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 September 30, 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 ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☑ No ☐

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 ☐

Non-accelerated filer ☐	Smaller reporting company ☐

Emerging growth company ☐

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

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

Number of shares of the registrant’s common stock outstanding at October 29, 2018: 200,250,195 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	36

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	58

	Item 4. Controls and Procedures	60

PART II – OTHER INFORMATION:		61

	Item 1. Legal Proceedings	61

	Item 1A. Risk Factors	61

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	62

	Item 6. Exhibits	63

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, disputes and derivative activities. 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 future events, expectations or possible 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 I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2017 and “Part II, Item 1A. Risk Factors” in our subsequent Quarterly Reports on Form 10-Q, and the other information included in our filings with the Securities and Exchange Commission and our public disclosure, as well as those factors summarized below:

· 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;

· risks related to ongoing expansion of our business, including the recruitment and retention of qualified personnel in the Permian Basin;

· drilling, completion and operating risks, including our ability to efficiently execute large-scale project development as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity;

· declines in, or the sustained depression of, the prices we receive for our oil and natural gas, or increases in the differential between index oil or natural gas prices and prices received;

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

· 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;

· risks associated with acquisitions, including our recent acquisition of RSP Permian, Inc., such as increased expenses and integration efforts, failure to realize the expected benefits of the transaction, liabilities associated with acquired properties or businesses and the ability to realize expected benefits;

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

· 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;

· 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 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 September 30, 2018 and December 31, 2017	1

Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017	2

Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2018	3

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017	4

Condensed Notes to Consolidated Financial Statements	5

iii

Concho Resources Inc.

Consolidated Balance Sheets

Unaudited


				September 30,		December 31,
(in millions, except share and per share amounts)					2018	2017
Assets
Current assets:
	Cash and cash equivalents			$	24	$	-
	Accounts receivable, net of allowance for doubtful accounts:
		Oil and natural gas			520		331
		Joint operations and other			387		212
	Inventory				36		14
	Prepaid costs and other				61		35
			Total current assets		1,028		592
Property and equipment:
	Oil and natural gas properties, successful efforts method				30,980		21,267
	Accumulated depletion and depreciation				(9,362)		(8,460)
		Total oil and natural gas properties, net			21,618		12,807
	Other property and equipment, net				277		234
		Total property and equipment, net			21,895		13,041
Deferred loan costs, net					11		13
Goodwill					2,246		-
Intangible assets, net					20		26
Other assets					10		60
	Total assets			$	25,210	$	13,732
Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable - trade			$	44	$	43
	Bank overdrafts				87		116
	Revenue payable				283		183
	Accrued drilling costs				548		330
	Derivative instruments				547		277
	Other current liabilities				367		216
			Total current liabilities		1,876		1,165
Long-term debt					4,143		2,691
Deferred income taxes					1,431		687
Noncurrent derivative instruments					363		102
Asset retirement obligations and other long-term liabilities					165		172
Commitments and contingencies (Note 10)
Stockholders’ equity:
	Common stock, $0.001 par value; 300,000,000 authorized; 201,268,321 and
		149,324,849 shares issued at September 30, 2018 and December 31, 2017,
		respectively			-		-
	Additional paid-in capital				14,749		7,142
	Retained earnings				2,613		1,840
	Treasury stock, at cost; 1,028,138 and 598,049 shares at September 30, 2018 and
		December 31, 2017, respectively			(130)		(67)
			Total stockholders’ equity		17,232		8,915
	Total liabilities and stockholders’ equity			$	25,210	$	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				Nine Months Ended
			September 30,				September 30,
(in millions, except per share amounts)				2018		2017		2018		2017

Operating revenues:
	Oil sales		$	957	$	498	$	2,545	$	1,461
	Natural gas sales			235		129		539		345
		Total operating revenues		1,192		627		3,084		1,806
Operating costs and expenses:
	Oil and natural gas production			156		106		416		293
	Production and ad valorem taxes			89		48		229		140
	Gathering, processing and transportation			16		-		36		-
	Exploration and abandonments			10		7		36		42
	Depreciation, depletion and amortization			406		284		1,033		848
	Accretion of discount on asset retirement obligations			3		2		7		6
	General and administrative (including non-cash stock-based
		compensation of $23 and $17 for the three months ended
		September 30, 2018 and 2017, respectively, and $58 and $43
		for the nine months ended September 30, 2018 and 2017,
		respectively)		84		64		221		180
	(Gain) loss on derivatives			625		206		793		(289)
	(Gain) loss on disposition of assets, net			5		(13)		(719)		(667)
	Transaction costs			23		-		39		2
		Total operating costs and expenses		1,417		704		2,091		555
Income (loss) from operations				(225)		(77)		993		1,251
Other income (expense):
	Interest expense			(46)		(39)		(103)		(118)
	Loss on extinguishment of debt			-		(65)		-		(66)
	Other, net			3		2		108		20
		Total other income (expense)		(43)		(102)		5		(164)
Income (loss) before income taxes				(268)		(179)		998		1,087
	Income tax (expense) benefit			69		66		(225)		(398)
Net income (loss)			$	(199)	$	(113)	$	773	$	689
Earnings per share:
	Basic net income (loss)		$	(1.05)	$	(0.77)	$	4.74	$	4.64
	Diluted net income (loss)		$	(1.05)	$	(0.77)	$	4.74	$	4.63

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		-		-		-		773		-		-		773
	Common stock issued in business combination		50,915		-		7,549		-		-		-		7,549
	Grants of restricted stock		646		-		-		-		-		-		-
	Performance unit share conversion		446		-		-		-		-		-		-
	Cancellation of restricted stock		(64)		-		-		-		-		-		-
	Stock-based compensation		-		-		58		-		-		-		58
	Purchase of treasury stock		-		-		-		-		430		(63)		(63)
BALANCE AT SEPTEMBER 30, 2018			201,268	$	-	$	14,749	$	2,613		1,028	$	(130)	$	17,232

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

Concho Resources Inc.

Consolidated Statements of Cash Flows

Unaudited


					Nine Months Ended
					September 30,
(in millions)					2018		2017
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income				$	773	$	689
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation, depletion and amortization				1,033		848
		Accretion of discount on asset retirement obligations				7		6
		Exploration and abandonments, including dry holes				20		29
		Non-cash stock-based compensation expense				58		43
		Deferred income taxes				225		392
		Gain on disposition of assets, net				(719)		(667)
		(Gain) loss on derivatives				793		(289)
		Net settlements received from (paid on) derivatives				(238)		126
		Loss on extinguishment of debt				-		66
		Other				(94)		1
	Changes in operating assets and liabilities, net of acquisitions and dispositions:
			Accounts receivable			(57)		(61)
			Prepaid costs and other			(15)		(1)
			Inventory			(12)		(1)
			Accounts payable			(27)		7
			Revenue payable			62		5
			Other current liabilities			52		(8)
				Net cash provided by operating activities		1,861		1,185
CASH FLOWS FROM INVESTING ACTIVITIES:
	Additions to oil and natural gas properties					(1,669)		(1,092)
	Acquisitions of oil and natural gas properties					(105)		(866)
	Additions to property, equipment and other assets					(53)		(34)
	Proceeds from the disposition of assets					260		803
	Direct transaction costs for disposition of assets					(3)		(18)
	Distribution from equity method investment					148		-
				Net cash used in investing activities		(1,422)		(1,207)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Borrowings under credit facility					2,408		473
	Payments on credit facility					(2,537)		(105)
	Issuance of senior notes, net					1,595		1,794
	Repayments of senior notes					-		(2,150)
	Repayments of RSP debt					(1,690)		-
	Debt extinguishment costs					(83)		(63)
	Payments for loan costs					(16)		(25)
	Purchase of treasury stock					(63)		(23)
	Increase (decrease) in bank overdrafts					(29)		68
				Net cash used in financing activities		(415)		(31)
				Net increase (decrease) in cash and cash equivalents		24		(53)
Cash and cash equivalents at beginning of period						-		53
Cash and cash equivalents at end of period					$	24	$	-
NON-CASH INVESTING AND FINANCING ACTIVITIES:
	Issuance of common stock for business combinations				$	7,549	$	291

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 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 in January 2018. 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, 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 (“U.S. GAAP”) 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, goodwill, 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.

Goodwill. As a result of the RSP Acquisition, as defined in Note 4, the Company has goodwill in the amount of $2.2 billion at September 30, 2018. Goodwill is not amortized but assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed as of July 1 of each year. The balance of goodwill is allocated in its entirety to the Company’s one reporting unit. When testing goodwill for impairment, the Company first performs a qualitative analysis to determine if it is more likely than not that the fair value of its reporting unit is less than its carrying

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

value. If the analysis shows that the fair value is more likely than not less than the carrying value, then the Company performs a quantitative impairment test. The reporting unit’s fair value is calculated as the combined market capitalization of the Company’s equity plus a control premium plus the fair value of the Company’s long-term debt. As the Company has elected to early adopt Accounting Standards Update (“ASU”) No. 2017-04, “Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (“ASU 2017-04”), if the results of the quantitative test are such that the fair value of the reporting unit is less than the carrying value, goodwill is then reduced by an amount that is equal to the amount by which the carrying value of the reporting unit exceeds the fair value.

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 (expense) 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. In February 2018, Oryx obtained a term loan of $800 million. The proceeds were used in part to fund a cash distribution to its 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 (expense) on the Company’s consolidated statement of operations 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. The Company recorded income of approximately $2 million for the three months ended September 30, 2017 and $5 million and $4 million for the nine months ended September 30, 2018 and 2017, respectively. The Company will not record income or loss on the Oryx investment until such net income is greater than the distribution in excess of its investment.

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.

Litigation contingencies. The Company is a party to proceedings and claims incidental to its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. The amount of any resulting losses may differ from these estimates. An accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable. See Note 10 for additional information.

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 reported net income (loss), cash flows from operations or statement of stockholders’ equity.

