Edgar Filing: CONCHO RESOURCES INC

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


☑		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-33615

Concho Resources Inc.

(Exact name of registrant as specified in its charter)


Delaware		76-0818600
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

One Concho Center
600 West Illinois Avenue
Midland, Texas		79701
(Address of principal executive offices)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑	Accelerated filer o

Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Emerging growth company o

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 or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ☑

Number of shares of the registrant’s common stock outstanding at April 30, 2018: 149,071,775 shares

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION:		iii

	Item 1. Consolidated Financial Statements (Unaudited)	iii

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	47

	Item 4. Controls and Procedures	49

PART II – OTHER INFORMATION:		50

	Item 1. Legal Proceedings	50

	Item 1A. Risk Factors	50

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	55

	Item 6. Exhibits	56

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements and information contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities, potential financing and our proposed acquisition of RSP Permian, Inc., a Delaware corporation (“RSP”). Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “will,” “goal” or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, whether as a result of new information, future events or otherwise, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Part II, Item 1A. Risk Factors” in this Quarterly Report and in “Part I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017, as well as those factors summarized below:

· risks associated with our proposed acquisition of RSP, including increased expenses, management distraction from our business, declines in the market price of our common stock and failure to realize the expected benefits of the transaction;

· failure, difficulties and delays in meeting conditions required for closing set forth in the Acquisition Agreement, as defined herein;

· risks associated with acquisitions, including liabilities associated with acquired properties or businesses and the ability to realize expected benefits;

· disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, natural gas liquids and natural gas and other processing and transportation considerations;

· declines in, or the sustained depression of, the prices we receive for our oil and natural gas;

· risks related to the concentration of our operations in the Permian Basin of southeast New Mexico and west Texas;

· evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;

· the costs and availability of equipment, resources, services and qualified personnel required to perform our drilling, completion and operating activities;

· drilling, completion and operating risks;

· environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

· the effects of government regulation, permitting and other legal requirements, including new legislation or regulation related to hydraulic fracturing, climate change, derivatives reform or the export of oil and natural gas;

· the impact of current and potential changes to federal or state tax rules and regulations, including the Tax Cuts and Jobs Act;

· potential financial losses or earnings reductions from our commodity price risk-management program;

· difficult and adverse conditions in the domestic and global capital and credit markets;

· the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our Credit Facility, as defined herein;

· the impact of potential changes in our credit ratings;

· uncertainties about our ability to successfully execute our business and financial plans and strategies;

· uncertainties about the estimated quantities of oil and natural gas reserves;

· uncertainties about our ability to replace reserves and economically develop our current reserves;

· general economic and business conditions, either internationally or domestically;

· competition in the oil and natural gas industry; and

· uncertainty concerning our assumed or possible future results of operations.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and the price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets at March 31, 2018 and December 31, 2017	1

Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017	2

Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2018	3

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017	4

Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


					March 31,	December 31,
(in millions, except share and per share amounts)					2018	2017
Assets
Current assets:
	Cash and cash equivalents			$	-	$	-
	Accounts receivable, net of allowance for doubtful accounts:
		Oil and natural gas			392		331
		Joint operations and other			260		212
	Inventory				11		14
	Derivative instruments				23		-
	Prepaid costs and other				33		35
			Total current assets		719		592
Property and equipment:
	Oil and natural gas properties, successful efforts method				22,023		21,267
	Accumulated depletion and depreciation				(8,658)		(8,460)
		Total oil and natural gas properties, net			13,365		12,807
	Other property and equipment, net				246		234
		Total property and equipment, net			13,611		13,041
Deferred loan costs, net					12		13
Intangible assets, net					22		26
Noncurrent derivative instruments					2		-
Other assets					15		60
	Total assets			$	14,381	$	13,732
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable - trade			$	33	$	43
	Bank overdrafts				72		116
	Revenue payable				185		183
	Accrued drilling costs				307		330
	Derivative instruments				248		277
	Other current liabilities				264		216
			Total current liabilities		1,109		1,165
Long-term debt					2,370		2,691
Deferred income taxes					941		687
Noncurrent derivative instruments					79		102
Asset retirement obligations and other long-term liabilities					144		172
Commitments and contingencies (Note 10)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 149,870,242 and
		149,324,849 shares issued at March 31, 2018 and December 31, 2017, respectively			-		-
	Additional paid-in capital				7,159		7,142
	Retained earnings				2,675		1,840
	Treasury stock, at cost; 799,644 and 598,049 shares at March 31, 2018 and
		December 31, 2017, respectively			(96)		(67)
			Total stockholders’ equity		9,738		8,915
	Total liabilities and stockholders’ equity			$	14,381	$	13,732

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

Concho Resources Inc.

Consolidated Statements of Operations

Unaudited


			Three Months Ended
			March 31,
(in millions, except per share amounts)				2018		2017
Operating revenues:
	Oil sales		$	793	$	502
	Natural gas sales			154		110
		Total operating revenues		947		612
Operating costs and expenses:
	Oil and natural gas production			130		87
	Production and ad valorem taxes			70		48
	Gathering, processing and transportation			11		-
	Exploration and abandonments			18		15
	Depreciation, depletion and amortization			317		283
	Accretion of discount on asset retirement obligations			2		2
	General and administrative (including non-cash stock-based compensation of $17 and
		$12 for the three months ended March 31, 2018 and 2017, respectively)		65		56
	(Gain) loss on derivatives			35		(286)
	Gain on disposition of assets, net			(723)		(654)
		Total operating costs and expenses		(75)		(449)
Income from operations				1,022		1,061
Other income (expense):
	Interest expense			(30)		(40)
	Other, net			97		-
		Total other income (expense)		67		(40)
Income before income taxes				1,089		1,021
	Income tax expense			(254)		(371)
Net income			$	835	$	650
Earnings per share:
	Basic net income		$	5.60	$	4.39
	Diluted net income		$	5.58	$	4.37

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

Concho Resources Inc.

Consolidated Statement of Stockholders’ Equity

Unaudited


			Common Stock			Additional								Total
			Issued			Paid-in		Retained			Treasury Stock			Stockholders’
(in millions, except share data)			Shares	Amount		Capital		Earnings			Shares	Amount		Equity
		(in thousands)								(in thousands)
BALANCE AT DECEMBER 31, 2017			149,325	$	-	$	7,142	$	1,840		598	$	(67)	$	8,915
	Net income		-		-		-		835		-		-		835
	Grants of restricted stock		112		-		-		-		-		-		-
	Performance unit share conversion		446		-		-		-		-		-		-
	Cancellation of restricted stock		(13)		-		-		-		-		-		-
	Stock-based compensation		-		-		17		-		-		-		17
	Purchase of treasury stock		-		-		-		-		202		(29)		(29)
BALANCE AT MARCH 31, 2018			149,870	$	-	$	7,159	$	2,675		800	$	(96)	$	9,738

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

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited


					Three Months Ended
					March 31,
(in millions)					2018		2017
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	835	$	650
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				317		283
		Accretion of discount on asset retirement obligations				2		2
		Exploration and abandonments, including dry holes				10		6
		Non-cash stock-based compensation expense				17		12
		Deferred income taxes				254		363
		Gain on disposition of assets, net				(723)		(654)
		(Gain) loss on derivatives				35		(286)
		Net settlements received from (paid on) derivatives				(112)		28
		Other				(96)		1
	Changes in operating assets and liabilities, net of acquisitions and dispositions:
			Accounts receivable			(81)		(6)
			Prepaid costs and other			(2)		(8)
			Inventory			3		-
			Accounts payable			(12)		7
			Revenue payable			2		8
			Other current liabilities			39		1
				Net cash provided by operating activities		488		407
CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to oil and natural gas properties					(474)		(286)
	Acquisitions of oil and natural gas properties					(13)		(171)
	Additions to property, equipment and other assets					(6)		(2)
	Proceeds from the disposition of assets					255		806
	Direct transaction costs for disposition of assets					(3)		(17)
	Distribution from equity method investment					148		-
				Net cash provided by (used in) investing activities		(93)		330
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from issuance of debt					662		105
	Payments of debt					(984)		(105)
	Purchase of treasury stock					(29)		(19)
	Decrease in bank overdrafts					(44)		-
				Net cash used in financing activities		(395)		(19)
				Net increase in cash and cash equivalents		-		718
Cash and cash equivalents at beginning of period						-		53
Cash and cash equivalents at end of period					$	-	$	771
NON-CASH INVESTING AND FINANCING ACTIVITIES:
	Issuance of common stock for business combinations				$	-	$	258

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 1. Organization and nature of operations

Concho Resources Inc. (the “Company”) is a Delaware corporation formed on February 22, 2006. The Company’s principal business is the acquisition, development, exploration and production of oil and natural gas properties primarily located in the Permian Basin of southeast New Mexico and west Texas.

Note 2. Summary of significant accounting policies

Principles of consolidation. The consolidated financial statements of the Company include the accounts of the Company and its 100 percent owned subsidiaries. The consolidated financial statements also included the accounts of a variable interest entity (“VIE”) where the Company was the primary beneficiary of the arrangements until the VIE structure dissolved. See Note 5 for additional information regarding the circumstances surrounding the VIE. The Company consolidates the financial statements of these entities. All material intercompany balances and transactions have been eliminated.

Reclassifications. Certain prior period amounts have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or total cash flows.

Use of estimates in the preparation of financial statements. Preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil 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, commodity price outlooks and prevailing market rates of other sources of income and costs. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of stock-based compensation, fair value of business combinations, fair value of nonmonetary transactions, fair value of derivative financial instruments and income taxes.

Interim financial statements. The accompanying consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2017 is derived from audited consolidated financial statements. In the opinion of management, the accompanying consolidated financial statements reflect all adjustments necessary to present fairly the Company’s consolidated financial statements. All such adjustments are of a normal, recurring nature. In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed in or omitted from these consolidated financial statements. Accordingly, these condensed notes to the consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

Cash equivalents. The Company considers all cash on hand, depository accounts held by banks, money market accounts and investments with an original maturity of three months or less to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

Equity method investments. The Company accounts for its equity method investments under the equity method of accounting and includes the investment balance in other assets on the consolidated balance sheets. Gains and losses incurred from the Company’s equity investments are recorded in other income on the consolidated statements of operations.

The Company owns a 23.75 percent membership interest in Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity that operates a crude oil gathering and transportation system in the Southern Delaware Basin. During the three months ended March 31, 2018, Oryx obtained a term loan of $800 million. The proceeds were used in part to fund a cash distribution to its

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

equity holders, of which the Company received a distribution of approximately $157 million. Of this amount, approximately $54 million fully offset the Company’s net investment in Oryx. The remaining distribution of approximately $103 million was recorded in other income on the Company’s consolidated statement of operations for the three months ended March 31, 2018 since the lenders to the term loan do not have recourse against the Company, and the Company has no contractual obligation to repay the distribution.

The Company’s net investment in Oryx was approximately $49 million at December 31, 2017. During the three months ended March 31, 2018 and 2017, the Company recorded income of approximately $5 million and $1 million, respectively.

In February 2017, the Company closed on the divestiture of its 50 percent membership interest in a midstream joint venture, Alpha Crude Connector, LLC (“ACC”), that constructed a crude oil gathering and transportation system in the Northern Delaware Basin. See Note 5 for additional information regarding the disposition of ACC.

Revenue recognition. On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”) using the modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment and does not have a material impact on the Company’s ongoing consolidated balance sheets, statements of operations, statement of stockholders’ equity, or statements of cash flows.

The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. All revenues are recognized in the geographical region of the Permian Basin. Prior to the adoption of ASC 606, the Company recorded oil and natural gas revenues at the time of physical transfer of such products to the purchaser, which for the Company is primarily at the wellhead. The Company followed the sales method of accounting for oil and natural gas sales, recognizing revenues based on the Company’s actual proceeds from the oil and natural gas sold to purchasers.

The Company enters into contracts with customers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At March 31, 2018, the Company had receivables related to contracts with customers of $392 million.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, “Revenue recognition” (“ASC 605”):


		Three Months Ended
		March 31, 2018
(in millions)		Under ASC 606		Under ASC 605		Increase (Decrease)

Operating revenues:
	Oil sales	$	793	$	791	$	2
	Natural gas sales		154		148		6

Operating costs and expenses:
	Oil and natural gas production		130		133		(3)
	Gathering, processing and transportation		11		-		11

Net income		$	835	$	835	$	-

Oil Contracts. The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in gathering, processing and transportation on the Company’s consolidated statements of operations as they represent payment for services performed outside of the contract with the customer.

Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under these contracts, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Company receives natural gas liquids and residue gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those costs, revenue is recognized on a gross basis, and the related costs are classified in gathering, processing and transportation on the Company’s consolidated statements of operations.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

General and administrative expense. The Company receives fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and records such reimbursements as reductions to general and administrative expense. Such fees totaled approximately $4 million for each of the three months ended March 31, 2018 and 2017.

