Exhibit 99.2

SILVER HILL ENERGY PARTNERS II, LLC

CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE PERIOD FROM JANUARY 12, 2016 (INCEPTION) TO SEPTEMBER 30, 2016

(UNAUDITED)

See accompanying notes to these unaudited consolidated financial statements.

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SILVER HILL ENERGY PARTNERS II, LLC

CONSOLIDATED BALANCE SHEET

AS OF SEPTEMBER 30, 2016

(UNAUDITED)

See accompanying notes to these unaudited consolidated financial statements.

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SILVER HILL ENERGY PARTNERS II, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE PERIOD FROM JANUARY 12, 2016 (INCEPTION) TO SEPTEMBER 30, 2016

(UNAUDITED)

See accompanying notes to these unaudited consolidated financial statements.

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SILVER HILL ENERGY PARTNERS II, LLC

CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL

FOR THE PERIOD FROM JANUARY 12, 2016 (INCEPTION) TO SEPTEMBER 30, 2016

(UNAUDITED)

See accompanying notes to these unaudited consolidated financial statements.

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SILVER HILL ENERGY PARTNERS II, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2016 AND FOR THE FOR THE PERIOD FROM JANUARY 12, 2016 (INCEPTION) TO SEPTEMBER 30, 2016

(UNAUDITED)

Organization—Silver Hill Energy Partners II, LLC (the “Company” or “SHEP II”), a Delaware limited liability company, was formed on January 12, 2016. SHEP II was formed initially for the purpose of acquiring producing properties and undeveloped acreage from Concho Resources Inc. (“Concho”) for $292 million. SHEP II is engaged in the acquisition, exploitation and development of oil and gas properties. SHEP II’s operations are focused in the Delaware Basin of West Texas.

On October 13, 2016, the Company entered into a Membership Interest Purchase and Sale Agreement (“PSA Agreement”) with RSP Permian, Inc. (“RSP”), a Delaware corporation, pursuant to which RSP agreed to acquire Silver Hill E&P II, LLC (“SHEP II E&P”), a wholly owned subsidiary holding all the assets and operations of SHEP II, for cash consideration of $645.9 million and 16.0 million shares of RSP common stock, subject to customary adjustments (“SHEP II E&P Sale”). The SHEP II E&P Sale is expected to close in March 2017 with an effective date of November 1, 2016. See Note 8.

These unaudited consolidated financial statements include only those assets, liabilities, revenues and expenses that relate to the business of the Company and have been prepared in accordance with accounting principles generally accepted in the United States of America. The statements do not include any assets, liabilities, revenues or expenses attributable to the members’ individual activities. The unaudited consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim period. The results of operations for the interim period are not necessarily indicative of the results of operations to be expected for the full year.

The Company is a limited liability company (“LLC”). As an LLC, the amount of loss at risk for each individual member is limited to the amount of capital contributed to the LLC and, unless otherwise noted, the individual member’s liability for indebtedness of an LLC is limited to the member’s actual capital contribution.

Accounting Estimates—The preparation of the Company’s unaudited consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company’s management to make estimates and assumptions that affect the amounts reported in these unaudited consolidated financial statements and accompanying notes. Certain significant estimates made by management include oil and gas reserves, which affect the carrying value of oil and gas properties, evaluation for impairment of proved and unevaluated property costs and asset retirement obligations. Actual results could differ from those estimates and the differences could be material.

Management believes that it is reasonably possible that the estimates involved in the determination of proved oil and gas reserves could significantly change in the coming year. Total proved reserves are defined as those reserves which can be produced economically using current oil and gas prices. Accordingly, the estimated quantity of proved reserves and the annual amortization expense will likely change along with future price increases and decreases.

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Furthermore, estimating reserves is not an exact science. Estimates can be expected to change as additional information becomes available. Estimates of oil and gas reserves are projections based on the interpretation of engineering data to determine future rates of production and the timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and the engineering and geological interpretation and judgment of the estimator. Accordingly, there can be no assurance that the reserves as estimated will ultimately be produced, nor can there be assurance that the proved undeveloped reserves as estimated will be developed within the period anticipated.

Cash and Cash Equivalents—Cash and cash equivalents include cash and all highly liquid investments with maturities, at the date of purchase, of three months or less. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. Management monitors the soundness of the financial institutions and believes the Company’s risk is negligible.

Financial Instruments—The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, unless otherwise stated, as of September 30, 2016.

Oil and Gas Properties—The Company’s oil and gas properties consisted of the following:

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have found proved reserves. If the Company determines that the wells do not find proved reserves, the costs are charged to expense. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion and depreciation are eliminated from the property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the amount received is treated as a reduction of the cost of the interest retained.