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

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

after production. At September 30, 2018, the Company had receivables related to contracts with customers of approximately $520 million.

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						Nine Months Ended
		September 30, 2018						September 30, 2018
		Under		Under		Increase		Under		Under		Increase
(in millions)		ASC 606		ASC 605		(Decrease)		ASC 606		ASC 605		(Decrease)

Operating revenues:
	Oil sales	$	957	$	952	$	5	$	2,545	$	2,537	$	8
	Natural gas sales		235		227		8		539		519		20

Operating costs and expenses:
	Oil and natural gas production		156		159		(3)		416		424		(8)
	Gathering, processing and transportation		16		-		16		36		-		36

Net income (loss)		$	(199)	$	(199)	$	-	$	773	$	773	$	-

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 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 the majority of the Company’s 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 September 30, 2018 and 2017 and $13 million and $12 million for the nine months ended September 30, 2018 and 2017, respectively.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Recently adopted accounting pronouncements. In January 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-04, which simplifies how an entity subsequently measures goodwill by eliminating Step 2 from the goodwill impairment test. In place of Step 2, under this standard an entity will recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to the reporting unit. This standard should be applied on a prospective basis and is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted after January 1, 2017. The Company has elected to early adopt this standard beginning in the third quarter of 2018. The early adoption of this standard did not have an impact on the Company’s financial results.

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. The Company does not plan to early adopt the standard. The Company plans to make policy elections to not capitalize short-term leases for all asset classes and to not separate non-lease components from lease components for all asset classes except for vehicles. The Company also plans to not elect the package of practical expedients that allows for certain considerations under the original “Leases (Topic 840)” accounting standard (“Topic 840”) to be carried forward upon adoption of ASU 2016-02.

The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, 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. Upon adoption, the Company will be required to recognize right-of-use assets and associated lease liabilities that are not currently recognized under applicable guidance. The Company does not believe this adoption will have a material impact on its consolidated balance sheets based on the leases in place as of the filing of this Quarterly Report.

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 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 July 2018, the FASB issued ASU No. 2018-11, “Targeted Improvements,” which provides a transition election to not restate comparative periods for the effects of applying the new lease standard. This transition election permits entities to change the date of initial application to the beginning of the year of adoption and to recognize the effects of applying the new standard as a cumulative-effect adjustment to the opening balance of retained earnings. The Company expects to elect this transition approach and recognize the cumulative impact of adoption in the opening balance of retained earnings as of January 1, 2019.

In July 2018, the FASB issued ASU No. 2018-09, “Codification Improvements,” which makes amendments to multiple codification topics to clarify, correct errors in, or make minor improvements to the accounting standards codification. The effective date of the standard is dependent on the facts and circumstances of each amendment. Some amendments do not require transition guidance and will be effective upon the issuance of this standard. Many of the amendments in ASU 2018-09 will be effective in annual periods beginning after December 15, 2018. The Company will be required to adopt this standard in the first quarter of fiscal 2019. The Company is currently assessing the effect that this ASU will have on the financial position, results of operations, and disclosures.

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

September 30, 2018

Unaudited

On August 17, 2018, the U.S. Securities and Exchange Commission (the “SEC”) issued a final rule that amends certain of its disclosure requirements that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes in stockholders’ equity. The final rule extends to interim periods the annual disclosure requirement in SEC Regulation S-X, Rule 3-04, of presenting changes in stockholders’ equity. The registrants will be required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. The final rule is effective for all filings submitted on or after November 5, 2018. The Company is currently analyzing the final rule and will comply with the new disclosure requirements for all filings after the effective date.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 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 nine months ended September 30, 2018:


		Nine Months Ended
(in millions)		September 30, 2018

Beginning capitalized exploratory well costs		$	182
	Additions to exploratory well costs pending the determination of proved reserves		321
	Reclassifications due to determination of proved reserves		(163)
	Disposition of wells		(14)
Ending capitalized exploratory well costs		$	326

The following table provides an aging at September 30, 2018 and December 31, 2017 of capitalized exploratory well costs based on the date drilling was completed:


		September 30,		December 31,
(in millions, except number of projects)		2018		2017

Capitalized exploratory well costs that have been capitalized for a period of one year		$	326	$	180
	or less
Capitalized exploratory well costs that have been capitalized for a period greater
	than one year		-		2
	Total capitalized exploratory well costs	$	326	$	182
Number of projects with exploratory well costs that have been capitalized for a period
	greater than one year		-		2

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Note 4. RSP Acquisition

On July 19, 2018, the Company completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). RSP was an independent oil and natural gas company engaged in the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of RSP’s acreage was located on large, contiguous acreage blocks in the core of the Midland Basin and Southern Delaware Basin. The acquisition added approximately 92,000 net acres. Under the terms of the Agreement and Plan of Merger (the “Acquisition Agreement”), each share of RSP common stock was converted into 0.320 of a share of the Company’s common stock. The Company issued approximately 51 million shares of common stock at a price of $148.27 per share, resulting in total consideration paid by the Company to the former RSP shareholders of approximately $7.5 billion.

In connection with the closing of the RSP Acquisition, the Company repaid outstanding principal under RSP’s revolving credit facility and redeemed and canceled all of RSP’s outstanding unsecured senior notes. See Note 9 for additional information regarding the Company’s debt activity.

In connection with the RSP Acquisition, the Company incurred approximately $23 million and $33 million of costs related to consulting, investment banking, advisory, legal and other acquisition-related fees during the three and nine months ended September 30, 2018, respectively, which are included in transaction costs in operating costs and expenses on the consolidated statements of operations. In addition, the Company acquired 670,369 shares of common stock from RSP employees for the payment of withholding taxes due on the vesting of their restricted shares pursuant to the Acquisition Agreement, resulting in an increase of approximately $32 million in the Company’s treasury stock balance.

Purchase price allocation. The RSP Acquisition has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of RSP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Any value assigned to goodwill is not expected to be deductible for income tax purposes. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of RSP’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including goodwill, may be revised as appropriate.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

The following table sets forth the Company’s preliminary purchase price allocation:


(in millions)

Total purchase price			$	7,549

Fair value of liabilities assumed:
	Accounts payable – trade		$	25
	Accrued drilling costs			131
	Current derivative instruments			10
	Other current liabilities			130
	Long-term debt			1,758
	Deferred income taxes			518
	Asset retirement obligations			16
	Noncurrent derivative instruments			5
		Total liabilities assumed	$	2,593

		Total purchase price plus liabilities assumed	$	10,142

Fair value of assets acquired:
	Accounts receivable		$	213
	Current derivative instruments			36
	Other current assets			21
	Proved oil and natural gas properties			4,052
	Unproved oil and natural gas properties			3,565
	Other property and equipment			5
	Noncurrent derivative instruments			2
	Other long-term assets			2
	Implied goodwill			2,246
		Total assets acquired	$	10,142

The fair values of assets acquired and liabilities assumed were based on the following key inputs:

Oil and natural gas properties

The fair value of proved and unproved oil and natural gas properties was measured using valuation techniques that convert the future cash flows to a single discounted amount. Significant inputs to the valuation of proved and unproved oil and natural gas properties include estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average costs of capital. The Company utilized a combination of the New York Mercantile Exchange (“NYMEX”) strip pricing and consensus pricing to value the reserves, then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the oil and natural gas properties acquired.

The fair value of asset retirement obligations totaled $16 million and is included in proved oil and natural gas properties with a corresponding liability in the table above. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

The inputs used to value oil and natural gas properties and asset retirement obligations require significant judgment and estimates made by management and represent Level 3 inputs.

Financial instruments and other

The fair value measurements of long-term debt were estimated based on the market prices and represent Level 1 inputs. The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves, implied market volatility, contract terms and prices and discount factors as of the close date of the RSP Acquisition and represent Level 2 inputs. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk and the derivative instruments in a liability position include a measure of the Company’s own nonperformance risk, each based on the current published credit default swap rates.

The fair values determined for accounts receivable, accounts payable – trade, accrued drilling costs and other current liabilities were equivalent to the carrying value due to their short-term nature.

Other current liabilities include approximately $22 million of liabilities primarily related to certain regulatory obligations.

Deferred income taxes

The RSP Acquisition qualified as a tax free merger whereby the Company acquired carryover tax basis in RSP’s assets and liabilities, adjusted for differences between the purchase price allocated to the assets acquired and liabilities assumed based on the fair value and the carryover tax basis. See Note 11 for additional discussion of deferred income taxes.

Goodwill recognized is primarily attributable to the following factors: (i) operating and administrative synergies and (ii) net deferred tax liabilities arising from the differences between the purchase price allocated to RSP’s assets and liabilities based on fair value and the tax basis of these assets and liabilities. For the operating and administrative synergies, the total consideration for the RSP Acquisition included a control premium, which resulted in a higher value compared to the fair value of net assets acquired. There are also other qualitative assumptions of long-term factors that the RSP Acquisition creates for the Company’s stockholders, including additional potential for exploration and development opportunities and additional scale and efficiencies in basins in which the Company already operates.

Approximately $250 million of operating revenues and approximately $15 million of loss from operations attributed to the RSP Acquisition are included in the Company’s results of operations from the closing date on July 19, 2018 through September 30, 2018.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Pro forma data. The following unaudited pro forma combined condensed financial data for the three and nine months ended September 30, 2018 and 2017 was derived from the historical financial statements of the Company giving effect to the RSP Acquisition, as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for RSP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert RSP’s outstanding shares of common stock and equity awards as of the closing date of the RSP Acquisition, (ii) the depletion of RSP’s fair-valued proved oil and gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $23 million and $33 million for the three and nine months ended September 30, 2018, respectively, and acquisition-related costs incurred by RSP and severance payments to certain RSP employees that totaled approximately $52 million and $56 million for the three and nine months ended September 30, 2018, respectively. The pro forma results of operations do not include any cost savings or other synergies that may result from the RSP Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the RSP assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. The pro forma combined condensed financial data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the RSP Acquisition taken place on January 1, 2017 and is not intended to be a projection of future results.