New accounting pronouncements issued but not yet adopted. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842)” (“ASU 2016-02”), which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Lease expense recognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company does not plan to early adopt the standard. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. The Company has substantially completed the process of reviewing and determining the contracts to which this new guidance applies. The Company is currently enhancing its accounting system in order to track and calculate additional information necessary for adoption of this standard. The Company believes this new guidance will have a moderate impact on its consolidated balance sheets due to the recognition of right-of-use assets and lease liabilities that are not recognized under currently applicable guidance.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). The Company enters into land easements on a routine basis as part of its ongoing operations and has many such agreements currently in place; however, the Company does not currently account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, the Company will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, the Company will assess any new land easements to determine whether the arrangement should be accounted for as a lease.

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. This guidance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. The Company does not believe this new guidance will have a material impact on its consolidated financial statements.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 3. Exploratory well costs

The Company capitalizes exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. After an exploratory well has been completed and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. See Note 16 for the proved and unproved components of oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments expense in the consolidated statements of operations.

The following table reflects the Company’s net capitalized exploratory well activity during the three months ended March 31, 2018:


		Three Months Ended
(in millions)		March 31, 2018

Beginning capitalized exploratory well costs		$	182
	Additions to exploratory well costs pending the determination of proved reserves		163
	Reclassifications due to determination of proved reserves		(76)
	Disposition of wells		(16)
Ending capitalized exploratory well costs		$	253

The following table provides an aging at March 31, 2018 and December 31, 2017 of capitalized exploratory well costs based on the date drilling was completed:


		March 31,		December 31,
(in millions, except number of projects)		2018		2017

Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	239	$	180
Capitalized exploratory well costs that have been capitalized for a period greater
	than one year		14		2
	Total capitalized exploratory well costs	$	253	$	182
Number of projects with exploratory well costs that have been capitalized for a period greater
	than one year		2		2

Northern Delaware Basin project. At March 31, 2018, the Company had approximately $12 million of suspended well costs greater than one year recorded for a well drilled in the first quarter of 2017. This well is part of a multi-well pad project. This well was completed during the three months ended March 31, 2018 and began economically producing subsequent to March 31, 2018.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 4. RSP Acquisition

On March 27, 2018, the Company and RSP Permian, Inc. (“RSP”) entered into an Agreement and Plan of Merger (the “Acquisition Agreement”) under which the Company will acquire RSP through an all-stock transaction (the “RSP Acquisition”). The Company expects the RSP Acquisition to be completed during the third quarter of 2018, subject to the satisfaction of certain regulatory approvals and other customary closing conditions, and will account for the RSP Acquisition as a business combination using the acquisition method of accounting.

If the RSP Acquisition is completed, RSP shareholders will automatically receive 0.320 of a share of the Company’s common stock in exchange for one share of RSP common stock. This exchange ratio is fixed and will not be adjusted for changes in the Company’s or RSP’s stock price. The Company estimates that it will issue up to approximately 51 million shares in connection with the RSP Acquisition.

The Acquisition Agreement also provides the Company certain termination rights under which it may exercise and effectively terminate the Acquisition Agreement. Should certain unlikely events occur under the specified circumstances outlined in the Acquisition Agreement, the Company will be required to pay RSP a termination fee of $350 million.

Note 5. Acquisitions, divestitures and nonmonetary transactions

During the three months ended March 31, 2018, the Company entered into the following transactions:

February 2018 acquisition and divestiture. In February 2018, the Company closed on an acquisition treated as a business combination where it received producing wells with approximately 5 MBoepd along with approximately 21,000 net acres, primarily located in the Midland Basin. As consideration for the non-cash acquisition, the Company divested of approximately 34,000 net acres, primarily comprised of approximately 32,000 net acres in the Northern Delaware Basin, with current production of 3 MBoepd. The business 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 preliminary non-cash gain of approximately $575 million, subject to customary post-closing adjustments. The approximately $755 million fair value of assets acquired comprised of approximately $245 million of proved properties, approximately $480 million of unproved properties and approximately $30 million of other assets. The fair value of the assets received in the business combination approximated the fair value of assets disposed.

Southern Delaware Basin divestitures. In January 2018, the Company closed on two asset sales transactions of certain non-core assets in Reeves and Ward Counties with combined preliminary proceeds of approximately $280 million, subject to customary post-closing adjustments. After direct transaction costs, the Company recorded a pre-tax gain of approximately $134 million, which is included in gain on disposition of assets, net on its consolidated statement of operations for the three months ended March 31, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

These divestitures completed a transaction structured as a reverse like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031 of the Internal Revenue Code of 1986, as amended, that the Company entered into concurrent with a July 2017 acquisition in the Midland Basin. In connection with the Reverse 1031 Exchange, the Company assigned the ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. The Company operated the properties pursuant to a management agreement with the VIE. At December 31, 2017 and prior to the completion of the reverse like-kind exchange in January 2018, the Company was determined to be the primary beneficiary of the VIE, as the Company had the ability to control the activities that most significantly impact the VIE’s economic performance.

Upon completion of the Reverse 1031 Exchange in January 2018, the assets and liabilities attributable to the acquisition that were held by the VIE were conveyed to the Company, and the VIE structure was dissolved.

Nonmonetary transactions. During the three months ended March 31, 2018, the Company completed multiple nonmonetary transactions. These transactions included the exchange of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, the Company recorded pre-tax gains of approximately $14 million.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

During the three months ended March 31, 2017, the Company entered into the following transactions:

Northern Delaware Basin acquisition. In January and April 2017, the Company closed on the two-part acquisition in the Northern Delaware Basin. As consideration for the entire acquisition, the Company paid approximately $160 million in cash and issued to the seller approximately 2.2 million shares of its common stock with an approximate value of $291 million.

ACC divestiture. In February 2017, the Company closed on the divestiture of its ownership interest in ACC. The Company and its joint venture partner entered into separate agreements to sell 100 percent of their respective ownership interests in ACC. After adjustments for debt and working capital, the Company received cash proceeds from the sale of approximately $803 million. After direct transaction costs, the Company recorded a pre-tax gain of approximately $656 million, which is included in gain on disposition of assets, net on its consolidated statement of operations for the three months ended March 31, 2017. The Company’s net investment in ACC at the time of closing was approximately $129 million.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 6. Stock incentive plan

The Company’s 2015 Stock Incentive Plan (“the Plan”) provides for granting stock options, restricted stock awards and performance awards to directors, officers and employees of the Company. The restricted stock-based compensation awards generally vest over a period ranging from one to eight years. Performance unit awards vest over a period of three years. Shares issued as a result of awards granted under the Plan are generally new common shares.

A summary of the Company’s restricted stock shares and performance unit activity under the Plan for the three months ended March 31, 2018 is presented below:


		Restricted		Performance
		Stock Shares		Units

Outstanding at December 31, 2017			1,149,246		247,647
	Awards granted (a)		112,024		111,490
	Awards cancelled / forfeited		(13,463)		-
	Lapse of restrictions		(106,094)		-
Outstanding at March 31, 2018		1,141,713		359,137

(a) Weighted average grant date fair value per share/unit		$	151.37	$	216.03

The Company used the following assumptions to estimate the fair value of performance unit awards granted during the three months ended March 31, 2018 and 2017:


	Three Months Ended
	March 31,
	2018	2017



Risk-free interest rate	2.00%	1.47%
Range of volatilities	23.5% - 64.0%	24.8% - 60.2%

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at March 31, 2018:


(in millions)

Remaining 2018		$	50
2019			37
2020			17
Thereafter			3
	Total	$	107

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 7. Disclosures about fair value measurements

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets 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: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, collars and floors, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) current market and contractual prices for the underlying instruments and (iv) volatility factors, as well as other relevant economic measures.

Level 3: Prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value, (iii) volatility factors and (iv) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Financial Assets and Liabilities Measured at Fair Value

The following table presents the carrying amounts and fair values of the Company’s financial instruments at March 31, 2018 and December 31, 2017:


			March 31, 2018				December 31, 2017
			Carrying		Fair		Carrying		Fair
(in millions)			Value		Value		Value		Value

	Assets:
		Derivative instruments	$	25	$	25	$	-	$	-

	Liabilities:
		Derivative instruments	$	327	$	327	$	379	$	379
		Credit facility	$	-	$	-	$	322	$	322
		$600 million 4.375% senior notes due 2025 (a)	$	593	$	604	$	593	$	624
		$1,000 million 3.75% senior notes due 2027 (a)	$	988	$	971	$	987	$	1,012
		$800 million 4.875% senior notes due 2047 (a)	$	789	$	838	$	789	$	874


(a)	The carrying value includes associated deferred loan costs and any discount.

Credit facility. The carrying amount of the Company’s credit facility, as amended and restated (the “Credit Facility”), approximates its fair value, as the applicable interest rates are variable and reflective of market rates.

Senior notes. The fair values of the Company’s senior notes are based on quoted market prices. The debt securities are not actively traded and, therefore, are classified as Level 2 in the fair value hierarchy.

Other financial assets and liabilities. The Company has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Derivative instruments. The fair value of the Company’s derivative instruments is estimated by management considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following tables summarize (i) the valuation of each of the Company’s financial instruments by required fair value hierarchy levels and (ii) the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at March 31, 2018 and December 31, 2017. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.


March 31, 2018
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet

	Assets:
		Current:
			Commodity derivatives		$	-	$	111	$	-	$	111	$	(88)	$	23
		Noncurrent:
			Commodity derivatives			-		29		-		29		(27)		2

	Liabilities:
		Current:
			Commodity derivatives			-		(336)		-		(336)		88		(248)
		Noncurrent:
			Commodity derivatives			-		(106)		-		(106)		27		(79)

	Net derivative instruments				$	-	$	(302)	$	-	$	(302)	$	-	$	(302)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited


December 31, 2017
				Fair Value Measurements Using												Net
				Quoted Prices										Gross		Fair Value
				in Active				Significant						Amounts		Presented
				Markets for				Other		Significant				Offset in the		in the
				Identical				Observable		Unobservable		Total		Consolidated		Consolidated
				Assets				Inputs		Inputs		Fair		Balance		Balance
(in millions)				(Level 1)				(Level 2)		(Level 3)		Value		Sheet		Sheet

	Assets:
		Current:
			Commodity derivatives		$	-	$	13	$	-	$	13	$	(13)	$	-
		Noncurrent:
			Commodity derivatives			-		1		-		1		(1)		-

	Liabilities:
		Current:
			Commodity derivatives			-		(290)		-		(290)		13		(277)
		Noncurrent:
			Commodity derivatives			-		(103)		-		(103)		1		(102)

	Net derivative instruments				$	-	$	(379)	$	-	$	(379)	$	-	$	(379)

Concentrations of credit risk. At March 31, 2018, the Company’s primary concentrations of credit risk are the risk of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations.

The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 8 for additional information regarding the Company’s derivative activities and counterparties.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 8. Derivative financial instruments

The Company uses derivative financial instruments to manage its exposure to commodity price fluctuations. Commodity derivative instruments are used to (i) reduce the effect of the volatility of price changes on the oil and natural gas the Company produces and sells, (ii) support the Company’s capital budget and expenditure plans and (iii) support the economics associated with acquisitions. The Company does not enter into derivative financial instruments for speculative or trading purposes. The Company also enters into fixed-price forward physical power purchase contracts to manage the volatility of the price of power needed for ongoing operations. The Company may also enter into physical delivery contracts to effectively provide commodity price hedges. Because these physical contracts are not expected to be net cash settled, the Company has elected normal purchase or normal sale treatment and such contracts are thus recorded at cost.

The Company does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Company reflects changes in the fair value of its derivative instruments in its consolidated statements of operations as they occur.

The following table summarizes the amounts reported in earnings related to the commodity derivative instruments for the three months ended March 31, 2018 and 2017:


			Three Months Ended
			March 31,
(in millions)				2018		2017

*Gain (loss) on derivatives:*
	Oil derivatives		$	(33)	$	266
	Natural gas derivatives			(2)		20
		Total	$	(35)	$	286


The following table represents the Company’s net cash receipts from (payments on) derivatives for the three months ended March 31, 2018 and 2017:



			Three Months Ended
			March 31,
(in millions)				2018		2017

*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	(113)	$	31
	Natural gas derivatives			1		(3)
		Total	$	(112)	$	28

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Commodity derivative contracts at March 31, 2018. The following table sets forth the Company’s outstanding derivative contracts at March 31, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at March 31, 2018 are expected to settle by December 31, 2020.