The Company records depletion, depreciation and amortization of capitalized costs of proved oil and gas properties using the unit-of-production method over estimated proved reserves using the unit conversion ratio of six million cubic feet of gas to one barrel of oil equivalent. Capitalized costs of proved mineral interests are depleted over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depreciated over estimated

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proved developed reserves. Depletion, depreciation and amortization expense for oil and gas properties amounted to $12.5 million for the period from January 12, 2016 (inception) to September 30, 2016.

Unproved oil and natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. No impairment of unproved properties was recorded during the period from January 12, 2016 (inception) to September 30, 2016 as the Company continues to extend its leases and complies with its lease terms through production and continuous development. The Company began its horizontal drilling strategy in February 2016 and has completed ten economical wells in 2016. Management also evaluated several recent transactions in the West Texas area and believes the terms support its carrying value as of September 30, 2016.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then an impairment charge is recognized in the Statement of Operations equal to the difference between the carrying value proved properties and their estimated fair values based on the present value of the related future net cash flows. The Company recorded impairment of $0.2 million on proved properties for period from January 12, 2016 (inception) to September 30, 2016.

Furniture, Fixtures, and Equipment—Furniture, fixtures, and equipment are recorded at cost less accumulated depreciation. Depreciation of the related assets is provided using the straight-line method over their respective estimated useful lives.

When assets are sold or retired, the applicable costs and accumulated depreciation are removed and any gain or loss is included in income. Maintenance and repairs are expensed as incurred. Major renewals and improvements are capitalized.

Asset Retirement Obligation—Asset retirement obligations (“ARO”) consist of future plugging and abandonment expenses on oil and gas properties. The Company records the estimated fair value of its ARO when the related wells are acquired or completed with a corresponding increase in the carrying amount of oil and gas. The liability is accreted to its present value each period. Management estimates the fair value of additions to the asset retirement obligation liability using a valuation technique that converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on management’s experience; (ii) estimated remaining life per well; and (iii) the Company’s credit-adjusted risk-free rate. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

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The following is a summary of changes in the ARO during the period from January 12, 2016 (inception) to September 30, 2016:

Revenue—The Company recognizes revenue for its production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices.

Lease Operating Costs—Lease operating costs, including pumpers’ salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating costs on the consolidated statement of operations.

Concentration of Credit Risk— Substantially all accounts receivable result from the sales of oil and natural gas. This concentration of customers may impact the Company’s overall credit risk, as these entities may be similarly affected by changes in economic and other conditions. For period from January 12, 2016 (inception) to September 30, 2016, nearly all of the Company’s oil and natural sales were derived from two purchasers. These purchasers are based in the United States and engaged in the transportation, storage, and marketing of crude oil and other petroleum products. Management believes that the loss of these purchasers would not have a material adverse effect on the Company’s financial position or results of operations because there is an adequate number of potential other purchasers of its oil and gas production.

Income Taxes—The Company is subject to U.S. federal income tax reporting requirements along with state income tax reporting requirements in Texas. Because the Company is a limited liability company, the income or loss of the Company for federal income tax purposes is generally allocated to the members in accordance with the Company’s formation agreements, and it is the responsibility of the members to report their share of taxable income or loss on their separate income tax returns. Accordingly, no recognition has been given to federal income taxes in the accompanying unaudited consolidated financial statements. The Company is subject to Texas margin tax on its operations within the state of Texas, and was de minimis in 2016. Based on management’s analysis, the Company did not have any uncertain tax positions as of September 30, 2016. No interest and penalties have been accrued or recorded.

The Company provides deferred income taxes using the asset and liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss, and tax credit carryforwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of the changes in tax laws and rates on the date of enactment.

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Recently Issued Accounting Standards—The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. This standard becomes effective for us beginning January 2019. The Company is evaluating the impact this ASU may have on our unaudited consolidated financial statements and related disclosures.

The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU reduces the number of existing consolidation models. This ASU is effective for us beginning January 2017. This ASU is not expected to have a material impact on us.

The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require debt issuance costs to be presented as a direct deduction from the carrying amount of that debt rather than as an asset. These ASUs were effective for us beginning January 2016. These ASUs did not have a material impact on our unaudited consolidated financial statements and related disclosures.

The FASB issued ASU 2016-2, Leases. This ASU requires lessees to recognize lease assets and lease liabilities on the statement of financial position. The update is effective for financial statements issued for annual periods beginning after December 15, 2019 and for interim periods within fiscal years beginning after December 15, 2020. Early adoption is permitted. The Company is evaluating the potential impact this ASU may have on our unaudited consolidated financial statements and related disclosures.

On February 26, 2016, the company closed on the acquisition of oil and gas properties from Concho Resources, Inc. for $292 million, of which $210.8 million was allocated to undeveloped acreage and $84.4 million was allocated to developed acreage (“Concho Acquisition”). The Company incurred $0.4 million of transaction costs related to the acquisition for the period from January 12, 2016 (inception) to September 30, 2016. These transaction costs are recorded in the consolidated statements of operations within the general and administrative line item.