		Three Months Ended				Nine Months Ended
		September 30,				September 30,
(in millions, except per share amounts)			2018		2017		2018		2017

Operating revenues		$	1,243	$	829	$	3,741	$	2,361
Net income (loss)		$	(133)	$	(94)	$	1,039	$	780
Earnings per share:
	Basic net income (loss)	$	(0.67)	$	(0.47)	$	5.19	$	3.92
	Diluted net income (loss)	$	(0.67)	$	(0.47)	$	5.19	$	3.91

Note 5. Other acquisitions, divestitures and nonmonetary transactions

During the nine months ended September 30, 2018, the Company entered into the following transactions (exclusive of the RSP Acquisition disclosed in Note 4):

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 non-cash gain of approximately $575 million. The fair value of the assets acquired totaled approximately $755 million, which was 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 proceeds of approximately $280 million. 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 nine months ended September 30, 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 its July 2017 Midland Basin acquisition. In connection with the Reverse 1031 Exchange, the Company assigned the

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

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 nine months ended September 30, 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 $15 million.

During the nine months ended September 30, 2017, the Company entered into the following transactions:

Midland Basin acquisition. In July 2017, the Company completed an acquisition in the Midland Basin. As consideration for the acquisition, the Company paid approximately $595 million in cash. Concurrent with the acquisition, the Company entered into a transaction structured as a Reverse 1031 Exchange, which was completed in January 2018 upon the closing of its Southern Delaware Basin divestitures.

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 $801 million. After direct transaction costs, the Company recorded a pre-tax gain of approximately $655 million, which is included in gain on disposition of assets, net on its consolidated statement of operations for the nine months ended September 30, 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

September 30, 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 nine months ended September 30, 2018 is presented below:


		Restricted			Performance
		Stock Shares			Units

Outstanding at December 31, 2017			1,149,246			247,647
	Awards granted (a)		645,584	(b)		111,490
	Awards cancelled / forfeited		(64,379)			-
	Lapse of restrictions		(368,665)			-
Outstanding at September 30, 2018		1,361,786			359,137

(a) Weighted average grant date fair value per share/unit		$	137.89		$	216.03
(b) Includes 167,122 restricted stock shares granted to certain RSP employees on July 20, 2018.

The following table reflects the future stock-based compensation expense to be recorded for all the stock-based compensation awards that were outstanding at September 30, 2018:


(in millions)

Remaining 2018		$	25
2019			63
2020			33
2021			10
Thereafter			1
	Total	$	132

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 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

September 30, 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 September 30, 2018 and December 31, 2017:


			September 30, 2018				December 31, 2017
			Carrying		Fair		Carrying		Fair
(in millions)			Value		Value		Value		Value

		Derivative instrument liabilities	$	910	$	910	$	379	$	379
		Credit facility	$	193	$	193	$	322	$	322
		$600 million 4.375% senior notes due 2025 (a)	$	593	$	605	$	593	$	624
		$1,000 million 3.75% senior notes due 2027 (a)	$	988	$	959	$	987	$	1,012
		$1,000 million 4.3% senior notes due 2028 (a)	$	988	$	996	$	-	$	-
		$800 million 4.875% senior notes due 2047 (a)	$	789	$	814	$	789	$	874
		$600 million 4.85% senior notes due 2048 (a)	$	592	$	606	$	-	$	-


(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

September 30, 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 September 30, 2018 and December 31, 2017. The Company nets the fair value of derivative instruments by counterparty in the Company’s consolidated balance sheets.


September 30, 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		$	-	$	207	$	-	$	207	$	(207)	$	-
		Noncurrent:
			Commodity derivatives			-		17		-		17		(17)		-

	Liabilities:
		Current:
			Commodity derivatives			-		(754)		-		(754)		207		(547)
		Noncurrent:
			Commodity derivatives			-		(380)		-		(380)		17		(363)

	Net derivative instruments				$	-	$	(910)	$	-	$	(910)	$	-	$	(910)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 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 September 30, 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

September 30, 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 and nine months ended September 30, 2018 and 2017:


			Three Months Ended				Nine Months Ended
			September 30,				September 30,
(in millions)				2018		2017		2018		2017

*Gain (loss) on derivatives:*
	Oil derivatives		$	(626)	$	(205)	$	(787)	$	260
	Natural gas derivatives			1		(1)		(6)		29
		Total	$	(625)	$	(206)	$	(793)	$	289



The following table represents the Company’s net cash receipts from (payments on) derivatives for the three and nine months ended September 30, 2018 and 2017:



			Three Months Ended				Nine Months Ended
			September 30,				September 30,
(in millions)				2018		2017		2018		2017

*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	(46)	$	28	$	(245)	$	129
	Natural gas derivatives			2		2		7		(3)
		Total	$	(44)	$	30	$	(238)	$	126

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Commodity derivative contracts at September 30, 2018. The following table sets forth the Company’s outstanding derivative contracts at September 30, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed. All of the Company’s derivative contracts at September 30, 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)								11,902,007		11,902,007
		Price per Bbl							$	56.86	$	56.86
	*2019:*
		Volume (Bbl)		11,272,250		10,289,750		9,514,000		8,932,000		40,008,000
		Price per Bbl	$	56.14	$	55.83	$	55.61	$	55.44	$	55.78
	*2020:*
		Volume (Bbl)		6,680,500		6,344,500		6,049,000		5,814,000		24,888,000
		Price per Bbl	$	58.11	$	58.08	$	58.02	$	57.99	$	58.05
Oil Three-Way Collars: (a)
	*2018:*
		Volume (Bbl)								1,227,000		1,227,000
		Ceiling price per Bbl							$	60.96	$	60.96
		Floor price per Bbl							$	48.00	$	48.00
		Short put price per Bbl							$	38.00	$	38.00
Oil Costless Collars: (a)
	*2018:*
		Volume (Bbl)								1,058,000		1,058,000
		Ceiling price per Bbl							$	60.11	$	60.11
		Floor price per Bbl							$	46.52	$	46.52
	*2019:*
		Volume (Bbl)		1,335,250		1,213,250		1,135,000		1,058,000		4,741,500
		Ceiling price per Bbl	$	64.67	$	64.00	$	63.47	$	62.95	$	63.83
		Floor price per Bbl	$	56.46	$	56.06	$	55.74	$	55.43	$	55.96
Oil Basis Swaps: (b)
	*2018:*
		Volume (Bbl)								10,517,000		10,517,000
		Price per Bbl							$	(0.77)	$	(0.77)
	*2019:*
		Volume (Bbl)		11,730,000		11,419,500		10,994,000		10,533,000		44,676,500
		Price per Bbl	$	(2.93)	$	(3.02)	$	(2.97)	$	(3.07)	$	(2.99)
	*2020:*
		Volume (Bbl)		8,645,000		8,645,000		8,740,000		8,740,000		34,770,000
		Price per Bbl	$	(0.82)	$	(0.82)	$	(0.82)	$	(0.82)	$	(0.82)
Natural Gas Price Swaps: (c)
	*2018:*
		Volume (MMBtu)								18,458,000		18,458,000
		Price per MMBtu							$	3.00	$	3.00
	*2019:*
		Volume (MMBtu)		7,291,533		7,231,387		7,178,537		7,089,535		28,790,992
		Price per MMBtu	$	2.82	$	2.81	$	2.81	$	2.81	$	2.81
	*2020:*
		Volume (MMBtu)		3,276,000		3,276,000		3,128,000		3,128,000		12,808,000
		Price per MMBtu	$	2.70	$	2.70	$	2.70	$	2.70	$	2.70


(a) The oil derivative contracts are settled based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
(b) The basis differential price is between Midland – WTI and Cushing – WTI. The majority of these contracts are settled on a calendar-
month basis, while certain contracts assumed in connection with the RSP Acquisition are settled on a trading-month basis.
(c) The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

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.

Note 9. Debt

The Company’s debt consisted of the following at September 30, 2018 and December 31, 2017:


				September 30,		December 31,
(in millions)				2018		2017

Credit facility due 2022			$	193	$	322
4.375% unsecured senior notes due 2025 (a)				600		600
3.75% unsecured senior notes due 2027				1,000		1,000
4.3% unsecured senior notes due 2028				1,000		-
4.875% unsecured senior notes due 2047				800		800
4.85% unsecured senior notes due 2048				600		-
Unamortized original issue discount				(10)		(6)
Senior notes issuance costs, net				(40)		(25)
	Less: current portion			-		-
		Total long-term debt	$	4,143	$	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 September 30, 2018, the Company’s commitments from its bank group were $2.0 billion, of which $1.8 billion was unused commitments, net of letters of credit. During the nine months ended September 30, 2018, the weighted average interest rate on the Credit Facility was 4.6 percent.

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.

On July 2, 2018, the Company issued $1,600 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 4.3% unsecured senior notes due 2028 (the “4.3% Notes”) and $600 million in aggregate principal amount of 4.85% unsecured senior notes due 2048 (the “4.85% Notes” and, together with the 4.3% Notes, the “Notes”). The 4.3% Notes were issued at a price equal to 99.660 percent of par, and the 4.85% Notes were issued at a price equal to 99.740 percent of par. The net proceeds of approximately $1,579 million were used to redeem and cancel all of RSP’s outstanding $700 million aggregate principal amount of 6.625% unsecured senior notes due 2022 (the “RSP 2022 Notes”) and $450 million aggregate principal amount of 5.25% unsecured senior notes due 2025 (the “RSP 2025 Notes” and, together with the RSP 2022 Notes, the “RSP Notes”). The Company made aggregate payments of approximately $1.2 billion to redeem and cancel the RSP Notes, including make-whole call premiums of approximately $35 million and $33 million for the RSP 2022 Notes and RSP 2025 Notes, respectively. The Company also paid accrued interest of approximately $14 million on the RSP Notes. The remaining proceeds, along with borrowings under the Company’s Credit Facility, were used to repay the $540 million of outstanding principal under RSP’s revolving credit facility, including $1 million in accrued interest. See Note 4 for additional information regarding the RSP Acquisition.