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total
Oil Price Swaps: (a)
	*2018:*
		Volume (Bbl)				10,724,170		9,496,318		8,658,007		28,878,495
		Price per Bbl			$	53.79	$	53.56	$	53.20	$	53.54
	*2019:*
		Volume (Bbl)		7,849,000		7,366,500		6,950,000		6,601,000		28,766,500
		Price per Bbl	$	53.28	$	53.21	$	53.21	$	53.18	$	53.22
	*2020:*
		Volume (Bbl)		1,482,000		1,416,000		1,357,000		1,309,000		5,564,000
		Price per Bbl	$	54.59	$	54.60	$	54.62	$	54.62	$	54.61
Oil Basis Swaps: (b)
	*2018:*
		Volume (Bbl)				9,492,000		8,465,000		7,757,000		25,714,000
		Price per Bbl			$	(0.81)	$	(0.85)	$	(0.89)	$	(0.85)
	*2019:*
		Volume (Bbl)		7,050,000		6,687,500		6,394,000		5,933,000		26,064,500
		Price per Bbl	$	(0.95)	$	(0.96)	$	(0.97)	$	(1.01)	$	(0.97)
	*2020:*
		Volume (Bbl)		2,730,000		2,730,000		2,760,000		2,760,000		10,980,000
		Price per Bbl	$	(0.08)	$	(0.08)	$	(0.08)	$	(0.08)	$	(0.08)
Natural Gas Price Swaps: (c)
	*2018:*
		Volume (MMBtu)				16,979,000		15,740,000		14,778,000		47,497,000
		Price per MMBtu			$	3.04	$	3.04	$	3.03	$	3.04
	*2019:*
		Volume (MMBtu)		4,591,533		4,501,387		4,418,537		4,329,535		17,840,992
		Price per MMBtu	$	2.86	$	2.86	$	2.86	$	2.86	$	2.86


(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average
	futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI.
(c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the creditworthiness of counterparties to its derivative instruments. The Company believes that all of its derivative counterparties are currently acceptable credit risks. The Company is not required to provide credit support or collateral to any counterparties under its derivative contracts, nor are they required to provide credit support to the Company.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 9. Debt

The Company’s debt consisted of the following at March 31, 2018 and December 31, 2017:


				March 31,		December 31,
(in millions)				2018		2017

Credit facility			$	-	$	322
4.375% unsecured senior notes due 2025 (a)				600		600
3.75% unsecured senior notes due 2027				1,000		1,000
4.875% unsecured senior notes due 2047				800		800
Unamortized original issue discount				(5)		(6)
Senior notes issuance costs, net				(25)		(25)
	Less: current portion			-		-
		Total long-term debt	$	2,370	$	2,691


(a)	For each of the twelve-month periods beginning on January 15, 2020, 2021, 2022, 2023 and thereafter, these notes are
	callable at 103.281%, 102.188%, 101.094% and 100%, respectively.

Credit facility. The Company’s Credit Facility has a maturity date of May 9, 2022. At March 31, 2018, the Company’s commitments from its bank group were $2.0 billion.

Senior notes. Interest on the Company’s senior notes is paid in arrears semi-annually. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company’s 100 percent owned subsidiaries, subject to customary release provisions as described in Note 14.

At March 31, 2018, the Company was in compliance with the covenants under all of its debt instruments.

Principal maturities of long-term debt. Principal maturities of long-term debt outstanding at March 31, 2018 were as follows:


(in millions)

Remaining 2018		$	-
2019			-
2020			-
2021			-
2022			-
2023			-
Thereafter			2,400
	Total	$	2,400

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Interest expense. The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2018 and 2017:


		Three Months Ended
		March 31,
(in millions)			2018		2017

Cash payments for interest		$	18	$	61
Non-cash interest			1		3
Net changes in accruals			12		(24)
	Interest costs incurred		31		40
Less: capitalized interest			(1)		-
	Total interest expense	$	30	$	40

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 10. Commitments and contingencies

Legal actions. The Company is a 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 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.

Severance tax, royalty and joint interest audits. The Company is subject to routine severance, royalty and joint interest audits from regulatory bodies and non-operators and makes accruals as necessary for estimated exposure when deemed probable and estimable. Additionally, the Company is subject to various possible contingencies that arise primarily from interpretations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, allowable costs under joint interest arrangements and other matters. Although the Company believes that it has estimated its exposure with respect to the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.

Commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds. These contractual arrangements relate to purchase agreements the Company has entered into including drilling commitments, water commitment agreements, throughput volume delivery commitments, fixed and variable power commitments, sand commitment agreements, fixed asset commitments and maintenance commitments. The following table summarizes the Company’s commitments at March 31, 2018:


(in millions)

Remaining 2018		$	32
2019			64
2020			55
2021			52
2022			21
2023			17
Thereafter			56
	Total	$	297

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Operating leases. The Company leases vehicles, equipment and office facilities under non-cancellable operating leases. Lease payments associated with these operating leases were approximately $3 million for each of the three months ended March 31, 2018 and 2017.

Future minimum lease commitments under non-cancellable operating leases at March 31, 2018 were as follows:


(in millions)

Remaining 2018		$	8
2019			9
2020			8
2021			6
2022			1
2023			-
Thereafter			1
	Total	$	33

Note 11. Income taxes

The Company’s provision for income taxes for the three months ended March 31, 2018 and 2017 is based on the estimated annual effective tax rate plus discrete items. The effective income tax rates were 23 percent and 36 percent for the three months ended March 31, 2018 and 2017, respectively.

The difference between the Company’s effective tax rates for the three months ended March 31, 2018 and 2017 is primarily due to (i) the reduction of the U.S. federal statutory corporate income tax rate from 35 percent to 21 percent, (ii) the impact of changes in non-deductible expenses and (iii) state income taxes, net of federal income tax benefits. The Company recorded a discrete income tax benefit related to stock-based awards of approximately $2 million and $7 million for the three months ended March 31, 2018 and 2017, respectively.

On December 22, 2017, the President of the United States signed into law the “Tax Cuts and Jobs Act” (“TCJA”), which enacted significant changes to federal income tax laws, including a decrease in the federal corporate income tax rate from 35 percent to 21 percent, which was effective January 1, 2018. In accordance with Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”), the Company recorded, based on reasonable estimates, a $398 million decrease to its income tax provision at December 31, 2017. This provisional amount related to the re-measurement of certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future.

At March 31, 2018, the Company has not completed its accounting for all of the tax effects of the TCJA and has not made an adjustment to the provisional tax benefit recorded under SAB 118 at December 31, 2017. In addition, the Company has considered in its estimated annual effective tax rate for 2018 the impact of the statutory changes enacted by the TCJA, including reasonable estimates of those provisions effective for the 2018 tax year.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 12. Related party transactions

The Company paid royalties on certain properties to a partnership in which a director of the Company is the general partner and owns a 3.5 percent partnership interest. These payments were reported in the Company’s consolidated statements of operations and totaled approximately $1 million and $2 million for the three months ended March 31, 2018 and 2017, respectively.

Note 13. Earnings per share

The Company uses the two-class method of calculating earnings per share because certain of the Company’s unvested share-based awards qualify as participating securities.

The Company’s basic earnings per share attributable to common stockholders is computed as (i) net income (loss) as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings per share attributable to common stockholders is computed as (i) basic earnings attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted common shares outstanding.

The following table reconciles the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the three months ended March 31, 2018 and 2017, respectively, under the two-class method:



			Three Months Ended
			March 31,
(in millions)			2018		2017

Net income as reported			$	835	$	650
Participating basic earnings (a)				(6)		(5)
	Basic earnings attributable to common stockholders			829		645
Reallocation of participating earnings				-		-
	Diluted earnings attributable to common stockholders		$	829	$	645


(a)		Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity holders of the Company. Participating earnings represent the distributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

The following table is a reconciliation of the basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2018 and 2017:



			Three Months Ended
			March 31,
(in thousands)			2018	2017

*Weighted average common shares outstanding:*
	Basic		147,925	146,838
		Dilutive common stock options	-	12
		Dilutive performance units	537	701
	Diluted		148,462	147,551

The following table is a summary of the performance units that were not included in the computation of diluted earnings per share, as inclusion of these items would be antidilutive:



		Three Months Ended
		March 31,
(in thousands)		2018	2017

*Number of antidilutive units:*
	Antidilutive performance units	-	108

Performance unit awards. The number of shares of common stock that will ultimately be issued for performance units will be determined by a combination of (i) comparing the Company’s total shareholder return relative to the total shareholder return of a predetermined group of peer companies at the end of the performance period and (ii) the Company’s absolute total shareholder return at the end of the performance period. The performance period is 36 months. The actual payout of shares will be between zero and 300 percent.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 14. Subsidiary guarantors

At March 31, 2018, certain of the Company’s 100 percent owned subsidiaries have fully and unconditionally guaranteed the Company’s senior notes. The indentures governing the Company’s senior notes provide that the guarantees of its subsidiary guarantors will be released in certain customary circumstances including (i) in connection with any sale, exchange or other disposition, whether by merger, consolidation or otherwise, of the capital stock of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, such that, after giving effect to such transaction, such guarantor would no longer constitute a subsidiary of the Company, (ii) in connection with any sale, exchange or other disposition (other than a lease) of all or substantially all of the assets of that guarantor to a person that is not the Company or a restricted subsidiary of the Company, (iii) upon the merger of a guarantor into the Company or any other guarantor or the liquidation or dissolution of a guarantor, (iv) if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture, (v) upon legal defeasance or satisfaction and discharge of the indenture and (vi) upon written notice of such release or discharge by the Company to the trustee following the release or discharge of all guarantees by such guarantor of any indebtedness that resulted in the creation of such guarantee, except a discharge or release by or as a result of payment under such guarantee.

See Note 9 for a summary of the Company’s senior notes. In accordance with practices accepted by the SEC, the Company has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. In addition, one of the Company’s subsidiaries does not guarantee the Company’s senior notes and is included in the Company’s consolidated financial statements. This entity is a 100 percent owned subsidiary that was recently acquired, and is referred to as a “Subsidiary Non-Guarantor” in the tables below. An additional entity did not guarantee the Company’s senior notes at December 31, 2017. This entity was a VIE that was formed to effectuate a tax-free exchange of assets. During the three months ended March 31, 2018, the Reverse 1031 Exchange was completed and all assets and liabilities attributable to the VIE were conveyed to the Company. This entity did not guarantee the Company’s senior notes until the conveyance was completed. See Note 5 for additional information regarding the completion of the Reverse 1031 Exchange.

The following condensed consolidating balance sheets at March 31, 2018 and December 31, 2017, condensed consolidating statements of operations for the three months ended March 31, 2018 and 2017 and condensed consolidating statements of cash flows for the three months ended March 31, 2018 and 2017, present financial information for Concho Resources Inc. as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the subsidiary non-guarantors on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. All current and deferred income taxes are recorded on Concho Resources Inc., as the subsidiaries are flow-through entities for income tax purposes. The subsidiary guarantors and subsidiary non-guarantors are not restricted from making distributions to the Company.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited


Condensed Consolidating Balance Sheet
March 31, 2018


			Parent	Subsidiary			Subsidiary		Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor			Entries		Total

ASSETS
Accounts receivable - related parties		$	8,390	$	(657)	$	-	$	(7,733)	$	-
Other current assets			28		691		-		-		719
Oil and natural gas properties, net			-		13,348		17		-		13,365
Property and equipment, net			-		246		-		-		246
Investment in subsidiaries			4,355		-		-		(4,355)		-
Other long-term assets			25		26		-		-		51
	Total assets	$	12,798	$	13,654	$	17	$	(12,088)	$	14,381

LIABILITIES AND EQUITY
Accounts payable - related parties		$	(657)	$	8,373	$	17	$	(7,733)	$	-
Other current liabilities			327		782		-		-		1,109
Long-term debt			2,370		-		-		-		2,370
Other long-term liabilities			1,020		144		-		-		1,164
Equity			9,738		4,355		-		(4,355)		9,738
	Total liabilities and equity	$	12,798	$	13,654	$	17	$	(12,088)	$	14,381

Condensed Consolidating Balance Sheet
December 31, 2017


			Parent	Subsidiary			Subsidiary	Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantors			Entries		Total

ASSETS
Accounts receivable - related parties		$	8,836	$	(669)	$	-	$	(8,167)	$	-
Other current assets			6		576		10		-		592
Oil and natural gas properties, net			-		12,192		615		-		12,807
Property and equipment, net			-		234		-		-		234
Investment in subsidiaries			3,202		-		-		(3,202)		-
Other long-term assets			23		76		-		-		99
	Total assets	$	12,067	$	12,409	$	625	$	(11,369)	$	13,732

