Concho Resources (CXO) 8-K/A Financial Statements and Exhibits

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 at June 30, 2018; 158,596,324 shares issued and outstanding at December 31, 2017		1,594			1,586
Additionalpaid-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

The accompanying notes are an integral part of these consolidated financial statements.

1

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

The accompanying notes are an integral part of these consolidated financial statements.

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RSP PERMIAN, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

	Common Stock						Additional Capital			Accumulated Earnings (Deficit)			Total Stockholders’ Equity
(in thousands)	Shares			Amount
BALANCE AT DECEMBER 31, 2016		141,924		$	1,419		$	3,455,916		$	(40,023	)	$	3,417,312
Shares 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			Accumulated Earnings (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

The accompanying notes are an integral part of these consolidated financial statements.

3

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

The accompanying notes are an integral part of these consolidated financial statements.

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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 company engaged in the acquisition, exploration, exploitation, development and production of unconventional oil and associated liquids-rich natural gas reserves in the 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 Midland Basin and the Delaware Basin, bothsub-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 Delaware corporation (“Concho”), and Green Merger Sub Inc., a Delaware corporation and wholly owned subsidiary of Concho (“Merger Sub”), pursuant to which Merger Sub merged with and into RSP Inc. (the “Merger”), with RSP Inc. surviving the Merger as a wholly owned subsidiary of Concho. The Merger closed 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 the effective 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 total consideration 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 Exchange Commission (“SEC”) and are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation. All such adjustments are of a normal, recurring nature. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. These financial statements should be read together with the financial statements and notes thereto included in the Company’s Annual Report on Form10-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 of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. The more significant estimates pertain to proved oil, natural gas liquids (“NGLs”) and natural gas reserves, asset retirement obligations (“AROs”), equity-based compensation, estimates relating to oil, NGLs and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and income taxes. Although management believes these estimates are reasonable, actual results could differ from 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 natural gas properties are recorded. Depletion of oil and natural gas properties are determined using estimates of proved oil, NGLs and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates. It is possible that these estimates could be revised at future dates and such revisions could be material.

Revenue from Contracts with Customers (Topic 606) - ASU2014-09

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”). ASC 606 provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance and includes a five-step revenue recognition model to depict the transfer of goods or 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 adopted ASC 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 on our opening accumulated earnings balance in our consolidated balance sheet. Results for reporting periods beginning after January 1, 2018 are presented under 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”).

Disaggregation of revenue

In accordance with ASC 606, the Company disaggregates revenues from contracts with customers by product type. All of the Company’s revenue is recognized at a point in time when the customer obtains control of the delivered product, which for the Company is primarily at the wellhead. The following table 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 the definition 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 to revenues. In contracts where the Company meets the definition of a principal under the control model defined in ASC 606, the fees paid to these service providers are recorded as lease operating expenses.

Oil, natural gas and NGLs sales

We generally sell oil production at the wellhead for a contractually specified index price plus or minus a differential, less transportation costs, and recognize 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 processing entity’s system. For those contracts where we have concluded we are the agent and the midstream processing entity is our customer, we recognize natural gas and NGLs revenues based on the net amount of the proceeds received from the midstream processing entity. Alternatively, for those contracts where we have 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 sales are 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 was delivered to the purchaser and the price that will be received. Variances between our estimates and the actual amounts received, if any, are recorded in the month payment is received. During the first half of 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods were not significant.