At September 30, 2018, the Company was in compliance with the covenants under all of its debt instruments.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Interest expense. The following amounts have been incurred and charged to interest expense for the three and nine months ended September 30, 2018 and 2017:


		Three Months Ended				Nine Months Ended
		September 30,				September 30,
(in millions)			2018		2017		2018		2017

Cash payments for interest		$	16	$	73	$	76	$	138
Non-cash interest			1		1		4		5
Net changes in accruals			31		(35)		28		(25)
	Interest costs incurred		48		39		108		118
Less: capitalized interest			(2)		-		(5)		-
	Total interest expense	$	46	$	39	$	103	$	118

Note 10. Commitments and contingencies

Legal actions. The Company is a party to proceedings and claims incidental to its business. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter. For material matters that the Company believes an unfavorable outcome is reasonably possible, it would disclose the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. The Company does not believe that the loss for any other litigation matters and claims that are reasonably possible to occur will have a material adverse effect on its financial position, results of operations or liquidity. The Company will continue to evaluate proceedings and claims involving the Company on a regular basis and will establish and adjust any estimated accruals as appropriate.

Mabee Ranch litigation. On July 30, 2018, the owners of certain mineral and surface interests on the Mabee Ranch in Martin and Andrews Counties, Texas filed a lawsuit against the Company in Martin County District Court. These owners claimed that the Company breached certain leases by, among other things, exceeding permitted surface uses, failing to obtain required consents and failing to pay certain royalties due to them. The Company filed its answer to the lawsuit on September 10, 2018; shortly thereafter, the plaintiffs and the Company entered into settlement negotiations. Effective September 28, 2018, the parties executed a settlement agreement that provides for a dismissal of the lawsuit with prejudice.

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.

Regulatory and environmental compliance. Regulatory liabilities relate to acquisitions where additional equipment is necessary to have facilities compliant with local, state and federal obligations. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs. At September 30, 2018 and December 31, 2017, the Company had regulatory and environmental liabilities of approximately $32 million and $3 million, respectively.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

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 September 30, 2018:


(in millions)

Remaining 2018		$	66
2019			79
2020			80
2021			76
2022			36
2023			33
Thereafter			129
	Total	$	499

Throughput sales commitment. In May 2018, the Company entered into a one-year term oil marketing contract with a third-party purchaser. The contract requires the Company to deliver not less than seven thousand barrels per day. Should there be a delivery shortfall in any given month, the Company retains an option to deliver the shortfall volume in any two subsequent months; however, failure to meet this volume delivery commitment would result in a penalty equal to the volume shortfall multiplied by the then market price for oil. If production is not sufficient to meet the sales commitment, the Company may purchase commodities in the market to satisfy its commitment.

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 and $2 million for the three months ended September 30, 2018 and 2017, respectively, and approximately $9 million and $7 million for the nine months ended September 30, 2018 and 2017, respectively.

Future minimum lease commitments under non-cancellable operating leases at September 30, 2018 were as follows:


(in millions)

Remaining 2018		$	3
2019			13
2020			12
2021			9
2022			2
2023			-
Thereafter			1
	Total	$	40

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Note 11. Income taxes

The Company’s provision for income taxes for the nine months ended September 30, 2018 and 2017 is based on the estimated annual effective tax rate plus discrete items. The effective income tax rates were 26 percent and 37 percent for the three months ended September 30, 2018 and 2017, respectively, and 23 percent and 37 percent for the nine months ended September 30, 2018 and 2017, respectively.

The change in the Company’s effective tax rates for the three and nine months ended September 30, 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, including transaction costs incurred in connection with the RSP Acquisition, and (iii) state income taxes, net of federal income tax benefits. As a result of the RSP Acquisition described in Note 4 and below, the Company recorded an income tax benefit of approximately $7 million, net of federal benefit, due to a change in the Company’s estimated state tax rate. Additionally, the Company recorded a discrete income tax benefit related to stock-based awards of approximately $3 million and $6 million for the nine months ended September 30, 2018 and 2017, respectively.

On July 19, 2018, the Company completed the acquisition of RSP Permian Inc. For federal income tax purposes, the transaction qualified as a tax free merger whereby the Company acquired carryover tax basis in RSP’s assets and liabilities. The Company recorded an opening balance sheet deferred tax liability of $518 million, which includes a deferred tax asset related to tax attributes acquired from RSP. The acquired income tax attributes primarily consist of NOLs and research and development credits that are subject to an annual limitation under Internal Revenue Code Section 382. The Company expects that these tax attributes will be fully utilized prior to expiration.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position. As part of the RSP Acquisition, the Company recorded an unrecognized tax benefit of approximately $20 million, primarily related to research and development credits. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain.

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 September 30, 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. The Company has not finalized its accounting for the TCJA pending guidance on matters related to treatment of certain compensation and the completion of its re-measurement of certain deferred tax assets and liabilities. 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.

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 $2 million and $1 million for the three months ended September 30, 2018 and 2017, respectively, and approximately $6 million and $5 million for the nine months ended September 30, 2018 and 2017, respectively.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

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 and nine months ended September 30, 2018 and 2017, respectively, under the two-class method:


				Three Months Ended				Nine Months Ended
			September 30,				September 30,
(in millions)			2018		2017		2018		2017

Net income (loss) as reported			$	(199)	$	(113)	$	773	$	689
Participating basic earnings (a)				-		-		(6)		(5)
	Basic earnings attributable to common stockholders			(199)		(113)		767		684
Reallocation of participating earnings				-		-		-		-
	Diluted earnings attributable to common stockholders		$	(199)	$	(113)	$	767	$	684


(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

September 30, 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 and nine months ended September 30, 2018 and 2017:


			Three Months Ended		Nine Months Ended
			September 30,		September 30,
(in thousands)			2018	2017	2018	2017

*Weighted average common shares outstanding:*
	Basic		188,953	147,557	161,605	147,233
		Dilutive common stock options	-	-	-	4
		Dilutive performance units	313	-	342	549
	Diluted		189,266	147,557	161,947	147,786

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		Nine Months Ended
		September 30,		September 30,
(in thousands)		2018	2017	2018	2017

*Number of antidilutive units:*
	Antidilutive performance units	111	-	110	107

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

September 30, 2018

Unaudited

Note 14. Subsidiary guarantors

At September 30, 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 U.S. Securities and Exchange Commission, 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 nine months ended September 30, 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 September 30, 2018 and December 31, 2017, condensed consolidating statements of operations for the three and nine months ended September 30, 2018 and 2017 and condensed consolidating statements of cash flows for the nine months ended September 30, 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

September 30, 2018

Unaudited


Condensed Consolidating Balance Sheet
September 30, 2018


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

ASSETS
Accounts receivable - related parties		$	9,981	$	(8,190)	$	-	$	(1,791)	$	-
Other current assets			21		1,007		-		-		1,028
Oil and natural gas properties, net			-		21,601		17		-		21,618
Property and equipment, net			-		277		-		-		277
Investment in subsidiaries			5,097		-		-		(5,097)		-
Goodwill			-		2,246		-		-		2,246
Other long-term assets			17		24		-		-		41
	Total assets	$	15,116	$	16,965	$	17	$	(6,888)	$	25,210

LIABILITIES AND EQUITY
Accounts payable - related parties		$	(8,190)	$	9,964	$	17	$	(1,791)	$	-
Other current liabilities			657		1,219		-		-		1,876
Long-term debt			4,143		-		-		-		4,143
Other long-term liabilities			1,274		685		-		-		1,959
Equity			17,232		5,097		-		(5,097)		17,232
	Total liabilities and equity	$	15,116	$	16,965	$	17	$	(6,888)	$	25,210

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

September 30, 2018

Unaudited


Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2018


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

Total operating revenues		$	-	$	1,192	$	-	$	-	$	1,192
Total operating costs and expenses			(626)		(791)		-		-		(1,417)
	Income (loss) from operations		(626)		401		-		-		(225)
Interest expense			(46)		-		-		-		(46)
Other, net			404		3		-		(404)		3
	Income (loss) before income taxes		(268)		404		-		(404)		(268)
Income tax benefit			69		-		-		-		69
	Net income (loss)	$	(199)	$	404	$	-	$	(404)	$	(199)

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2017


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

Total operating revenues		$	-	$	619	$	8	$	-	$	627
Total operating costs and expenses			(207)		(491)		(6)		-		(704)
	Income (loss) from operations		(207)		128		2		-		(77)
Interest expense			(39)		-		-		-		(39)
Loss on extinguishment of debt			(65)		-		-		-		(65)
Other, net			132		2		-		(132)		2
	Income (loss) before income taxes		(179)		130		2		(132)		(179)
Income tax benefit			66		-		-		-		66
	Net income (loss)	$	(113)	$	130	$	2	$	(132)	$	(113)

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited


Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2018


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

Total operating revenues		$	-	$	3,079	$	5	$	-	$	3,084
Total operating costs and expenses			(794)		(1,294)		(3)		-		(2,091)
	Income (loss) from operations		(794)		1,785		2		-		993
Interest expense			(103)		-		-		-		(103)
Other, net			1,895		108		-		(1,895)		108
	Income before income taxes		998		1,893		2		(1,895)		998
Income tax expense			(225)		-		-		-		(225)
	Net income	$	773	$	1,893	$	2	$	(1,895)	$	773

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2017


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

Total operating revenues		$	-	$	1,798	$	8	$	-	$	1,806
Total operating costs and expenses			288		(837)		(6)		-		(555)
	Income from operations		288		961		2		-		1,251
Interest expense			(117)		(1)		-		-		(118)
Loss on extinguishment of debt			(66)		-		-		-		(66)
Other, net			982		20		-		(982)		20
	Income before income taxes		1,087		980		2		(982)		1,087
Income tax expense			(398)		-		-		-		(398)
	Net income	$	689	$	980	$	2	$	(982)	$	689

