 31, 2017 2,043 295 138 2,476

Proved Developed Reserves: December 31, 2016 1,190 76 35 1,301 December 31, 2017 1,512 133 63 1,708

Proved Undeveloped Reserves: December 31, 2016 562 101 48 711 December 31, 2017 531 162 75 768

NGLs (MMBbls)

RSP

Historical


(a)


Balance—December 31, 2016 43 (43) — Purchases of minerals-in-place 6 (6) — Extensions and discoveries 16 (16) — Revisions of previous estimates 3 (3) — Production (3) 3 —

Balance—December 31, 2017 65 (65) —

Proved Developed Reserves: December 31, 2016 19 (19) — December 31, 2017 30 (30) —

Proved Undeveloped Reserves: December 31, 2016 24 (24) — December 31, 2017 35 (35) —

(a) Adjustment for conversion from three-stream to two-stream based on dry natural gas residue sold and the shrink factor related to NGL content,

resulting in wet gas volumes produced.

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The pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2017is as follows (in millions):

Concho Historical

RSP Historical


December 31, 2017 Future cash inflows $ 29,761 $ 14,635 $ 44,396 Future production costs (9,612) (3,868) (13,480) Future development and abandonment costs (2,636) (1,893) (4,529) Future income tax expense (2,565) (1,553) (4,118)

Future net cash flows 14,948 7,321 22,269 10% annual discount factor (7,470) (4,290) (11,760)

Standardized measure of discounted future net cash flows $ 7,478 $ 3,031 $ 10,509

The changes in the pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for theyear ended December 31, 2017 are as follows (in millions):

Concho Historical

RSP Historical

Concho ProForma

Combined December 31, 2017

Purchases of minerals-in-place $ 304 $ 378 $ 682 Sales of minerals-in-place (20) — (20) Extensions and discoveries 2,014 968 2,982 Development costs incurred during the period 619 163 782 Net changes in prices and production costs 1,830 804 2,634 Oil and natural gas sales, net of production costs (1,979) (632) (2,611) Changes in future development costs 84 43 127 Revisions of previous quantity estimates (154) 200 46 Accretion of discount 470 142 612 Changes in production rates, timing and other 470 153 623

Change in present value of future net revenues 3,638 2,219 5,857 Net change in present value of future income tax expense (350) (381) (731)

3,288 1,838 5,126 Balance, beginning of year 4,190 1,193 5,383

Balance, end of year $ 7,478 $ 3,031 $ 10,509

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