LIABILITIES AND EQUITY
Accounts payable - related parties		$	(669)	$	8,223	$	613	$	(8,167)	$	-
Other current liabilities			341		821		3		-		1,165
Long-term debt			2,691		-		-		-		2,691
Other long-term liabilities			789		166		6		-		961
Equity			8,915		3,199		3		(3,202)		8,915
	Total liabilities and equity	$	12,067	$	12,409	$	625	$	(11,369)	$	13,732

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited


Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2018


			Parent		Subsidiary		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Non-Guarantor		Entries		Total

Total operating revenues		$	-	$	942	$	5	$	-	$	947
Total operating costs and expenses			(34)		112		(3)		-		75
	Income (loss) from operations		(34)		1,054		2		-		1,022
Interest expense			(30)		-		-		-		(30)
Other, net			1,153		97		-		(1,153)		97
	Income before income taxes		1,089		1,151		2		(1,153)		1,089
Income tax expense			(254)		-		-		-		(254)
	Net income	$	835	$	1,151	$	2	$	(1,153)	$	835

Condensed Consolidating Statement of Operations
Three Months Ended March 31, 2017


			Parent		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Entries		Total

Total operating revenues		$	-	$	612	$	-	$	612
Total operating costs and expenses			285		164		-		449
	Income from operations		285		776		-		1,061
Interest expense			(40)		-		-		(40)
Other, net			776		-		(776)		-
	Income before income taxes		1,021		776		(776)		1,021
Income tax expense			(371)		-		-		(371)
	Net income	$	650	$	776	$	(776)	$	650

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited


Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2018


			Parent	Subsidiary		Subsidiary			Consolidating
(in millions)			Issuer	Guarantors		Non-Guarantor				Entries		Total

Net cash flows provided by operating activities		$	351	$	137		$	-	$	-	$	488
Net cash flows used in investing activities			-		(93)			-		-		(93)
Net cash flows used in financing activities			(351)		(44)			-		-		(395)
	Net increase in cash and cash equivalents		-		-			-		-		-
	Cash and cash equivalents at beginning of period		-		-			-		-		-
	Cash and cash equivalents at end of period	$	-	$	-		$	-	$	-	$	-

Condensed Consolidating Statement of Cash Flows
Three Months Ended March 31, 2017


			Parent		Subsidiary		Consolidating
(in millions)			Issuer		Guarantors		Entries		Total

Net cash flows provided by operating activities		$	19	$	388	$	-	$	407
Net cash flows provided by investing activities			-		330		-		330
Net cash flows used in financing activities			(19)		-		-		(19)
	Net increase in cash and cash equivalents		-		718		-		718
	Cash and cash equivalents at beginning of period		-		53		-		53
	Cash and cash equivalents at end of period	$	-	$	771	$	-	$	771

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 15. Subsequent events

New commodity derivative contracts. After March 31, 2018, the Company entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of the Company’s estimated future production:


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total

Oil Price Swaps: (a)
	*2018:*
		Volume (Bbl)				729,000		659,000		417,000		1,805,000
		Price per Bbl			$	64.92	$	64.76	$	64.54	$	64.77
	*2019:*
		Volume (Bbl)		443,000		328,000		257,000		217,000		1,245,000
		Price per Bbl	$	59.81	$	59.71	$	59.46	$	59.34	$	59.63
	*2020:*
		Volume (Bbl)		1,244,000		1,185,000		1,131,000		1,104,000		4,664,000
		Price per Bbl	$	56.05	$	56.01	$	55.95	$	55.92	$	55.98
Oil Basis Swaps: (b)
	*2019:*
		Volume (Bbl)		630,000		637,000		644,000		644,000		2,555,000
		Price per Bbl	$	(3.26)	$	(3.26)	$	(3.26)	$	(3.26)	$	(3.26)
Natural Gas Price Swaps: (c)
	*2018:*
		Volume (MMBtu)				1,200,000		3,680,000		3,680,000		8,560,000
		Price per MMBtu			$	2.88	$	2.88	$	2.88	$	2.88
	*2019:*
		Volume (MMBtu)		2,700,000		2,730,000		2,760,000		2,760,000		10,950,000
		Price per MMBtu	$	2.75	$	2.75	$	2.75	$	2.75	$	2.75
	*2020:*
		Volume (MMBtu)		1,820,000		1,820,000		1,840,000		1,840,000		7,320,000
		Price per MMBtu	$	2.70	$	2.70	$	2.70	$	2.70	$	2.70


(a)	The index prices for the oil price swaps are based on the NYMEX – WTI monthly average futures price.
(b)	The basis differential price is between Midland – WTI and Cushing – WTI.
(c)	The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

March 31, 2018

Unaudited

Note 16. Supplementary information

Capitalized costs


			March 31,		December 31,
(in millions)			2018		2017

*Oil and natural gas properties:*
	Proved		$	18,907	$	18,565
	Unproved			3,116		2,702
	Less: accumulated depletion			(8,658)		(8,460)
		Net capitalized costs for oil and natural gas properties	$	13,365	$	12,807	(a)


(a)	Approximately $135 million of the balance at December 31, 2017 relates to assets held for sale that were disposed of
	during January 2018.

Costs incurred for oil and natural gas producing activities


		Three Months Ended
		March 31,
(in millions)		2018		2017

Property acquisition costs:
	Proved	$	-	$	127
	Unproved		13		306
Exploration			243		235
Development			207		158
	Total costs incurred for oil and natural gas properties	$	463	$	826

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our historical consolidated financial statements and notes.

Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. Our core operations are primarily focused in the Permian Basin of southeast New Mexico and west Texas. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends. We are actively developing our resource base by utilizing extended length lateral drilling, enhanced completion techniques, multi-well pad locations and large-scale development projects throughout our four core operating areas: the Northern Delaware Basin, the Southern Delaware Basin, the Midland Basin and the New Mexico Shelf. Oil comprised 60 percent of our 840 MMBoe of estimated proved reserves at December 31, 2017 and 63 percent of our 21 MMBoe of production for the three months ended March 31, 2018. We seek to operate the wells in which we own an interest, and we operated wells that accounted for 92 percent of our proved developed producing reserves and 79 percent of our 8,152 gross wells at December 31, 2017. By controlling operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and stimulation methods used.

Financial and Operating Performance

Our financial and operating performance for the three months ended March 31, 2018 and 2017 included the following highlights:

· Net income was $835 million ($5.58 per diluted share) as compared to $650 million ($4.37 per diluted share) for the first three months of 2018 and 2017, respectively. The increase was primarily due to:

• $335 million increase in oil and natural gas revenues as a result of a 26 percent increase in production and a 23 percent increase in commodity price realizations per Boe (excluding the effects of derivative activities);

• $117 million decrease in our income tax provision primarily due to the lower U.S. federal statutory corporate income tax rate as a result of the Tax Cuts and Jobs Act (the “TCJA”) for the three months ended March 31, 2018, as compared to 2017;

• $97 million increase in other income, primarily due to a gain of approximately $103 million on the equity method investment distribution received from Oryx Southern Delaware Holdings, LLC (“Oryx”); and

• $69 million net increase in gain on disposition of assets due to a gain of approximately $723 million during the three months ended March 31, 2018 primarily due to our February 2018 acquisition and divestiture and Southern Delaware Basin divestitures, as compared to a gain of approximately $654 million during 2017 primarily due to our disposition of Alpha Crude Connector, LLC (“ACC”);

partially offset by:

• $321 million change in (gain) loss on derivatives due to a $35 million loss on derivatives during the three months ended March 31, 2018, as compared to a $286 million gain during 2017;

• $43 million increase in production expense, primarily due to (i) increased production associated with our wells successfully drilled and completed in 2017 and 2018, (ii) our acquisitions and nonmonetary transactions during the last nine months of 2017 and first quarter of 2018 and (iii) increased cost of services;

• $34 million increase in depreciation, depletion and amortization expense, primarily due to an increase in production, partially offset by a decrease in the depletion rate per Boe; and

• $22 million increase in production and ad valorem tax expense, primarily due to increased production taxes as a result of increased oil and natural gas sales.

· Average daily sales volumes of 228 MBoe per day during the first three months of 2018 increased 26 percent as compared to 181 MBoe per day during 2017.

· Net cash provided by operating activities increased by approximately $81 million to $488 million for the first three months of 2018, as compared to $407 million in the first three months of 2017, primarily due to an increase in oil and natural gas revenues, partially offset by (i) changes related to cash settlements on derivatives, (ii) negative variances in working capital, (iii) increased production expense and (iv) increased production tax expense.

Commodity Prices

Our results of operations are heavily influenced by commodity prices. Commodity prices may fluctuate widely in response to (i) relatively minor changes in the supply of and demand for oil, natural gas and natural gas liquids, (ii) market uncertainty and (iii) a variety of additional factors that are beyond our control. Factors that may impact future commodity prices, including the price of oil, natural gas and natural gas liquids, include, but are not limited to:

· the overall global demand for oil, natural gas and natural gas liquids;

· the domestic and foreign supply of oil, natural gas and natural gas liquids;

· the overall North American oil, natural gas and natural gas liquids supply and demand fundamentals, including:

· the U.S. economy,

· weather conditions, and

· liquefied natural gas deliveries to and exports from the United States;

· economic conditions worldwide;

· the level of global inventories;

· political and economic developments in oil and natural gas producing regions, including Africa, South America and the Middle East;

· the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to influence global oil supply levels;

· risks related to the concentration of our operations in the Permian Basin of southeast New Mexico and west Texas and the level of commodity inventory in the Permian Basin;

· the proximity, capacity, cost and availability of pipelines and other transportation facilities, as well as the availability of commodity processing and gathering and refining capacity;

· technological advances affecting energy consumption and energy supply;

· the effect of energy conservation efforts;

· political and economic events that directly or indirectly impact the relative strength or weakness of the U.S. dollar, on which oil prices are benchmarked globally, against foreign currencies;

· domestic and foreign governmental regulations, including limits on the United States’ ability to export crude oil, and taxation;

· the cost and availability of products and personnel needed for us to produce oil and natural gas, including rigs, crews, sand, water and water disposal;

· the quality of the oil we produce; and

· the price and availability of alternative fuels.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Notes 8 and 15 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commodity derivative positions at March 31, 2018 and additional derivative contracts entered into subsequent to March 31, 2018, respectively.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. The average oil price was higher and the average gas price was lower during the comparable periods of 2018 measured against 2017, respectively. The following table sets forth the average New York Mercantile Exchange (“NYMEX”) oil and natural gas prices for the three months ended March 31, 2018 and 2017, as well as the high and low NYMEX prices for the same periods:



			Three Months Ended
			March 31,
			2018		2017

Average NYMEX prices:
	Oil (Bbl)		$	62.96	$	51.95
	Natural gas (MMBtu)		$	2.84	$	3.08

High and Low NYMEX prices:
	*Oil (Bbl):*
		High	$	66.14	$	54.45
		Low	$	59.19	$	47.34
	*Natural gas (MMBtu):*
		High	$	3.63	$	3.72
		Low	$	2.55	$	2.56

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $68.64 and $62.06 per Bbl and $2.82 and $2.66 per MMBtu, respectively, during the period from April 1, 2018 to April 30, 2018. At April 30, 2018, the NYMEX oil price and NYMEX natural gas price were $68.57 per Bbl and $2.76 per MMBtu, respectively.

Historically, and during the three months ended March 31, 2018, we derived a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids was $27.64 per Bbl and $24.19 per Bbl during the three months ended March 31, 2018 and 2017, respectively.

Recent Events

RSP Acquisition. On March 27, 2018, we and RSP Permian, Inc. (“RSP”) entered into an Agreement and Plan of Merger (the “Acquisition Agreement”) under which we will acquire RSP through an all-stock transaction (the “RSP Acquisition”). Under the terms of the Acquisition Agreement, shareholders of RSP will receive 0.320 of a share of our common stock in exchange for one share of RSP common stock. We estimate that we will issue up to 51 million shares in connection with the RSP Acquisition. We expect to complete the RSP Acquisition during the third quarter of 2018, subject to the approval of both our and RSP’s shareholders, the satisfaction of certain regulatory approvals and other customary closing conditions.

Oryx distribution. During the three months ended March 31, 2018, we received a cash equity method investment distribution from Oryx of approximately $157 million. Of this amount, approximately $54 million fully offset our net investment in Oryx. The remaining distribution of approximately $103 million was recorded in other income on our consolidated statement of operations for the three months ended March 31, 2018 since the lenders to the term loan do not have recourse against us, and we have no contractual obligation to repay the distribution.

2018 capital budget. In February 2018, we announced our 2018 capital budget, excluding acquisitions, of approximately $2.0 billion with expected capital spending to range between $1.9 billion and $2.1 billion. Approximately 93 percent of capital will be directed to drilling and completion activity. Our 2018 capital program is expected to continue focusing on large-scale project development. Our 2018 capital budget, based on our current expectations of commodity prices and costs, is expected to be within our operating cash flows. Our budget could change depending on numerous factors, including commodity prices, leverage metrics and industry conditions.