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited


Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2018


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

Net cash flows provided by operating activities		$	386	$	1,475		$	-	$	-	$	1,861
Net cash flows used in investing activities			-		(1,422)			-		-		(1,422)
Net cash flows used in financing activities			(386)		(29)			-		-		(415)
	Net increase in cash and cash equivalents		-		24			-		-		24
	Cash and cash equivalents at beginning of period		-		-			-		-		-
	Cash and cash equivalents at end of period	$	-	$	24		$	-	$	-	$	24

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2017


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

Net cash flows provided by operating activities		$	99	$	1,084	$	2	$	-	$	1,185
Net cash flows used in investing activities			-		(592)		(615)		-		(1,207)
Net cash flows provided by (used in) financing
	activities		(99)		(545)		613		-		(31)
	Net decrease in cash and cash equivalents		-		(53)		-		-		(53)
	Cash and cash equivalents at beginning of period		-		53		-		-		53
	Cash and cash equivalents at end of period	$	-	$	-	$	-	$	-	$	-

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Note 15. Subsequent events

New commodity derivative contracts. After September 30, 2018, the Company entered into the following derivative contracts to hedge additional amounts of estimated future production :


				First		Second		Third		Fourth
				Quarter		Quarter		Quarter		Quarter		Total

Oil Price Swaps: (a)
	*2019:*
		Volume (Bbl)		720,000		546,000		552,000		552,000		2,370,000
		Price per Bbl	$	67.15	$	67.11	$	67.11	$	67.11	$	67.12
	*2020:*
		Volume (Bbl)		455,000		455,000		368,000		368,000		1,646,000
		Price per Bbl	$	64.37	$	64.37	$	64.18	$	64.18	$	64.28


(a)	The oil derivative contracts are settled based on the NYMEX – WTI monthly average futures price.

Concho Resources Inc.

Condensed Notes to Consolidated Financial Statements

September 30, 2018

Unaudited

Note 16. Supplementary information

Capitalized costs


			September 30,		December 31,
(in millions)			2018		2017

*Oil and natural gas properties:*
	Proved		$	24,361	$	18,565
	Unproved			6,619		2,702
	Less: accumulated depletion			(9,362)		(8,460)
		Net capitalized costs for oil and natural gas properties	$	21,618	$	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				Nine Months Ended
		September 30,				September 30,
(in millions)		2018		2017		2018		2017

Property acquisition costs:
	Proved	$	4,126	$	162	$	4,126	$	301
	Unproved		3,578		472		3,596		865
Exploration			481		252		1,059		725
Development			280		175		653		478
	Total costs incurred for oil and natural gas properties	$	8,465	$	1,061	$	9,434	$	2,369

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

Concho Resources Inc. (“Concho,” the “Company,” “we,” “us,” and “our”) is an independent exploration and production company. We are one of the largest operators 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 large-scale development projects, which include long-lateral wells, enhanced completion techniques and multi-well pad locations, throughout our operating areas.

Financial and Operating Performance

On July 19, 2018, we completed our acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”), which, among other things, impacted the comparability of our results of operations. Our financial and operating performance for the nine months ended September 30, 2018 and 2017 included the following highlights:

· Net income was $773 million ($4.74 per diluted share) as compared to $689 million ($4.63 per diluted share) for the first nine months of 2018 and 2017, respectively. The increase was primarily due to:

• $1.3 billion increase in oil and natural gas revenues as a result of a 33 percent increase in production and a 28 percent increase in commodity price realizations per Boe (excluding the effects of derivative activities);

• $173 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 nine months ended September 30, 2018, as compared to 2017;

• $88 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

• $52 million net increase in gain on disposition of assets due to a gain of approximately $719 million during the nine months ended September 30, 2018 primarily due to our February 2018 acquisition and divestiture and Southern Delaware Basin divestitures, as compared to a gain of approximately $667 million during 2017 primarily due to our disposition of Alpha Crude Connector, LLC (“ACC”);

partially offset by:

• $1.1 billion change in (gain) loss on derivatives due to a $793 million loss on derivatives during the nine months ended September 30, 2018, as compared to a $289 million gain during 2017;

• $185 million increase in depreciation, depletion and amortization expense, primarily due to an increase in production, partially offset by a lower depletion rate per Boe;

• $123 million increase in production expense, primarily due to (i) increased production and activities associated with the additional wells successfully drilled and completed in 2017 and 2018, (ii) our acquisitions and nonmonetary transactions during the fourth quarter of 2017 and first nine months of 2018, (iii) increased cost of services and (iv) increased workover costs;

• $89 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; and

• $37 million increase in transaction costs, primarily due to consulting, investment banking, advisory, legal and other fees related to the RSP Acquisition.

· Average daily sales volumes of 248 MBoe per day during the first nine months of 2018 increased 33 percent as compared to 186 MBoe per day during 2017.

· Net cash provided by operating activities increased by approximately $676 million to $1,861 million for the first nine months of 2018, as compared to $1,185 million in the first nine 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) increased production expense and (iii) 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;

· 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;

· 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;

· 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 quality of the oil we produce;

· the price and availability of alternative fuels; and

· 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.

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 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 September 30, 2018 and additional derivative contracts entered into subsequent to September 30, 2018, respectively.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. The average New York Mercantile Exchange (“NYMEX”) oil price was higher and the average NYMEX natural gas price was lower during the comparable periods of 2018 measured against 2017. The following table sets forth the average NYMEX oil and natural gas prices for the three and nine months ended September 30, 2018 and 2017, as well as the high and low NYMEX prices for the same periods:


			Three Months Ended				Nine Months Ended
			September 30,				September 30,
			2018		2017		2018		2017

Average NYMEX prices:
	Oil (Bbl)		$	69.60	$	48.12	$	66.83	$	49.45
	Natural gas (MMBtu)		$	2.87	$	2.95	$	2.85	$	3.06

High and Low NYMEX prices:
	*Oil (Bbl):*
		High	$	74.15	$	52.22	$	74.15	$	54.45
		Low	$	65.01	$	44.23	$	59.19	$	42.53
	*Natural gas (MMBtu):*
		High	$	3.08	$	3.15	$	3.63	$	3.72
		Low	$	2.72	$	2.77	$	2.55	$	2.56

Further, the NYMEX oil price and NYMEX natural gas price reached highs and lows of $76.41 and $66.43 per Bbl and $3.32 and $3.09 per MMBtu, respectively, during the period from October 1, 2018 to October 29, 2018. At October 29, 2018, the NYMEX oil price and NYMEX natural gas price were $67.04 per Bbl and $3.19 per MMBtu, respectively.

Historically, and during the nine months ended September 30, 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. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) reflected a price greater than the related NYMEX natural gas price for the three and nine months ended September 30, 2018. The average Mont Belvieu price for a blended barrel of natural gas liquids was $34.82 per Bbl and $25.04 per Bbl during the three months ended September 30, 2018 and 2017, respectively, and $30.73 per Bbl and $23.74 per Bbl during the nine months ended September 30, 2018 and 2017, respectively.

Recent Events

2019 capital budget and dividends. In October 2018, our board approved the 2019 capital budget of up to $3.8 billion. We expect our 2019 capital spending on drilling and completion activity to range between $3.4 billion and $3.6 billion. Additionally, subject to declaration by our board, we plan to initiate a quarterly dividend of $0.125 per share beginning in the first quarter of 2019, with an indicated annual rate of $0.50 per share.

RSP Acquisition. On July 19, 2018, we completed the RSP Acquisition. Under the terms of the Agreement and Plan of Merger (the “Acquisition Agreement”), each share of RSP common stock was converted into 0.320 of a share of our common stock. We issued approximately 51 million shares of common stock at a price of $148.27 per share, resulting in total consideration paid to the former RSP shareholders of approximately $7.5 billion. Refer to Note 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding the acquisition.

Long-term debt. On July 2, 2018, we issued $1,600 million in aggregate principal amount of unsecured senior notes, consisting of $1,000 million in aggregate principal amount of 4.3% unsecured senior notes due 2028 (the “4.3% Notes”) and $600 million in aggregate principal amount of 4.85% unsecured senior notes due 2048 (the “4.85% Notes” and, together with the 4.3% Notes, the “Notes”). The net proceeds of approximately $1,579 million were used to redeem and cancel all of RSP’s outstanding $700 million aggregate principal amount of 6.625% unsecured senior notes due 2022 (the “RSP 2022 Notes”) and $450 million aggregate principal amount of 5.25% unsecured senior notes due 2025 (the “RSP 2025 Notes” and, together with the RSP 2022 Notes, the “RSP Notes”) and to repay a portion of the outstanding indebtedness under RSP’s existing credit facility. We repaid the remaining balance under RSP’s credit facility with borrowings under our credit facility, as amended and restated (our “Credit Facility”), resulting in a total payoff of $1,773 million, which included the accrued interest and premiums on the senior notes and other fees and expenses related to RSP’s credit facility.

2018 capital budget. In July 2018, our board approved a revised 2018 capital budget of up to $2.7 billion. The revised budget includes capital we plan to invest during the second half of the year on the acquired RSP assets. We expect our 2018 capital spending on drilling and completion activity to range between $2.5 billion and $2.6 billion. Our 2018 capital budget, excluding acquisitions and based on our current expectations of commodity prices and costs, is expected to be within our operating cash flows.

Derivative Financial Instruments

Derivative financial instrument exposure. At September 30, 2018, the fair value of our financial derivatives was a net liability of $910 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 do not allow us to offset amounts we may owe a lender against amounts we may be owed related to our derivative financial instruments with such party.

New commodity derivative contracts. After September 30, 2018, we entered into derivative contracts to hedge additional amounts of estimated future production. Refer to Note 15 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding these commodity derivative contracts.

Results of Operations

The following table sets forth summary information concerning our production and operating data for the three and nine months ended September 30, 2018 and 2017. The actual historical data in this table excludes results from the RSP Acquisition for periods prior to July 19, 2018. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions and divestitures, the historical information presented below should not be interpreted as being indicative of future results.