Practical expedients and exemptions

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 our sales contracts, each barrel of oil and NGLs, or MMBtu of natural gas represents a separate performance obligation; therefore future volumes are wholly unsatisfied 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 prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, receivables related to joint interest billings and income tax receivables are included in accounts receivable. The Company routinely reviews outstanding balances, assesses the financial strength of its customers and records 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 and 2017, 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 the Company related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, 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, while activities are in progress to bring the assets to their intended use. The Company has not capitalized any interest as projects generally lasted less than six months. 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 theunit-of-production method based on proved reserves. Capitalized exploration well costs and development costs, including AROs, are depleted using theunit-of-production method based 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 producing property was $162.1 million and $127.8 million, respectively. Depletion expense is included in depreciation, depletion and amortization in the accompanying 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. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient 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’s carrying amount may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows available, 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 to the undiscounted future net cash flows by applying estimates of future oil, NGLs and natural gas prices to the estimated future production of oil, NGLs and natural gas reserves over the economic life of the asset and deducting future costs. Future net cash flows are based upon our reservoir engineers’ estimates of 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 is recognized. 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 a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. No impairment of proved property was recorded for the six months ended June 30, 2018 or 2017. The calculation of expected future net cash flows in impairment evaluations is primarily based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted probable reserves. The Company’s estimates for future oil and natural gas prices used 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 an impairment may be possible. For the six months ended June 30, 2018 and 2017, we impaired approximately $8.7 million and $5.4 million, respectively, of unproved oil and natural gas properties, which primarily related to management’s expectation that certain leasehold interests would expire and not be renewed.

Proceeds from the sales of individual oil and natural gas properties that are part of a depletion base are credited to accumulated depletion with no immediate impact on income until the entire depletion base is sold. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Gains and losses arising from the sale of properties are generally included in operating 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 reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to 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 condition similar 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 current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated 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 the associated capitalized costs are depreciated on aunit-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 basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using amore-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. We have not recognized any interest and penalties relating to unrecognized tax benefits in our consolidated financial statements.

9

New Accounting Pronouncements

In February 2016, the FASB issued ASU2016-02, Leases (Topic 842) (“ASU2016-02”). ASU2016-02 generally requires all lease transactions (with expected 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 apply ASU2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. We do not plan to early adopt the standard. We are currently evaluating the impact of ASU2016-02 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 are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes in stockholders’ equity. The final rule extends to interim periods the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changes in stockholders’ equity. The registrants are required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-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 onbolt-on acquisitions of undeveloped acreage in the Delaware Basin for an aggregate total purchase price of $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 and natural gas production. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current 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 the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is below the short put price, the Company pays its counterparty an amount equal to the difference between the settlement 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 counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the 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
OilThree-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) TheMid-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 consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities based on the expected settlement dates of the instruments. The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in 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 not reflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements. See Note 5 for further discussion related 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 Company related 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 fair value 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 for the 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) and the 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 as follows:

• 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 or liabilities 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 inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported 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 may reflect 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 lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires 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. There were 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

Fair value of commodity derivative instruments

The fair value of derivative financial instruments is determined utilizing industry standard models incorporating assumptions and inputs, most of which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, 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 December 31, 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	)

Fair value of other financial instruments

Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued expenses. The carrying amount of these instruments approximates fair value because of their short-term nature. The carrying value of our borrowings under our revolving credit facility (“Revolving Credit Facility”) approximates fair value as these are subject to short-term floating interest rates that approximate the rates available to us for those periods. 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 in active markets and are classified as Level 1. In connection with the closing of the Merger, on July 19, 2018, Concho repaid the outstanding principal balance 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 assumptions associated 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’s estimate 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 based upon assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs. Our estimated abandonment costs are obtained primarily from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition or costs incurred historically for similar work. Additions to the Company’s AROs represent a nonrecurring Level 3 measurement.

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

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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 Credit Facility. In connection with the closing of the Merger, on July 19, 2018, Concho repaid the outstanding principal balance under the Revolving Credit Facility.

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 the Revolving 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 loans to others, make investments, enter into mergers, make or declare dividends, enter into commodity hedges exceeding a specified percentage or our expected production, enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness, incur liens, sell assets, enter into transactions with 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 on the 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, the Company 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 for registered 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 in Note 7 in the notes to our consolidated financial statements in our Annual Report on Form10-K for the year ended December 31, 2017, other than additional 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 Company believes 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 of operations. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any reserves 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 regulatory matters primarily related to additional equipment necessary to have facilities compliant with local, state and federal obligations. This amount is subject to change 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 stock awards to employees, consultants and directors of the Company and its affiliates who perform services for the Company. Equity-based compensation expense, 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 the six 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 the Company’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 an identified peer group.

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NOTE 9—EARNINGS PER SHARE

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

	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 containnon-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using thetwo-class method. Participating securities, however, do not participate in undistributed net losses.

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