February 2018 acquisition and divestiture. In February 2018, we closed on an acquisition treated as a business combination where we received producing wells with approximately 5 MBoepd along with approximately 21,000 net acres, primarily located in the Midland Basin. As consideration for the non-cash acquisition, we divested of approximately 34,000 net acres, primarily comprised of approximately 32,000 net acres in the Northern Delaware Basin, with current production of 3 MBoepd. The business 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 preliminary non-cash gain of approximately $575 million, subject to customary post-closing adjustments. The approximately $755 million fair value of assets acquired comprised of approximately $245 million of proved properties, approximately $480 million of unproved properties and approximately $30 million of other assets. The fair value of the assets received in the business combination approximated the fair value of assets disposed.

Southern Delaware Basin divestitures. In January 2018, we closed on two asset sales transactions of certain non-core assets in Reeves and Ward Counties with combined preliminary proceeds of approximately $280 million, subject to customary post-closing adjustments. After direct transaction costs, we recorded a pre-tax gain on disposition of assets of approximately $134 million, which is included in gain on disposition of assets, net on our consolidated statement of operations for the three months ended March 31, 2018. The assets divested included proved and unproved oil and natural gas properties on approximately 20,000 net acres.

These divestitures completed a transaction structured as a reverse like-kind exchange (“Reverse 1031 Exchange”) in accordance with Section 1031 of the Internal Revenue Code of 1986, as amended, that we entered into concurrent with a July 2017 acquisition in the Midland Basin. In connection with the Reverse 1031 Exchange, we assigned the ownership of the oil and natural gas properties acquired to a VIE formed by an exchange accommodation titleholder. We operated the properties pursuant to a management agreement with the VIE. At December 31, 2017 and prior to the completion of the reverse like-kind exchange in January 2018, we were determined to be the primary beneficiary of the VIE, as we had the ability to control the activities that most significantly impact the VIE’s economic performance.

Upon completion of the Reverse 1031 Exchange in January 2018, the assets and liabilities attributable to the acquisition that were held by the VIE were conveyed to us, and the VIE structure was dissolved.

Nonmonetary transactions. During the three months ended March 31, 2018, we completed multiple nonmonetary transactions. These transactions included the exchange of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, we recorded pre-tax gains of approximately $14 million.

Derivative Financial Instruments

Derivative financial instrument exposure. At March 31, 2018, the fair value of our financial derivatives was a net liability of $302 million. Under the terms of our financial derivative instruments, we do not have exposure to potential “margin calls” on our financial derivative instruments. The terms of our credit facility, as amended and restated (our “Credit Facility”), do not allow us to offset amounts we may owe a lender against amounts we may be owed related to our financial instruments with such party.

New commodity derivative contracts. After March 31, 2018, we entered into the following oil price swaps, oil basis swaps and natural gas price swaps to hedge additional amounts of our estimated future production:


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total

Oil Price Swaps: (a)
	*2018:*
		Volume (Bbl)				729,000		659,000		417,000		1,805,000
		Price per Bbl			$	64.92	$	64.76	$	64.54	$	64.77
	*2019:*
		Volume (Bbl)		443,000		328,000		257,000		217,000		1,245,000
		Price per Bbl	$	59.81	$	59.71	$	59.46	$	59.34	$	59.63
	*2020:*
		Volume (Bbl)		1,244,000		1,185,000		1,131,000		1,104,000		4,664,000
		Price per Bbl	$	56.05	$	56.01	$	55.95	$	55.92	$	55.98
Oil Basis Swaps: (b)
	*2019:*
		Volume (Bbl)		630,000		637,000		644,000		644,000		2,555,000
		Price per Bbl	$	(3.26)	$	(3.26)	$	(3.26)	$	(3.26)	$	(3.26)
Natural Gas Price Swaps: (c)
	*2018:*
		Volume (MMBtu)				1,200,000		3,680,000		3,680,000		8,560,000
		Price per MMBtu			$	2.88	$	2.88	$	2.88	$	2.88
	*2019:*
		Volume (MMBtu)		2,700,000		2,730,000		2,760,000		2,760,000		10,950,000
		Price per MMBtu	$	2.75	$	2.75	$	2.75	$	2.75	$	2.75
	*2020:*
		Volume (MMBtu)		1,820,000		1,820,000		1,840,000		1,840,000		7,320,000
		Price per MMBtu	$	2.70	$	2.70	$	2.70	$	2.70	$	2.70


(a)	The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.

(b)	The basis differential price is between Midland – WTI and Cushing – WTI.
(c)	The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.

Results of Operations

The following table sets forth summary information concerning our production and operating data for the three months ended March 31, 2018 and 2017. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.


					Three Months Ended
					March 31,
					2018		2017

*Production and operating data:*
	Net production volumes:
		Oil (MBbl)				12,939		10,224
		Natural gas (MMcf)				45,448		36,597
		Total (MBoe)				20,514		16,324

	Average daily production volumes:
		Oil (Bbl)				143,767		113,600
		Natural gas (Mcf)				504,978		406,633
		Total (Boe)				227,930		181,372

	Average prices per unit:
		Oil, without derivatives (Bbl)			$	61.29	$	49.08
		Oil, with derivatives (Bbl) (a)			$	52.59	$	52.12
		Natural gas, without derivatives (Mcf)			$	3.39	$	3.00
		Natural gas, with derivatives (Mcf) (a)			$	3.41	$	2.90
		Total, without derivatives (Boe)			$	46.17	$	37.47
		Total, with derivatives (Boe) (a)			$	40.71	$	39.15

	Operating costs and expenses per Boe: (b)
		Oil and natural gas production			$	6.33	$	5.35
		Production and ad valorem taxes			$	3.40	$	2.93
		Gathering, processing and transportation			$	0.53	$	-
		Depreciation, depletion and amortization			$	15.43	$	17.36
		General and administrative			$	3.31	$	3.36


	(a)	Includes the effect of net cash receipts from (payments on) derivatives:
	(a)


					Three Months Ended
					March 31,
		(in millions)			2018		2017

		Net cash receipts from (payments on) derivatives:
			Oil derivatives		$	(113)	$	31
			Natural gas derivatives			1		(3)
				Total	$	(112)	$	28


		The presentation of average prices with derivatives is a result of including the net cash receipts from (payments on) commodity derivatives that are presented in our statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.



	(b)	Per Boe amounts calculated using dollars and volumes rounded to thousands.
	(b)

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Oil and natural gas revenues. Revenue from oil and natural gas operations was $947 million for the three months ended March 31, 2018, an increase of $335 million (55 percent) from $612 million for 2017. This increase was primarily due to the increase in oil and natural gas production as well as the increase in realized oil and natural gas prices (excluding the effects of derivative activities). Additionally, on January 1, 2018, we adopted Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers,” (“ASC 606”), which requires certain costs related to gathering, processing and transportation to be separately presented on the consolidated statements of operations. Prior to the adoption of ASC 606, these costs were generally accounted for as a deduction to revenue and included within total operating revenues on the consolidated statements of operations. We elected to use the modified retrospective approach for adopting ASC 606, and as such prior period amounts have not been restated. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding the adoption of ASC 606. Specific factors affecting oil and natural gas revenues include the following:

· total oil production was 12,939 MBbl for the three months ended March 31, 2018, an increase of 2,715 MBbl (27 percent) from 10,224 MBbl for 2017;

· average realized oil price (excluding the effects of derivative activities) was $61.29 per Bbl during the three months ended March 31, 2018, an increase of 25 percent from $49.08 per Bbl during 2017. For the three months ended March 31, 2018, our crude oil price differential relative to NYMEX was $(1.67) per Bbl, or a realization of approximately 97 percent, as compared to a crude oil price differential relative to NYMEX of $(2.87) per Bbl, or a realization of approximately 94 percent, for 2017. We incur fixed deductions from the posted Midland oil price based on the location of our oil within the Permian Basin. These fixed deductions were less per Boe during the three months ended March 31, 2018 as compared to 2017 primarily due to more production transported through pipelines and successful renegotiation of fixed deductions for trucked volumes. Additionally, the basis differential between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil directly impacts our realized oil price. For the three months ended March 31, 2018 and 2017, the average market basis differential between WTI-Midland and WTI-Cushing was a price benefit of $0.38 per Bbl and $0.75 per Bbl, respectively;

· total natural gas production was 45,448 MMcf for the three months ended March 31, 2018, an increase of 8,851 MMcf (24 percent) from 36,597 MMcf for 2017; and

· average realized natural gas price (excluding the effects of derivative activities) was $3.39 per Mcf during the three months ended March 31, 2018, an increase of 13 percent from $3.00 per Mcf during 2017. For the three months ended March 31, 2018 and 2017, we realized approximately 119 percent and 97 percent, respectively, of the average NYMEX natural gas prices for the respective periods. The increase in our realized natural gas price (excluding the effects of derivatives) as a percentage of NYMEX during the three months ended March 31, 2018 as compared to 2017 was primarily due to the adoption of ASC 606, as our natural gas realized price was $0.13 per Mcf higher than what it would have been under the previous revenue standard. The increase in our realized natural gas price was also due to an increase in the average Mont Belvieu price for a blended barrel of natural gas liquids during the three months ended March 31, 2018 as compared to 2017. Historically, and during the three months ended March 31, 2018, we derived a significant portion of our total natural gas revenues from the value of the natural gas liquids contained in our natural gas, with the remaining portion coming from the value of the dry natural gas residue. The average Mont Belvieu price for a blended barrel of natural gas liquids was $27.64 per Bbl and $24.19 per Bbl during the three months ended March 31, 2018 and 2017, respectively.

Oil and natural gas production expenses. The following table provides the components of our oil and natural gas production expenses for the three months ended March 31, 2018 and 2017:


			Three Months Ended March 31,
			2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Lease operating expenses		$	121	$	5.88	$	82	$	5.05
Workover costs			9		0.45		5		0.30
	Total oil and natural gas production expenses	$	130	$	6.33	$	87	$	5.35

Lease operating expenses were $121 million ($5.88 per Boe) for the three months ended March 31, 2018, which was an increase of $39 million from $82 million ($5.05 per Boe) during 2017. The increase in lease operating expenses during the first quarter of 2018 as compared to 2017 was primarily due to (i) increased production associated with our wells successfully drilled and completed in 2017 and 2018, (ii) our acquisitions and nonmonetary transactions during the last nine months of 2017 and first quarter of 2018, particularly our July 2017 Midland Basin acquisition, whose associated properties incur higher lease operating expense per Boe than our legacy assets, (iii) our February 2018 acquisition and divestiture, in which we acquired an additional incremental working interest in the associated properties and (iv) increased cost of services. The increase in lease operating expenses per Boe was primarily due to the increase in lease operating expenses noted above including higher expenses per Boe on properties associated with our July 2017 Midland Basin acquisition and our February 2018 acquisition and divestiture, partially offset by an increase in production.

Production and ad valorem taxes. The following table provides the components of our production and ad valorem tax expenses for the three months ended March 31, 2018 and 2017:


			Three Months Ended March 31,
			2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Production taxes		$	64	$	3.13	$	44	$	2.66
Ad valorem taxes			6		0.27		4		0.27
	Total production and ad valorem taxes	$	70	$	3.40	$	48	$	2.93

Production taxes per unit of production were $3.13 per Boe during the three months ended March 31, 2018, an increase of 18 percent from $2.66 per Boe during 2017. Over the same period, our revenue per Boe (excluding the effects of derivatives) increased 23 percent. The increase in production taxes per unit of production was directly related to the increase in oil and natural gas sales, partially offset by a higher percentage of our total production originating in Texas, which has a lower tax rate than New Mexico. Production taxes fluctuate with the market value of our production sold, while ad valorem taxes are generally based on the valuation of our oil and natural gas properties at the beginning of the year, which vary across the different areas in which we operate.

Gathering, processing and transportation costs. The following table shows the gathering, processing and transportation costs for the three months ended March 31, 2018:


		Three Months Ended March 31, 2018
		Three Months Ended March 31, 2018
			Per
(in millions, except per unit amounts)	Amount		Boe

Gathering, processing and transportation costs	$	11	$	0.53

Gathering, processing and transportation costs were $11 million ($0.53 per Boe) for the three months ended March 31, 2018. On January 1, 2018, we adopted ASC 606, which requires certain amounts related to gathering, processing and transportation costs to be separately presented on the consolidated statements of operations. Prior to the adoption of ASC 606, the majority of these costs were accounted for as a deduction to revenue and included within total operating revenues on the consolidated statements of operations. We have elected to use the modified retrospective approach for adopting ASC 606, and as such, prior period amounts have not been restated.