					Three Months Ended				Nine Months Ended
					September 30,				September 30,
					2018		2017		2018		2017

*Production and operating data:*
	Net production volumes:
		Oil (MBbl)				16,979		11,000		42,947		31,527
		Natural gas (MMcf)				56,348		40,626		148,633		116,241
		Total (MBoe)				26,370		17,771		67,719		50,901

	Average daily production volumes:
		Oil (Bbl)				184,554		119,565		157,315		115,484
		Natural gas (Mcf)				612,478		441,587		544,443		425,791
		Total (Boe)				286,634		193,163		248,056		186,449

	Average prices per unit:
		Oil, without derivatives (Bbl)			$	56.38	$	45.29	$	59.25	$	46.34
		Oil, with derivatives (Bbl) (a)			$	53.67	$	47.81	$	53.55	$	50.45
		Natural gas, without derivatives (Mcf)			$	4.18	$	3.18	$	3.63	$	2.96
		Natural gas, with derivatives (Mcf) (a)			$	4.21	$	3.22	$	3.67	$	2.94
		Total, without derivatives (Boe)			$	45.23	$	35.29	$	45.54	$	35.47
		Total, with derivatives (Boe) (a)			$	43.56	$	36.96	$	42.02	$	37.95

	Operating costs and expenses per Boe: (b)
		Oil and natural gas production			$	5.93	$	5.99	$	6.15	$	5.76
		Production and ad valorem taxes			$	3.37	$	2.70	$	3.38	$	2.75
		Gathering, processing and transportation			$	0.60	$	-	$	0.53	$	-
		Depreciation, depletion and amortization			$	15.43	$	16.00	$	15.27	$	16.66
		General and administrative			$	3.13	$	3.60	$	3.26	$	3.56


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


					Three Months Ended				Nine Months Ended
					September 30,				September 30,
		(in millions)			2018		2017		2018		2017

		Net cash receipts from (payments on) derivatives:
			Oil derivatives		$	(46)	$	28	$	(245)	$	129
			Natural gas derivatives			2		2		7		(3)
				Total	$	(44)	$	30	$	(238)	$	126


		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.

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017

Oil and natural gas revenues. Revenue from oil and natural gas operations was $1,192 million for the three months ended September 30, 2018, an increase of $565 million (90 percent) from $627 million for 2017. This increase was primarily due to the increase in oil and natural gas production attributable to the RSP Acquisition and wells successfully drilled and completed, 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 16,979 MBbl for the three months ended September 30, 2018, an increase of 5,979 MBbl (54 percent) from 11,000 MBbl for 2017;

· average realized oil price (excluding the effects of derivative activities) was $56.38 per Bbl during the three months ended September 30, 2018, an increase of 24 percent from $45.29 per Bbl during 2017. For the three months ended September 30, 2018, our crude oil price differential relative to NYMEX was $(13.22) per Bbl, or a realization of approximately 81 percent, as compared to a crude oil price differential relative to NYMEX of $(2.83) per Bbl, or a realization of approximately 94 percent, for 2017. The basis differential (referred to as the “Mid-Cush 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 September 30, 2018 and 2017, the average market Mid-Cush differentials were price reductions of $(12.66) per Bbl and $(0.75) per Bbl, respectively. Our crude oil price differential relative to NYMEX excluding the Mid-Cush differential was $(0.56) per Bbl for the three months ended September 30, 2018, as compared to $(2.08) per Bbl for the three months ended September 30, 2017. This difference was due to the fluctuation between the price we receive, which is based on a calendar month average, as compared to NYMEX;

· total natural gas production was 56,348 MMcf for the three months ended September 30, 2018, an increase of 15,722 MMcf (39 percent) from 40,626 MMcf for 2017; and

· average realized natural gas price (excluding the effects of derivative activities) was $4.18 per Mcf during the three months ended September 30, 2018, an increase of 31 percent from $3.18 per Mcf during 2017. For the three months ended September 30, 2018 and 2017, we realized approximately 146 percent and 108 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Historically, and during the three months ended September 30, 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. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) reflected a price greater than the related NYMEX natural gas price for the three months ended September 30, 2018. The increase in our realized natural gas price (excluding the effects of derivatives) as a percentage of NYMEX during the three months ended September 30, 2018 as compared to 2017 was primarily due to an increase in the average Mont Belvieu price for a blended barrel of natural gas liquids, which was $34.82 per Bbl and $25.04 per Bbl during the three months ended September 30, 2018 and 2017, respectively. The increase in our realized natural gas price was also due to the adoption of ASC 606, as our natural gas realized price was $0.15 per Mcf higher than what it would have been under the previous revenue standard.

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 September 30, 2018 and 2017:


			Three Months Ended September 30,
			2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Lease operating expenses		$	146	$	5.54	$	100	$	5.68
Workover costs			10		0.39		6		0.31
	Total oil and natural gas production expenses	$	156	$	5.93	$	106	$	5.99

Lease operating expenses were $146 million ($5.54 per Boe) for the three months ended September 30, 2018, which was an increase of $46 million from $100 million ($5.68 per Boe) during 2017. The increase in lease operating expenses during the third quarter of 2018 as compared to 2017 was primarily due to (i) increased production and activities associated with the RSP Acquisition and additional wells successfully drilled and completed and (ii) increased cost of services. The decrease in lease operating expenses per Boe was primarily due to increased production, partially offset by the increase in lease operating expenses noted above.

Workover costs were $10 million ($0.39 per Boe) for the three months ended September 30, 2018, which was an increase of $4 million from $6 million ($0.31 per Boe) during 2017. The increase in workover costs during the third quarter of 2018 as compared to 2017 was primarily due to increased workover activity and cost of services. The increase in workover costs per Boe was primarily due to the increase in workover costs noted above, 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 September 30, 2018 and 2017:


			Three Months Ended September 30,
			2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Production taxes		$	79	$	2.98	$	44	$	2.48
Ad valorem taxes			10		0.39		4		0.22
	Total production and ad valorem taxes	$	89	$	3.37	$	48	$	2.70

Production taxes per unit of production were $2.98 per Boe during the three months ended September 30, 2018, an increase of 20 percent from $2.48 per Boe during 2017. Over the same period, our revenue per Boe (excluding the effects of derivatives) increased 28 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 September 30, 2018:


		Three Months Ended
		September 30, 2018
			Per
(in millions, except per unit amounts)	Amount		Boe

Gathering, processing and transportation costs	$	16	$	0.60

Gathering, processing and transportation costs were $16 million ($0.60 per Boe) for the three months ended September 30, 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. In addition, our gathering, processing and transportation costs are impacted by production volumes and fixed costs associated with certain contracts.

Exploration and abandonments expense. The following table provides the components of our exploration and abandonments expense for the three months ended September 30, 2018 and 2017:


		Three Months Ended
		September 30,
(in millions)		2018		2017

Geological and geophysical		$	2	$	2
Leasehold abandonments			6		-
Other			2		5
	Total exploration and abandonments	$	10	$	7

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing subsurface data to better characterize and develop our resources.

For the three months ended September 30, 2018, we recorded approximately $6 million of leasehold abandonments, which were primarily related to acreage in the Northern Delaware Basin where we had no future plans to drill and acres which expired 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 September 30, 2018 and 2017:


		Three Months Ended September 30,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties		$	401	$	15.19	$	279	$	15.67
Depreciation of other property and equipment			5		0.20		5		0.31
Amortization of intangible assets			-		0.04		-		0.02
	Total depletion, depreciation and amortization	$	406	$	15.43	$	284	$	16.00

Oil price used to estimate proved oil reserves at period end		$	59.92			$	46.27
Natural gas price used to estimate proved natural gas reserves at period end		$	2.91			$	3.00

Depletion of proved oil and natural gas properties was $401 million ($15.19 per Boe) for the three months ended September 30, 2018, an increase of $122 million (44 percent) from $279 million ($15.67 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 the increase in proved reserves due to our successful exploratory drilling program, cost reductions and higher oil prices. The decrease in depletion expense per Boe was partially offset by an increase in capitalized leasehold costs from the RSP Acquisition.

General and administrative expenses. The following table provides components of our general and administrative expenses for the three months ended September 30, 2018 and 2017:


		Three Months Ended September 30,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

General and administrative expenses		$	65	$	2.46	$	51	$	2.89
Less: Operating fee reimbursements			(4)		(0.19)		(4)		(0.24)
Non-cash stock-based compensation			23		0.86		17		0.95
	Total general and administrative expenses	$	84	$	3.13	$	64	$	3.60

General and administrative expenses were approximately $84 million ($3.13 per Boe) for the three months ended September 30, 2018, an increase of $20 million (31 percent) from $64 million ($3.60 per Boe) for 2017. The increases in cash general and administrative and non-cash stock-based compensation expenses were primarily the result of increased 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 and $4 million for the three months ended September 30, 2018 and 2017, respectively.

Gain (loss) on derivatives. The following table sets forth the gain (loss) on derivatives for the three months ended September 30, 2018 and 2017:


			Three Months Ended
			September 30,
(in millions)				2018		2017

*Gain (loss) on derivatives:*
	Oil derivatives		$	(626)	$	(205)
	Natural gas derivatives			1		(1)
		Total	$	(625)	$	(206)


The following table represents our net cash receipts from (payments on) derivatives for the three months ended September 30, 2018 and 2017:


			Three Months Ended
			September 30,
(in millions)				2018		2017

*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	(46)	$	28
	Natural gas derivatives			2		2
		Total	$	(44)	$	30

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.