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The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of February 26, 2016. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):

On February 26, 2016, the Company entered into a new $300 million Revolving Credit Agreement (“RBL”) with Wells Fargo Bank. The reserve-based facility features a borrowing base equal to the greater of a fixed amount of $45 million or a variable amount based upon the value of the Company’s oil and gas reserves as assessed by Wells Fargo Bank. The assessment of the Company’s oil and gas reserves is redetermined biannually in May and November. The RBL has a scheduled maturity date of February 26, 2021. The RBL has a variable annual interest rate based on the Company’s option, either the London InterBank Offered Rate (“LIBOR”) plus an applicable margin (Eurodollar rate) or the base rate (as defined in the Agreement) plus an applicable margin. In addition, a commitment fee between 0.375% and 0.5% per annum is charged on the unutilized balance of the committed borrowings. Debt issuance costs totaled $0.7 million as of September 30, 2016. The terms of the RBL contains representations, warranties, covenants and events of default that are customary for investment-grade, commercial bank credit agreements.

In June 2016, Wells Fargo Bank redetermined the Company’s borrowing based under the RBL and increased the variable amount to $90 million. For the period from January 12, 2016 (inception) to September 30, 2016, the Company had drawn $81 million in borrowings under the RBL leaving $9.0 million of available borrowings as of September 30, 2016.

In connection with the RBL, the Company failed to maintain compliance with the Current Ratio Covenant (“Covenant”) as of September 30, 2016 and subsequently received a waiver from Wells Fargo Bank. On November 14, 2016, Wells Fargo Bank increased the borrowing based under the RBL to $120 million. Subsequent to the balance sheet date, the Company expects to be compliant with this Covenant during 2016 and 2017, and therefore the borrowings under the RBL are classified as long-term as of September 30, 2016.

The LLC agreement dated February 25, 2016 governs the Company’s ownership. Capital contributions from Members during the period from January 12, 2016 (inception) to September 30, 2016 were used to fund the Company’s ongoing operating and investing activities including the Concho Acquisition (Note 2).

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Net income or loss and distributions are allocated among the members as follows:

The Company elected not to designate any of its financial commodity derivative contracts as accounting hedges and, accordingly, accounted for these financial commodity derivative contracts using the mark-to-market accounting method. During the period from January 12, 2016 (inception) to September 30, 2016, the Company recognized unrealized losses on the mark-to-market of financial commodity derivative contracts of $7.3 million and realized losses of $1.0 million on cash settled commodity derivative contracts.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with one counterparty. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. There are no credit-risk-related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.

US GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement).

The three levels of fair value hierarchy are as follows:

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The following table provided fair value measurement information within the fair value hierarchy for certain of the Company’s financial assets carried at fair value on a recurring basis at September 30, 2016. Amounts shown in thousands.

Fair Value Measurements

The estimated fair value of crude oil derivative contracts was based upon forward commodity price curves based on quoted market prices.

The following summarizes the Company’s commodity derivative positions as of September 30, 2016:

SWAPS

COLLARS

Nonrecurring Fair Value Measurements—Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis (e.g., oil and natural gas properties) and are subject to fair value adjustments under certain circumstances. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and are classified within Level 3.

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During the period from January 12, 2016 (inception) to September 30, 2016, using a discounted cash flow valuation technique, we adjusted the carrying value of certain oil and natural gas properties and recorded impairment charges of $0.2 million. The impairment charges primarily resulted from a decline in oil and natural gas prices and to a much lesser extent to minor changes in management’s assumptions, based on an extensive review of operating results, production history, price realizations and costs.

On February 26, 2016, the Company entered into a Management Services Agreement (“MSA”) with Silver Hill Energy Partners, LLC (“SHEP I”), an entity under common management of the Company, for which SHEP I will provide certain operational and general and administrative services with respect to the Company’s Delaware Basin assets. During the period from February 26, 2016 through September 30, 2016, the Company paid $1.8 million to SHEP I for services under the MSA.

We are party to various legal actions arising in the normal course of business. Management believes the disposition of these outstanding legal actions will not have a material impact on our financial condition, results of operations or cash flows.

On October 13, 2016, the Company entered into a PSA Agreement with RSP pursuant to which RSP agreed to acquire SHEP II E&P, a wholly owned subsidiary holding all of the Company’s assets and operations, for cash consideration of $645.9 million and 16.0 million of its shares of common stock, subject to customary adjustments. The SHEP II E&P Sale is expected to close in March 2017 with an effective date of November 1, 2016.

On November 14, 2016, the Company had increased the variable amount under the RBL to $120 million.

Subsequent events have been assessed through December 7, 2016, the date this report was available for issuance.

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