Exploration and abandonments expense. The following table provides the components of our exploration and abandonments expense for the three months ended March 31, 2018 and 2017:


		Three Months Ended
		March 31,
(in millions)		2018		2017

Geological and geophysical		$	5	$	6
Exploratory dry hole costs			-		-
Leasehold abandonments			10		6
Other			3		3
	Total exploration and abandonments	$	18	$	15

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing geophysical data and core analysis.

For the three months ended March 31, 2018 and 2017, we recorded approximately $10 million and $6 million, respectively, of leasehold abandonments. For the three months ended March 31, 2018, our abandonments were primarily related to (i) expiring acreage in the Southern Delaware Basin and (ii) acreage in the Northern Delaware Basin and New Mexico Shelf where we had no future plans to drill. For the three months ended March 31, 2017, our abandonments were primarily related to (i) acreage in the Northern Delaware Basin and Midland Basin where we had no future plans to drill and (ii) expiring acreage primarily located in the Southern Delaware Basin.

Our other expense for the periods presented above primarily consists of surface and title costs on locations we no longer intend to drill, certain plugging costs and delay rentals.

Depreciation, depletion and amortization expense. The following table provides components of our depreciation, depletion and amortization expense for the three months ended March 31, 2018 and 2017:


		Three Months Ended March 31,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties		$	311	$	15.13	$	277	$	16.97
Depreciation of other property and equipment			5		0.26		6		0.37
Amortization of intangible assets			1		0.04		-		0.02
	Total depletion, depreciation and amortization	$	317	$	15.43	$	283	$	17.36

Oil price used to estimate proved oil reserves at period end		$	49.94			$	44.10
Natural gas price used to estimate proved natural gas reserves at period end		$	3.00			$	2.73

Depletion of proved oil and natural gas properties was $311 million ($15.13 per Boe) for the three months ended March 31, 2018 and $277 million ($16.97 per Boe) for 2017. The increase in depletion expense was primarily due to an increase in production, partially offset by a lower depletion rate per Boe. The decrease in depletion expense per Boe was primarily due to (i) lower drilling and completion costs per Boe of proved developed reserves added since March 31, 2017 and (ii) an overall increase in proved reserves primarily caused by our successful exploratory drilling program, acquisitions, nonmonetary transactions and higher commodity prices, partially offset by decreased proved reserves caused by reclassification of proved undeveloped reserves to unproved reserves because they are no longer expected to be developed within five years of the date of their initial recognition.

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended March 31, 2018 and 2017:


		Three Months Ended March 31,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

General and administrative expenses		$	52	$	2.68	$	48	$	2.91
Less: Operating fee reimbursements			(4)		(0.21)		(4)		(0.24)
Non-cash stock-based compensation			17		0.84		12		0.69
	Total general and administrative expenses	$	65	$	3.31	$	56	$	3.36

General and administrative expenses were approximately $65 million ($3.31 per Boe) for the three months ended March 31, 2018, an increase of $9 million (16 percent) from $56 million ($3.36 per Boe) for 2017. The increase in cash general and administrative expenses was primarily driven by increased compensation expense as a result of increased employee headcount. The increase in non-cash stock-based compensation was primarily due to lower forfeitures in 2018 coupled with the increase in employee headcount. The decrease in total general and administrative expenses per Boe was primarily the result of increased production, partially offset by the increase in total general and administrative expenses noted above.

We receive fees for the operation of jointly-owned oil and natural gas properties during the drilling and production phases and record such reimbursements as reductions to general and administrative expenses on the consolidated statements of operations. We earned reimbursements of approximately $4 million for each of the three months ended March 31, 2018 and 2017.

Gain (loss) on derivatives. The following table sets forth the gain (loss) on derivatives for the three months ended March 31, 2018 and 2017:


			Three Months Ended
			March 31,
(in millions)				2018		2017

*Gain (loss) on derivatives:*
	Oil derivatives		$	(33)	$	266
	Natural gas derivatives			(2)		20
		Total	$	(35)	$	286


The following table represents our net cash receipts from (payments on) derivatives for the three months ended March 31, 2018 and 2017:


			Three Months Ended
			March 31,
(in millions)				2018		2017

*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	(113)	$	31
	Natural gas derivatives			1		(3)
		Total	$	(112)	$	28

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash settlements of those derivatives, which could be significant. To the extent the future commodity price outlook declines between measurement periods, we will have mark-to-market gains; while to the extent the future commodity price outlook increases between measurement periods, we will have mark-to-market losses. See Note 7 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding significant judgments made in classifying financial instruments in the fair value hierarchy.

Gain on disposition of assets, net. During the three months ended March 31, 2018, we recognized a preliminary non-cash gain of approximately $575 million, subject to customary post-closing adjustments, related to our February 2018 acquisition and divestiture.

In January 2018, we closed on our Southern Delaware Basin divestitures with combined preliminary proceeds of approximately $280 million, subject to customary post-closing adjustments. After direct transaction costs, we recorded a pre-tax gain on disposition of assets of approximately $134 million.

During the three months ended March 31, 2018, we completed multiple nonmonetary transactions. These transactions included the exchange of both proved and unproved oil and natural gas properties. Certain of these transactions were accounted for at fair value and, as a result, we recorded pre-tax gains of approximately $14 million.

In February 2017, we closed on the divestiture of our ownership interest in ACC. After adjustments for debt and working capital, we received cash proceeds from the sale of approximately $803 million. After direct transaction costs, we recorded a pre-tax gain on disposition of assets of approximately $656 million. Our net investment in ACC at the time of closing was approximately $129 million.

Interest expense. The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended March 31, 2018 and 2017:


		Three Months Ended
		March 31,
(in millions)		2018		2017

Interest expense, as reported		$	30	$	40
Capitalized interest			1		-
	Interest expense, excluding impact of capitalized interest	$	31	$	40

Weighted average interest rate - credit facility			4.3%		4.0%
Weighted average interest rate - senior notes			4.3%		5.3%
	Total weighted average interest rate		4.3%		5.3%

Weighted average credit facility balance		$	211	$	6
Weighted average senior notes balance			2,400		2,750
	Total weighted average debt balance	$	2,611	$	2,756

Our weighted average debt balance decreased for the three months ended March 31, 2018 as compared to 2017 primarily due to completing a cash tender offer and the satisfaction and discharge in September 2017 of all of the outstanding $600 million aggregate principal amount of our 5.5% unsecured senior notes due 2022 and $1,550 million aggregate principal amount of our 5.5% unsecured senior notes due 2023, partially offset by (i) the issuance of $1,000 million in aggregate principal amount of 3.75% unsecured senior notes due 2027 and $800 million in aggregate principal amount of 4.875% unsecured senior notes due 2047 and (ii) an increase in our weighted average credit facility balance. The decrease in interest expense was due to the decrease in the weighted average debt balance, weighted average interest rate and an increase in capitalized interest.

Other income, net. During the three months ended March 31, 2018, we recorded other income of approximately $97 million primarily related to a cash distribution received from Oryx. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding this distribution.

Income tax provisions. For the three months ended March 31, 2018 and 2017, we recorded income tax expense of $254 million and $371 million, respectively. These amounts include a discrete income tax benefit of approximately $2 million and $7 million related to excess tax benefits on stock-based awards for the three months ended March 31, 2018 and 2017, respectively. The change in our income tax provision was primarily due to the decrease in the U.S. federal statutory rate from 35 percent to 21 percent.

The effective income tax rates for the three months ended March 31, 2018 and 2017 were 23 percent and 36 percent, respectively.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. Our primary needs for cash are development, exploration and acquisition of oil and natural gas assets, payment of contractual obligations and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, financing under our Credit Facility, proceeds from the disposition of assets or alternative financing sources, as discussed in “— Capital resources” below.

Oil and natural gas properties. Our costs incurred on oil and natural gas properties, excluding acquisitions, during the three months ended March 31, 2018 and 2017 totaled $450 million and $393 million, respectively. The increase was primarily due to our increased drilling and completion activity level during the first three months of 2018 as compared to 2017. Our intent is to manage our capital spending to be within our operating cash flow, excluding unbudgeted acquisitions. The primary reason for the differences in costs incurred and cash flow expenditures was the timing of payments. Total 2018 expenditures were primarily funded in part from cash flows from operations and proceeds from our January 2018 Southern Delaware Basin divestitures.

2018 capital budget. In February 2018, we announced our 2018 capital budget, excluding acquisitions, of approximately $2.0 billion with expected capital spending to range between $1.9 billion and $2.1 billion. Our 2018 capital budget, based on our current expectations of commodity prices and costs, is expected to be within our operating cash flows.

After the completion of the RSP Acquisition, which is subject to approval of both our and RSP’s shareholders, the satisfaction of certain regulatory approvals and other customary closing conditions, we plan to make the necessary adjustments to our capital budget to accommodate the incremental activities associated with the assets acquired.

Other than the customary purchase of leasehold acreage, our capital budgets are exclusive of acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. We evaluate opportunities to purchase or sell oil and natural gas properties in the marketplace and could participate as a buyer or seller of properties at various times. We seek to acquire oil and natural gas properties that provide opportunities for the addition of reserves and production through a combination of development, high-potential exploration and control of operations that will allow us to apply our operating expertise, such as the RSP Acquisition.

Acquisitions. The following table reflects our expenditures for acquisitions of proved and unproved properties for the three months ended March 31, 2018 and 2017:


			Three Months Ended
			March 31,
(in millions)			2018		2017

Property acquisition costs:
	Proved		$	-	$	127
	Unproved			13		306
		Total property acquisition costs (a)	$	13	$	433


(a)	Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately $13 million and $5 million for the three months ended March 31, 2018 and 2017, respectively. For the three months ended March 31, 2017, our unbudgeted acquisitions are primarily comprised of approximately $393 million of property acquisition costs related to our January 2017 Northern Delaware Basin acquisition.

Contractual obligations. Our contractual obligations include long-term debt, cash interest expense on debt, derivative liabilities, asset retirement obligations, employment agreements with officers, purchase obligations, operating lease obligations and other obligations. Since December 31, 2017, the changes in our contractual obligations are not material, other than our derivative liability position, which decreased by $52 million. See Note 9 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on our long-term debt and information on changes in the fair value of our open derivative obligations during the three months ended March 31, 2018.

In connection with our proposed RSP Acquisition, the Acquisition Agreement provides us certain termination rights under which we may exercise and effectively terminate the Acquisition Agreement. Should certain unlikely events occur under

specified circumstances outlined in the Acquisition Agreement, we will be required to pay RSP a termination fee of $350 million. See Note 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding the RSP Acquisition.

Off-balance sheet arrangements. Currently, we do not have any material off-balance sheet arrangements.

Capital resources. Our primary sources of liquidity have been cash flows generated from (i) operating activities, (ii) borrowings under our Credit Facility, (iii) proceeds from bond and equity offerings and (iv) asset dispositions. In February 2018, we announced our 2018 capital budget, excluding acquisitions, of approximately $2.0 billion with expected capital spending to range between $1.9 billion and $2.1 billion. Our 2018 capital budget, based on our current expectations of commodity prices and costs, is expected to be within our operating cash flows.

The following table summarizes our changes in cash and cash equivalents for the three months ended March 31, 2018 and 2017:


		Three Months Ended
		March 31,
(in millions)		2018		2017

Net cash provided by operating activities		$	488	$	407
Net cash provided by (used in) investing activities			(93)		330
Net cash used in financing activities			(395)		(19)
	Net increase in cash and cash equivalents	$	-	$	718

Cash flow from operating activities. The increase in operating cash flows during the three months ended March 31, 2018 as compared to the same period in 2017 was primarily due to an increase in oil and natural gas revenues of approximately $335 million, partially offset by (i) a decrease in operating cash flow of approximately $140 million due to approximately $112 million for settlements paid on derivatives during the three months ended March 31, 2018, as compared to approximately $28 million in settlements received from derivatives during the comparable period in 2017, (ii) approximately $49 million of negative variances in operating assets and liabilities, (iii) approximately $43 million increase in production expense and (iv) approximately $22 million increase in production tax expense.

Our net cash provided by operating activities included a reduction of approximately $51 million and a benefit of approximately $2 million for the three months ended March 31, 2018 and 2017, respectively, associated with changes in working capital items. Changes in working capital items adjust for the timing of receipts and payments of actual cash.

Cash flow from investing activities. During the three months ended March 31, 2018 and 2017, we invested approximately $474 million and $286 million, respectively, for additions to oil and natural gas properties. Additionally, we completed acquisitions of oil and natural gas properties of approximately $13 million and $171 million during the three months ended March 31, 2018 and 2017, respectively. We received approximately $255 million related to proceeds from the disposition of assets during the three months ended March 31, 2018, as compared to $806 million during the comparable period of 2017. Finally, we received an equity method investment distribution from Oryx of approximately $157 million during the three months ended March 31, 2018. Of this amount, approximately $9 million represented cumulative Oryx earnings and was classified as cash flow from operating activities, while the remaining amount of approximately $148 million was classified as cash flow from investing activities.