Interest expense. The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the three months ended September 30, 2018 and 2017:


		Three Months Ended
		September 30,
(in millions)		2018		2017

Interest expense, as reported		$	46	$	39
Capitalized interest			2		-
	Interest expense, excluding impact of capitalized interest	$	48	$	39

Weighted average interest rate - credit facility			4.8%		4.8%
Weighted average interest rate - senior notes			4.4%		5.2%
	Total weighted average interest rate		4.4%		5.2%

Weighted average credit facility balance		$	152	$	12
Weighted average senior notes balance			3,982		2,731
	Total weighted average debt balance	$	4,134	$	2,743

The increase in interest expense was due to the increase in the weighted average debt balance, partially offset by the decrease in the weighted average interest rate and an increase in capitalized interest. The increase in the weighted average debt balance was due primarily to the Notes issued in connection with the RSP Acquisition.

Loss on extinguishment of debt. We recorded a loss on extinguishment of debt of approximately $65 million for the three months ended September 30, 2017. This amount includes approximately $36 million associated with the premium paid for the cash tender offer and redemption 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 (collectively, the “5.5% Notes”), approximately $25 million associated with the make-whole premium paid for the early extinguishment of the 5.5% Notes, approximately $21 million of unamortized deferred loan costs and approximately $2 million of additional interest on the 5.5% Notes to October 13, 2017, which was paid in September 2017, reduced by approximately $19 million of unamortized premium.

Income tax provisions. For the three months ended September 30, 2018 and 2017, we recorded an income tax benefit of approximately $69 million and $66 million, respectively. The amount for the three months ended September 30, 2018 includes discrete income tax benefits of approximately $7 million, primarily related to a change in our estimated state tax rate.

The effective income tax rates for the three months ended September 30, 2018 and 2017 were 26 percent and 37 percent, respectively. The change in our effective income tax rate was primarily due to the decrease in the U.S. federal statutory rate from 35 percent to 21 percent.

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017

Oil and natural gas revenues. Revenue from oil and natural gas operations was $3,084 million for the nine months ended September 30, 2018, an increase of $1,278 million (71 percent) from $1,806 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 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 42,947 MBbl for the nine months ended September 30, 2018, an increase of 11,420 MBbl (36 percent) from 31,527 MBbl for 2017;

· average realized oil price (excluding the effects of derivative activities) was $59.25 per Bbl during the nine months ended September 30, 2018, an increase of 28 percent from $46.34 per Bbl during 2017. For the nine months ended September 30, 2018, our crude oil price differential relative to NYMEX was $(7.58) per Bbl, or a realization of approximately 89 percent, as compared to a crude oil price differential relative to NYMEX of $(3.11) per Bbl, or a realization of approximately 94 percent, for 2017. The basis differential (referred to as the “Mid-Cush differential”) between the location of Midland, Texas and Cushing, Oklahoma (NYMEX pricing location) for our oil directly impacts our realized oil price. For the nine months ended September 30, 2018 and 2017, the average market Mid-Cush differentials were price reductions of $(5.81) per Bbl and $(0.31) per Bbl, respectively. Our crude oil price differential relative to NYMEX excluding the Mid-Cush differential was $(1.77) per Bbl for the nine months ended September 30, 2018, as compared to $(2.80) per Bbl for the nine months ended September 30, 2017. This difference was due to the fluctuation between the price we receive, which is based on a calendar month average, as compared to NYMEX;

· total natural gas production was 148,633 MMcf for the nine months ended September 30, 2018, an increase of 32,392 MMcf (28 percent) from 116,241 MMcf for 2017; and

· average realized natural gas price (excluding the effects of derivative activities) was $3.63 per Mcf during the nine months ended September 30, 2018, an increase of 23 percent from $2.96 per Mcf during 2017. For the nine months ended September 30, 2018 and 2017, we realized approximately 127 percent and 97 percent, respectively, of the average NYMEX natural gas prices for the respective periods. Historically, and during the nine months ended September 30, 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. Because of our liquids-rich natural gas stream and the related value of the natural gas liquids being included in our natural gas revenues, our realized natural gas price (excluding the effects of derivatives) reflected a price greater than the related NYMEX natural gas price for the nine months ended September 30, 2018. The increase in our realized natural gas price (excluding the effects of derivatives) as a percentage of NYMEX during the nine months ended September 30, 2018 as compared to 2017 was primarily due to an increase in the average Mont Belvieu price for a blended barrel of natural gas liquids, which was $30.73 per Bbl and $23.74 per Bbl during the nine months ended September 30, 2018 and 2017, respectively. The increase in our realized natural gas price was also due to the adoption of ASC 606, as our natural gas realized price was $0.14 per Mcf higher than what it would have been under the previous revenue standard.

Oil and natural gas production expenses. The following table provides the components of our oil and natural gas production expenses for the nine months ended September 30, 2018 and 2017:


		Nine Months Ended September 30,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Lease operating expenses		$	388	$	5.73	$	278	$	5.47
Workover costs			28		0.42		15		0.29
	Total oil and natural gas production expenses	$	416	$	6.15	$	293	$	5.76

Lease operating expenses were $388 million ($5.73 per Boe) for the nine months ended September 30, 2018, which was an increase of $110 million from $278 million ($5.47 per Boe) during 2017. The increase in lease operating expenses during the nine months ended September 30, 2018 as compared to 2017 was primarily due to (i) increased production and activities associated with the additional wells successfully drilled and completed and the RSP Acquisition, (ii) our acquisitions and nonmonetary transactions during the fourth quarter of 2017 and first nine months of 2018, particularly our July 2017 Midland Basin acquisition and our February 2018 acquisition and divestiture, whose associated properties incur higher lease operating expense per Boe than our legacy assets and (iii) increased cost of services. The increase in lease operating expenses per Boe was primarily due to the increase in lease operating expenses noted above, partially offset by an increase in production.

Workover costs were $28 million ($0.42 per Boe) for the nine months ended September 30, 2018, which was an increase of $13 million from $15 million ($0.29 per Boe) during 2017. The increase in workover costs during the nine months ended September 30, 2018 as compared to 2017 was primarily due to increased workover activity and cost of services. The increase in workover costs per Boe was primarily due to the increase in workover costs noted above, 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 nine months ended September 30, 2018 and 2017:


		Nine Months Ended September 30,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

Production taxes		$	207	$	3.05	$	128	$	2.52
Ad valorem taxes			22		0.33		12		0.23
	Total production and ad valorem taxes	$	229	$	3.38	$	140	$	2.75

Production taxes per unit of production were $3.05 per Boe during the nine months ended September 30, 2018, an increase of 21 percent from $2.52 per Boe during 2017. Over the same period, our revenue per Boe (excluding the effects of derivatives) increased 28 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 nine months ended September 30, 2018:


		Nine Months Ended
		September 30, 2018
			Per
(in millions, except per unit amounts)	Amount		Boe

Gathering, processing and transportation costs	$	36	$	0.53

Gathering, processing and transportation costs were $36 million ($0.53 per Boe) for the nine months ended September 30, 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 nine months ended September 30, 2018 and 2017:


		Nine Months Ended
		September 30,
(in millions)		2018		2017

Geological and geophysical		$	9	$	9
Leasehold abandonments			20		24
Other			7		9
	Total exploration and abandonments	$	36	$	42

Our geological and geophysical expense for the periods presented above primarily consists of the costs of acquiring and processing subsurface data to better characterize and develop our resources.

For the nine months ended September 30, 2018 and 2017, we recorded approximately $20 million and $24 million, respectively, of leasehold abandonments. For the nine months ended September 30, 2018, our abandonments were primarily related to (i) expiring acreage in the Southern Delaware Basin and (ii) acreage in the Southern Delaware Basin, Northern Delaware Basin and New Mexico Shelf where we had no future plans to drill. For the nine months ended September 30, 2017, our abandonments were primarily related to (i) non-contiguous acreage expiring in the Southern Delaware Basin and (ii) acreage in the Northern Delaware Basin and New Mexico Shelf in locations where we have no future plans to drill.

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 nine months ended September 30, 2018 and 2017:


		Nine Months Ended September 30,
		2018				2017
					Per				Per
(in millions, except per unit amounts)			Amount		Boe		Amount		Boe

Depletion of proved oil and natural gas properties		$	1,015	$	14.99	$	830	$	16.31
Depreciation of other property and equipment			16		0.24		17		0.33
Amortization of intangible assets - operating rights			2		0.04		1		0.02
	Total depletion, depreciation and amortization	$	1,033	$	15.27	$	848	$	16.66

Depletion of proved oil and natural gas properties was $1,015 million ($14.99 per Boe) for the nine months ended September 30, 2018, an increase of $185 million (22 percent) from $830 million ($16.31 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 the increase in proved reserves due to our successful exploratory drilling program, cost reductions and higher oil prices. The decrease in depletion expense per Boe was partially offset by an increase in capitalized leasehold costs from the RSP Acquisition.

General and administrative expenses. The following table provides components of our general and administrative expenses for the nine months ended September 30, 2018 and 2017:


		Nine Months Ended September 30,
		2018				2017
				Per				Per
(in millions, except per unit amounts)		Amount		Boe		Amount		Boe

General and administrative expenses		$	176	$	2.60	$	149	$	2.95
Less: Operating fee reimbursements			(13)		(0.20)		(12)		(0.24)
Non-cash stock-based compensation			58		0.86		43		0.85
	Total general and administrative expenses	$	221	$	3.26	$	180	$	3.56

General and administrative expenses were approximately $221 million ($3.26 per Boe) for the nine months ended September 30, 2018, an increase of $41 million (23 percent) from $180 million ($3.56 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 $13 million and $12 million for the nine months ended September 30, 2018 and 2017, respectively.

Gain (loss) on derivatives. The following table sets forth the gain (loss) on derivatives for the nine months ended September 30, 2018 and 2017:


			Nine Months Ended
			September 30,
(in millions)				2018		2017

*Gain (loss) on derivatives:*
	Oil derivatives		$	(787)	$	260
	Natural gas derivatives			(6)		29
		Total	$	(793)	$	289


The following table represents our net cash receipts from (payments on) derivatives for the nine months ended September 30, 2018 and 2017:


			Nine Months Ended
			September 30,
(in millions)				2018		2017

*Net cash receipts from (payments on) derivatives:*
	Oil derivatives		$	(245)	$	129
	Natural gas derivatives			7		(3)
		Total	$	(238)	$	126

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 nine months ended September 30, 2018, we recognized a non-cash gain of approximately $575 million related to our February 2018 acquisition and divestiture.