Cash flow from financing activities. Net cash used in financing activities was approximately $395 million and $19 million for the three months ended March 31, 2018 and 2017, respectively. We had net payments on our Credit Facility of $322 million for the three months ended March 31, 2018, as compared to no outstanding borrowings during the comparable period of 2017.

Advances on our Credit Facility bear interest, at our option, based on (i) an alternative base rate, which is equal to the highest of (a) the prime rate of JPMorgan Chase Bank (4.75 percent at March 31, 2018), (b) the federal funds effective rate plus 0.5 percent and (c) the London Interbank Offered Rate (“LIBOR”) plus 1.0 percent or (ii) LIBOR. Our Credit Facility’s interest rates and commitment fees on the unused portion of the available commitment vary depending on our credit ratings from Moody’s Investors Service, Inc. (“Moody’s”) and S&P Global Ratings (“S&P”). At our current credit ratings, LIBOR Rate Loans and Alternate Base Rate Loans bear interest margins of 150 basis points and 50 basis points per annum, respectively, and commitment fees on the unused portion of the available commitment are 25 basis points per annum.

In conducting our business, we may utilize various financing sources, including the issuance of (i) fixed and floating rate debt, (ii) convertible securities, (iii) preferred stock, (iv) common stock and (v) other securities. Historically, we have demonstrated our use of the capital markets by issuing common stock and senior unsecured debt. There are no assurances that we can access the capital markets to obtain additional funding, if needed, and at cost and terms that are favorable to us. We may also sell assets and issue securities in exchange for oil and natural gas assets or interests in energy companies, such as in the RSP Acquisition. Additional securities may be of a class senior to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined from time to time. Utilization of some of these financing sources may require approval from the lenders under our Credit Facility.

Liquidity. Our principal source of liquidity is available borrowing capacity under our Credit Facility. At March 31, 2018, our commitments from our bank group were $2.0 billion.

Debt ratings. We receive debt credit ratings from S&P, Moody’s and Fitch Ratings, which are subject to regular reviews. In determining our ratings, the agencies consider a number of qualitative and quantitative factors including, but not limited to: the industry in which we operate, production growth opportunities, liquidity, debt levels and asset and reserve mix.

A downgrade in our credit ratings could (i) negatively impact our costs of capital and our ability to effectively execute aspects of our strategy, (ii) affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt and (iii) negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. Further, if we are unable to maintain credit ratings of “Ba2” or better from Moody’s and “BB” or better from S&P, the investment grade period under our Credit Facility will automatically terminate and cause our Credit Facility to once again be secured by a first lien on substantially all of our oil and natural gas properties and by a pledge of the equity interests in our subsidiaries. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial condition and results of operations.

As of the filing of this Quarterly Report, no changes in our credit ratings have occurred since March 31, 2018; however, we cannot be assured that our credit ratings will not be downgraded in the future.

Book capitalization and current ratio. Our net book capitalization at March 31, 2018 was $12.1 billion, consisting of debt of $2.4 billion and stockholders’ equity of $9.7 billion. Our net book capitalization at December 31, 2017 was $11.6 billion, consisting of debt of $2.7 billion and stockholders’ equity of $8.9 billion. Our ratio of net debt to net book capitalization was 20 percent and 23 percent at March 31, 2018 and December 31, 2017, respectively. Our ratio of current assets to current liabilities was 0.65 to 1.0 at March 31, 2018 as compared to 0.51 to 1.0 at December 31, 2017.

Inflation and changes in prices. Our revenues, the value of our assets and our ability to obtain bank financing or additional capital on attractive terms have been and will continue to be affected by changes in commodity prices and the costs to produce our reserves. Commodity prices are subject to significant fluctuations that are beyond our ability to control or predict. During the three months ended March 31, 2018, we received an average of $61.29 per Bbl of oil and $3.39 per Mcf of natural gas before consideration of commodity derivative contracts compared to $49.08 per Bbl of oil and $3.00 per Mcf of natural gas in the three months ended March 31, 2017. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business.

Critical Accounting Policies, Practices and Estimates

Our historical consolidated financial statements and related notes to consolidated financial statements contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires that our management make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by us generally do not change our reported cash flows or liquidity. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to us.

In management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, asset retirement obligations, impairment of long-lived assets, valuation of stock-based compensation, valuation of business combinations, accounting and valuation of nonmonetary transactions, valuation of financial derivative instruments and income taxes. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the three months ended March 31, 2018. See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of our Annual Report on Form 10-K for the year ended December 31, 2017, filed with the SEC on February 21, 2018.

New accounting pronouncements issued but not yet adopted. In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” (“ASU 2016-02”) which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for financing and operating leases. Lease expense recognition on the consolidated statements of operations will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. We do not plan to early adopt the standard. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space, vehicles, field services, well equipment and drilling rigs. We are substantially complete with the process of reviewing and determining the contracts to which this new guidance applies. We are currently enhancing our accounting systems in order to track and calculate additional information necessary for adoption of this standard. We believe this new guidance will have a moderate impact to our consolidated balance sheets due to the recognition of right-of-use assets and lease liabilities that are not recognized under currently applicable guidance.

In January 2018, the FASB issued ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” which provides an optional practical expedient to not evaluate land easements that existed or expired before the adoption of ASU 2016-02 and that were not previously accounted for as leases under the original “Leases (Topic 840)” accounting standard (“Topic 840”). We enter into land easements on a routine basis as part of our ongoing operations and have many such agreements currently in place; however, we do not currently account for any land easements under Topic 840. As this guidance serves as an amendment to ASU 2016-02, we will elect this practical expedient, which becomes effective upon the date of adoption of ASU 2016-02. After the adoption of ASU 2016-02, we will assess any new land easements to determine whether the arrangement should be accounted for as a lease.

In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected credit losses on financial instruments. This guidance is effective for fiscal years beginning after December 15, 2019, and early adoption is allowed as early as fiscal years beginning after December 15, 2018. We do not believe this new guidance will have a material impact on our consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2017.

We are exposed to a variety of market risks, including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we are a party at March 31, 2018, and from which we may incur future gains or losses from changes in market interest rates or commodity prices and losses from extension of credit. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Hypothetical changes in interest rates and commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Credit risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries, and to a lesser extent, our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness.

We have entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 8 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative activities.

Commodity price risk. We are exposed to market risk as the prices of our commodities are subject to fluctuations resulting from changes in supply and demand. To reduce our exposure to changes in the prices of our commodities, we have entered into, and may in the future enter into, additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Our commodity price risk management arrangements are recorded at fair value and thus changes to the future commodity prices will have an impact on net income. The following table sets forth the hypothetical impact on the fair value of the commodity price risk management arrangements from an average increase and decrease in the commodity price of $5.00 per Bbl of oil and $0.50 per MMBtu of natural gas from the commodity prices at March 31, 2018:


				Increase of		Decrease of
				$5.00 per Bbl and		$5.00 per Bbl and
(in millions)				$0.50 per MMBtu		$0.50 per MMBtu

Gain (loss):
	Oil derivatives		$	(309)	$	309
	Natural gas derivatives			(29)		29
		Total	$	(338)	$	338

At March 31, 2018, we had (i) oil price swaps that settle on a monthly basis covering future oil production from April 1, 2018 through December 31, 2020 and (ii) oil basis swaps covering our Midland to Cushing basis differential from April 1, 2018 to December 31, 2020. The average NYMEX oil price for the three months ended March 31, 2018 was $62.96 per Bbl. At April 30, 2018, the NYMEX oil price was $68.57 per Bbl.

At March 31, 2018, we had natural gas price swaps that settle on a monthly basis covering future natural gas production from April 1, 2018 to December 31, 2019. The average NYMEX natural gas price for the three months ended March 31, 2018 was $2.84 per MMBtu. At April 30, 2018, the NYMEX natural gas price was $2.76 per MMBtu.

A decrease in the average forward NYMEX oil and natural gas prices below those at March 31, 2018 would decrease the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2018. Changes in the recorded fair value of our commodity derivative contracts are marked to market through earnings as gains or losses. The potential decrease in our fair value liability would be recorded in earnings as a gain. However, an increase in the average forward NYMEX oil and natural gas prices above those at March 31, 2018 would increase the fair value liability of our commodity derivative contracts from their recorded balance at March 31, 2018. The potential increase in our fair value liability would be recorded in earnings as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts.

We recorded a loss on derivatives of $35 million for the three months ended March 31, 2018, compared to a gain of $286 million for the three months ended March 31, 2017. The decrease was primarily due to the change in commodity future price curves at the respective measurement and settlement periods.

The fair value of our derivative instruments is determined based on our valuation models. We did not change our valuation method for our derivative instruments during the three months ended March 31, 2018. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the three months ended March 31, 2018:


		Commodity Derivative
		Instruments
(in millions)		Net Assets (Liabilities) (a)

Fair value of contracts outstanding at December 31, 2017			$	(379)
	Changes in fair values (b)			(35)
	Contract maturities			112
Fair value of contracts outstanding at March 31, 2018			$	(302)


(a)	Represents the fair values of open derivative contracts subject to market risk.
(b)	At inception, new derivative contracts entered into by us have no intrinsic value.

See Note 8 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our derivative instruments.

Interest rate risk. Our exposure to changes in interest rates relates primarily to debt obligations. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. To reduce our exposure to changes in interest rates we may, in the future, enter into interest rate risk management arrangements for a portion of our outstanding debt. The agreements that we have entered into generally have the effect of providing us with a fixed interest rate for a portion of our variable rate debt. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. We are exposed to changes in interest rates as a result of our Credit Facility, and the terms of our Credit Facility require us to pay higher interest rate margins as our credit ratings decrease.

We had no indebtedness outstanding under our Credit Facility at March 31, 2018.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at March 31, 2018 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are a party to proceedings and claims incidental to our business. While many of these other matters involve inherent uncertainty, we believe that the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations. We will continue to evaluate proceedings and claims involving us on a regular basis and will establish and adjust any reserves as appropriate to reflect our assessment of the then current status of the matters.

Item 1A. Risk Factors

In addition to the information set forth in this Quarterly Report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2017, under the headings “Item 1. Business — Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” which risks could materially affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2017, other than the risk factors set forth below. The risks described in our Annual Report on Form 10-K for the year ended December 31, 2017 and in this Quarterly Report are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

The following risk factors relate to the RSP Acquisition. For more information on the RSP Acquisition, please read our Registration Statement on Form S-4 filed with the SEC on April 20, 2018 and any subsequent amendments thereto, as well as any other related information on the RSP Acquisition that we have filed with the SEC.

Failure to complete the RSP Acquisition could negatively impact the price of shares of our common stock, as well as our future business and financial results.

The Acquisition Agreement contains a number of conditions that must be satisfied or waived prior to the completion of the RSP Acquisition. There can be no assurance that all of the conditions to the completion of the RSP Acquisition will be so satisfied or waived. If these conditions are not satisfied or waived, we will be unable to complete the RSP Acquisition.

If the RSP Acquisition is not completed for any reason, including the failure to receive the required approvals of our and RSP’s stockholders, our business and financial results may be adversely affected, including as follows:

· we may experience negative reactions from the financial markets, including negative impacts on the market price of shares of our common stock;

· the manner in which customers, vendors, business partners and other third parties perceive us may be negatively impacted, which in turn could affect our marketing operations or our ability to compete for new business or obtain renewals in the marketplace more broadly;

· we may experience negative reactions from employees; and

· we will have expended time and resources that could otherwise have been spent on our existing business and the pursuit of other opportunities that could have been beneficial to us, and our ongoing business and financial results may be adversely affected.

In addition to the above risks, if the Acquisition Agreement is terminated and our board seeks an alternative transaction, our stockholders cannot be certain that we will be able to find a party willing to engage in a transaction on more attractive terms than the RSP Acquisition. If the Acquisition Agreement is terminated under specified circumstances, we may be required to pay RSP a termination fee, reverse termination fee or other termination-related payment.

Further, if the RSP Acquisition is not completed by October 31, 2018, either we or RSP may choose not to proceed with the RSP Acquisition, and the parties can mutually decide to terminate the Acquisition Agreement at any time, before or after stockholder approval.

The RSP Acquisition may not be accretive, and may be dilutive, to our earnings per share, which may negatively affect the market price of shares of our common stock.

Because shares of our common stock will be issued in the RSP Acquisition, it is possible that, although we currently expect the RSP Acquisition to be accretive to earnings per share, the RSP Acquisition may be dilutive to our earnings per share, which could negatively affect the market price of shares of our common stock.

In connection with the completion of the RSP Acquisition, based on the number of issued and outstanding shares of RSP common stock as of April 16, 2018 and the number of outstanding RSP equity awards currently estimated to be payable in our common stock following the RSP Acquisition, we will issue up to approximately 51 million shares of our common stock. The issuance of these new shares of our common stock could have the effect of depressing the market price of shares of our common stock, through dilution of earnings per share or otherwise. Any dilution of, or delay of any accretion to, our earnings per share could cause the price of shares of our common stock to decline or increase at a reduced rate.

Our stockholders will be diluted by the RSP Acquisition.

The RSP Acquisition will dilute the ownership position of our current stockholders. We currently estimate that former RSP stockholders will own approximately 25.5 percent of the issued and outstanding shares of our common stock immediately following the effective time of the RSP Acquisition.

Required regulatory approvals may not be received, may take longer than expected to be received or may impose conditions that are not presently anticipated or cannot be met. In addition, an adverse outcome of any antitrust or similar review undertaken by a governmental authority could prevent the RSP Acquisition from being completed or have an adverse effect on us following the RSP Acquisition.

Completion of the RSP Acquisition is conditioned upon the approval by the New York Stock Exchange of the listing of the shares of our common stock to be issued in the RSP Acquisition upon official notice of issuance and the expiration or termination of the waiting period applicable to the RSP Acquisition under the Hart–Scott–Rodino Antitrust Improvements Act of 1976. There can be no assurance that these approvals will be obtained and that the other conditions to completing the RSP Acquisition will be satisfied. In addition, the governmental authorities from which the regulatory approvals are required may impose conditions on the completion of the RSP Acquisition or require changes to the terms of the RSP Acquisition or Acquisition Agreement. Such conditions or changes and the process of obtaining regulatory approvals could have the effect of delaying or impeding completion of the RSP Acquisition or of imposing additional costs or limitations on us following completion of the RSP Acquisition, any of which might have an adverse effect on us following completion of the RSP Acquisition.

We and RSP will be subject to business uncertainties while the RSP Acquisition is pending, which could adversely affect our respective businesses.

Uncertainty about the effect of the RSP Acquisition on employees and customers may have an adverse effect on us and RSP. These uncertainties may impair our and RSP’s ability to attract, retain and motivate key personnel until the RSP Acquisition is completed and for a period of time thereafter and could cause customers and others that deal with us and RSP to seek to change their existing business relationships with us and RSP, respectively. Employee retention at RSP may be particularly challenging during the pendency of the RSP Acquisition, as employees may experience uncertainty about their roles with us following the RSP Acquisition. In addition, the Acquisition Agreement restricts us and RSP from entering into certain corporate transactions and taking other specified actions without the consent of the other party, and generally requires each party to continue its operations in the ordinary course, until completion of the RSP Acquisition. These restrictions may prevent us and RSP from pursuing attractive business opportunities that may arise prior to the completion of the RSP Acquisition.

We will incur significant transaction and acquisition-related costs in connection with the RSP Acquisition, which may be in excess of those anticipated by us.

We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the RSP Acquisition, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the RSP Acquisition and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees.

We will also incur transaction fees and costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and employment-related costs. We will continue to assess the magnitude of these costs, and additional unanticipated costs may be incurred in the RSP Acquisition and the integration of the two companies’ businesses. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses,

may not offset integration-related costs and achieve a net benefit in the near term, or at all. For additional information, please read the risk factor entitled “The integration of RSP may not be as successful as anticipated” below.

The costs described above, as well as those borne by RSP and other unanticipated costs and expenses, could have a material adverse effect on our financial condition and operating results following the completion of the RSP Acquisition. Many of these costs will be borne by us even if the RSP Acquisition is not completed.

We have substantial indebtedness, and following the RSP Acquisition, will continue to have substantial indebtedness.

At March 31, 2018, we had approximately $2.4 billion of indebtedness outstanding under our senior unsecured notes and no amounts outstanding under our Credit Facility. At December 31, 2017, RSP had approximately $1.5 billion of outstanding indebtedness, consisting of amounts outstanding under its $2.0 billion senior secured credit facility and its senior unsecured notes. We continue to review the treatment of our and RSP’s existing indebtedness, and we may seek to repay, refinance, repurchase, redeem, exchange or otherwise terminate our or RSP’s existing indebtedness prior to, in connection with or following the completion of the RSP Acquisition. If we do seek to refinance our or RSP’s existing indebtedness, there can be no guarantee that we would be able to execute the refinancing on favorable terms or at all. Assuming we do not repay, refinance, repurchase, redeem, exchange or otherwise terminate any of our or RSP’s existing indebtedness, immediately following the completion of the RSP Acquisition, we are expected to have outstanding indebtedness of approximately $3.9 billion, based on our and RSP’s outstanding indebtedness as of March 31, 2018 and December 31, 2017, respectively.

Any increase in our level of indebtedness could have adverse effects on our financial condition and results of operations, including:

· imposing additional cash requirements on us in order to support interest payments, which reduces the amount we have available to fund our operations and other business activities;

· increasing the risk that we may default on our debt obligations;

· increasing our vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in our business;

· limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes;

· limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate; and

· increasing our exposure to a rise in interest rates, which will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges.

The integration of RSP may not be as successful as anticipated.

The RSP Acquisition involves numerous operational, strategic, financial, accounting, legal, tax and other risks, potential liabilities associated with the acquired businesses, and uncertainties related to design, operation and integration of RSP’s internal control over financial reporting. Difficulties in integrating RSP into our company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Our and RSP’s existing businesses could also be negatively impacted by the RSP Acquisition. Potential difficulties that may be encountered in the integration process include, among other factors:

· the inability to successfully integrate the businesses of RSP into our company in a manner that permits us to achieve the full revenue and cost savings anticipated from the RSP Acquisition;

· complexities associated with managing the larger, more complex, integrated business;

· not realizing anticipated operating synergies;

· integrating personnel from the two companies and the loss of key employees;

· potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the RSP Acquisition;

· integrating relationships with customers, vendors and business partners;

· performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the RSP Acquisition and integrating RSP’s operations into our company; and

· the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.

Our results may suffer if we do not effectively manage our expanded operations following the RSP Acquisition.

Following completion of the RSP Acquisition, our success will depend, in part, on our ability to manage our expansion, which poses numerous risks and uncertainties, including the need to integrate the operations and business of RSP into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors and business partners.

Even if we and RSP complete the RSP Acquisition, we may fail to realize all of the anticipated benefits of the RSP Acquisition.

The success of the RSP Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and RSP’s businesses, including operational and other synergies in excess of $2 billion (based on present value) that we believe the combined company will achieve. The anticipated benefits and cost savings of the RSP Acquisition may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized. The integration process may, for us and RSP, result in the loss of key employees, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. There could be potential unknown liabilities and unforeseen expenses associated with the RSP Acquisition that were not discovered in the course of performing due diligence.

Uncertainties associated with the RSP Acquisition may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company.

We and RSP are dependent on the experience and industry knowledge of officers and other key employees to execute our and RSP’s business plans, respectively. Each company’s success until the RSP Acquisition and the combined company’s success after the RSP Acquisition will depend in part upon the ability of both companies to retain key management personnel and other key employees. Current and prospective employees of each company may experience uncertainty about their roles within the combined company following the RSP Acquisition, which may have an adverse effect on the ability of each company to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees to the same extent that each company had previously been able to attract or retain such employees.

The market price of shares of our common stock may decline in the future as a result of the sale of shares of our common stock held by former RSP stockholders or current stockholders.

Based on the number of shares of RSP common stock outstanding as of April 16, 2018 and the number of outstanding RSP equity awards currently estimated to be payable in our common stock following the RSP Acquisition, we expect to issue up to approximately 51 million shares of our common stock to RSP stockholders in the RSP Acquisition. Following their receipt of shares of our common stock as acquisition consideration in the RSP Acquisition, former RSP stockholders may seek to sell the shares of our common stock delivered to them, and the Acquisition Agreement contains no restriction on the ability of former RSP stockholders to sell such shares of our common stock following completion of the RSP Acquisition. Other stockholders may also seek to sell shares of our common stock held by them following, or in anticipation of, completion of the RSP Acquisition. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner.

The combined company will record goodwill and other intangible assets that could become impaired and result in material non-cash charges to the results of operations of the combined company in the future.

The RSP Acquisition will be accounted for as an acquisition by us in accordance with accounting principles generally accepted in the United States. Under the acquisition method of accounting, the assets and liabilities of RSP and its subsidiaries will be recorded, as of completion, at their respective fair values and added to our assets and liabilities. The reported financial condition and results of operations of our company for periods after completion of the RSP Acquisition will reflect RSP balances and results after completion of the RSP Acquisition but will not be restated retroactively to reflect the historical financial position or results of operations of RSP and its subsidiaries for periods prior to the RSP Acquisition.

Under the acquisition method of accounting, the total purchase price will be allocated to RSP’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of the date of completion of the RSP Acquisition. The excess of the purchase price over those fair values will be recorded as goodwill. We and RSP expect that the RSP Acquisition will result in the creation of goodwill based upon the application of the acquisition method of accounting. To the extent the value of goodwill or intangibles becomes impaired, the combined company may be required to incur material non-cash charges relating to such impairment. The combined company’s operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.

Following the completion of the RSP Acquisition, we may incorporate RSP’s hedging activities into our business, and we may be exposed to additional commodity price risks arising from such hedges.

To mitigate its exposure to changes in commodity prices, RSP hedges oil, natural gas and natural gas liquids prices from time to time, primarily through the use of certain derivative instruments. If we assume existing RSP hedges, we will bear the economic impact of all of RSP’s current hedges following the completion of the RSP Acquisition. Actual crude oil, natural gas and natural gas liquids prices may differ from the combined company’s expectations, and as a result, such hedges may or may not have a negative impact on our business.

We and RSP may be targets of securities class action and derivative lawsuits which could result in substantial costs and may delay or prevent the RSP Acquisition from being completed.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition agreements. Even if the lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our and RSP’s respective liquidity and financial condition. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the RSP Acquisition, then that injunction may delay or prevent the RSP Acquisition from being completed, which may adversely affect our and RSP’s respective business, financial position and results of operations. Currently, neither we nor RSP is aware of any securities class action lawsuits or derivative lawsuits having been filed in connection with the RSP Acquisition.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds


Period		Total number of shares withheld (a)	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan

January 1, 2018 - January 31, 2018		199,970	$	151.53	-
February 1, 2018 - February 28, 2018		1,441	$	149.74	-
March 1, 2018 - March 31, 2018		184	$	148.20	-


(a)	Represents shares that were withheld by us to satisfy tax withholding obligations of certain employees that arose upon the lapse of restrictions on share-based awards.

Item 6. Exhibits


Exhibit Number		Exhibit

2.1	*	Agreement and Plan of Merger among Concho Resources Inc., RSP Permian, Inc. and Green Merger Sub Inc., dated as of March 27, 2018 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on March 28, 2018, and incorporated herein by reference).
3.1		Restated Certificate of Incorporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on August 8, 2007, and incorporated herein by reference).

3.2		Fourth Amended and Restated Bylaws of Concho Resources Inc., as amended January 2, 2018 (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).

4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Annual Report on Form 10-K on February 22, 2013, and incorporated herein by reference).
10.1	**	Performance Unit Award Agreement, dated January 2, 2018, by and between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).
10.2	**	Restricted Stock Agreement, dated January 2, 2018, between Concho Resources Inc. and E. Joseph Wright (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on January 4, 2018, and incorporated herein by reference).
31.1	(a)	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2	(a)	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32.1	(b)	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2	(b)	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

101.INS	(a)	XBRL Instance Document.

101.SCH	(a)	XBRL Schema Document.

101.CAL	(a)	XBRL Calculation Linkbase Document.

101.DEF	(a)	XBRL Definition Linkbase Document.

101.LAB	(a)	XBRL Labels Linkbase Document.

101.PRE	(a)	XBRL Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

* Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally a copy of such schedules, or any section thereof, to the SEC upon request.

** Management contract or compensatory plan or agreement.

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 undersigned thereunto duly authorized.

CONCHO RESOURCES INC.

Date:	May 2, 2018	By	/s/ Timothy A. Leach

			Timothy A. Leach
			Chairman of the Board of Directors and Chief Executive
			Officer
			(Principal Executive Officer)


		By	/s/ Jack F. Harper

			Jack F. Harper
			President and Chief Financial Officer
			(Principal Financial Officer)


		By	/s/ Brenda R. Schroer

			Brenda R. Schroer
			Senior Vice President, Chief Accounting Officer and Treasurer
			(Principal Accounting Officer)