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

During the nine months ended September 30, 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 $15 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 $801 million. After direct transaction costs, we recorded a pre-tax gain on disposition of assets of approximately $655 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 nine months ended September 30, 2018 and 2017:


		Nine Months Ended
		September 30,
(in millions)		2018		2017

Interest expense, as reported		$	103	$	118
Capitalized interest			5		-
	Interest expense, excluding impact of capitalized interest	$	108	$	118

Weighted average interest rate - credit facility			4.6%		4.5%
Weighted average interest rate - senior notes			4.3%		5.2%
	Total weighted average interest rate		4.3%		5.2%

Weighted average credit facility balance		$	138	$	6
Weighted average senior notes balance			2,927		2,744
	Total weighted average debt balance	$	3,065	$	2,750

The decrease in interest expense was due to the decrease in the weighted average interest rate and an increase in capitalized interest, partially offset by the increase in the weighted average debt balance.

The increase in the weighted average debt balance was due primarily to the Notes issued in connection with the RSP Acquisition.

Loss on extinguishment of debt. We recorded a loss on extinguishment of debt of approximately $66 million for the nine months ended September 30, 2017. This amount includes: (i) approximately $36 million associated with the premium paid for the cash tender offer and redemption of the 5.5% Notes, approximately $25 million associated with the make-whole premium paid for the early extinguishment of the 5.5% Notes, approximately $21 million of unamortized deferred loan costs and approximately $2 million of additional interest on the 5.5% Notes to October 13, 2017, which was paid in September 2017, reduced by approximately $19 million of unamortized premium; and (ii) approximately $1 million representing the proportional amount of unamortized deferred loan costs associated with banks that are no longer in the credit facility syndicate as a result of the April 2017 credit facility amendment.

Other income, net. During the nine months ended September 30, 2018, we recorded other income of approximately $108 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 nine months ended September 30, 2018 and 2017, we recorded income tax expense of approximately $225 million and $398 million, respectively. The amount for the nine months ended September 30, 2018 includes discrete income tax benefits of approximately $7 million, primarily related to a change in our estimated state tax rate. The amounts for the nine months ended September 30, 2018 and 2017 include discrete income tax benefits of approximately $3 million and $6 million, respectively, related to excess tax benefits on stock-based awards.

The effective income tax rates for the nine months ended September 30, 2018 and 2017 were 23 percent and 37 percent, respectively. The change in our effective income tax rate was primarily due to the decrease in the U.S. federal statutory rate from 35 percent to 21 percent.

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 nine months ended September 30, 2018 and 2017 totaled $1.7 billion and $1.2 billion, respectively. The increase was primarily due to our increased drilling and completion activity level during the first nine 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.

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 nine months ended September 30, 2018 and 2017:


			Nine Months Ended
			September 30,
(in millions)			2018		2017

Property acquisition costs:
	Proved		$	4,126	$	301
	Unproved			3,596		865
		Total property acquisition costs (a)	$	7,722	$	1,166


(a)	Included in the property acquisition costs above are budgeted unproved leasehold acreage acquisitions of approximately $31 million and $26 million for the nine months ended September 30, 2018 and 2017, respectively. For the nine months ended September 30, 2018, our unbudgeted acquisitions are primarily comprised of approximately $7.6 billion of property acquisition costs related to the RSP Acquisition. For the nine months ended September 30, 2017, our unbudgeted acquisitions are primarily comprised of approximately $603 million and $452 million of property acquisition costs related to our Midland Basin and Northern Delaware Basin acquisitions, respectively.

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, there have been the following material changes in our contractual obligations:

· $1,471 million increase in long-term debt due to the issuance of the 4.3% Notes and 4.85% Notes, partially offset by a decrease in our Credit Facility balance;

· $1,227 million increase in cash interest expense on debt due to the issuance of the 4.3% Notes and 4.85% Notes;

· $531 million increase in our derivative liability position;

· $243 million increase in purchase obligations mainly due to contracts assumed in the RSP Acquisition, including additional throughput volume delivery commitments, power commitments, daywork drilling contracts and sand commitment agreements; and

· a throughput sales commitment as described below.

Throughput sales commitment. In May 2018, we entered into a one-year term oil marketing contract with a third-party purchaser. The contract requires us to deliver not less than seven thousand barrels per day. Should there be a delivery shortfall in any given month, we retain an option to deliver the shortfall volume in any two subsequent months; however, failure to meet this volume delivery commitment would result in a penalty equal to the volume shortfall multiplied by the then market price for oil. If production is not sufficient to meet the sales commitment, we may purchase commodities in the market to satisfy our commitment.

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 July 2018, our board approved a revised 2018 capital budget of up to $2.7 billion. The revised budget includes capital we plan to invest during the second half of the year on the acquired RSP assets. We expect our 2018 capital spending on drilling and completion activity to range between $2.5 billion and $2.6 billion. Our 2018 capital budget, excluding acquisitions and 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 nine months ended September 30, 2018 and 2017:


		Nine Months Ended
		September 30,
(in millions)		2018		2017

Net cash provided by operating activities		$	1,861	$	1,185
Net cash used in investing activities			(1,422)		(1,207)
Net cash used in financing activities			(415)		(31)
	Net increase (decrease) in cash and cash equivalents	$	24	$	(53)

Cash flow from operating activities. The increase in operating cash flows during the nine months ended September 30, 2018 as compared to the same period in 2017 was primarily due to an increase in oil and natural gas revenues of approximately $1,278 million, partially offset by (i) a decrease in operating cash flow of approximately $364 million due to approximately $238 million for settlements paid on derivatives during the nine months ended September 30, 2018, as compared to approximately $126 million in settlements received from derivatives during the comparable period in 2017, (ii) approximately $123 million increase in production expense and (iii) approximately $89 million increase in production tax expense.

Our net cash provided by operating activities included a benefit of approximately $3 million and a reduction of approximately $59 million for the nine months ended September 30, 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 nine months ended September 30, 2018 and 2017, we invested approximately $1,669 million and $1,092 million, respectively, for additions to oil and natural gas properties. Additionally, we used approximately $105 million and $866 million of cash to fund certain acquisitions of oil and natural gas properties during the nine months ended September 30, 2018 and 2017, respectively. We received approximately $260 million related to proceeds from the disposition of assets during the nine months ended September 30, 2018, as compared to $803 million during the comparable period of 2017. Finally, we received an equity method investment distribution from Oryx of approximately $157 million during the nine months ended September 30, 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 $415 million and $31 million for the nine months ended September 30, 2018 and 2017, respectively. Below is a description of our significant financing activities:

· In July 2018, we issued $1,600 million in aggregate principal amount of the Notes, for which we received net proceeds of approximately $1,579 million. We used the net proceeds to redeem and cancel the RSP Notes. We made aggregate payments of approximately $1.2 billion to redeem and cancel the RSP Notes, including make-whole call premiums of approximately $35 million and $33 million for the RSP 2022 Notes and RSP 2025 Notes, respectively. We also paid accrued interest of approximately $14 million on the RSP Notes. The remaining proceeds, along with borrowings under our Credit Facility, were used to repay the $540 million of outstanding principal under RSP’s revolving credit facility, including $1 million in accrued interest.

· In September 2017, we issued $1,800 million in aggregate principal amount of the 3.75% unsecured senior notes due 2027 and 4.875% unsecured senior notes due 2047, for which we received net proceeds of approximately $1,777 million. We used the net proceeds from the offering, together with cash on hand and borrowings under our Credit Facility, to fund the (i) cash tender offer of $1,232 million principal amount of our 5.5% Notes at a price equal to 102.934 percent of par and (ii) satisfaction and discharge of our remaining obligations of $918 million principal amount under the indentures of the 5.5% Notes at a price equal to 102.75 percent of par. The early extinguishment price included approximately $36 million associated with the premium paid for the tender offer, approximately $25 million for the make-whole premium paid for the early extinguishment of the 5.5% Notes and approximately $2 million for prepaid interest as part of the satisfaction and discharge.

· During the first nine months of 2018, we had net payments on our Credit Facility of $129 million.

· During the first nine months of 2017, we borrowed $368 million on our Credit Facility.

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 (5.25 percent at September 30, 2018),

(b) the federal funds effective rate plus 0.5 percent and

(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. 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 sources of liquidity are cash on hand and available borrowing capacity under our Credit Facility. At September 30, 2018, we had approximately $24 million of cash on hand. At September 30, 2018, our commitments from our bank group were $2.0 billion, of which $1.8 billion was unused commitments.

Debt ratings. We receive debt credit ratings from S&P, Moody’s and Fitch Ratings and are designated as investment grade with all three agencies. In determining our ratings, the agencies perform regular reviews and 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 September 30, 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 September 30, 2018 was $21.3 billion, consisting of debt of $4.1 billion and stockholders’ equity of $17.2 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 19 percent and 23 percent at September 30, 2018 and December 31, 2017, respectively. Our ratio of current assets to current liabilities was 0.55 to 1.0 at September 30, 2018 as compared to 0.51 to 1.0 at December 31, 2017.

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. In addition to these areas, goodwill impairment, uncertain tax positions and litigation and environmental contingencies are also considered critical estimates and are discussed below.

Goodwill impairment. Goodwill is not amortized but assessed for impairment on an annual basis, or more frequently if indicators of impairment exist. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, will be performed as of July 1 of each year. As we operate as a single operating segment and a single reporting unit, we evaluate goodwill for impairment based on an evaluation of the fair value of the company as a whole. The fair value of the reporting unit is our enterprise value (combined market capitalization of our equity plus a control premium and the fair value of our long-term debt). There is considerable judgment involved in estimating fair values, particularly in determining the control premium. To establish a reasonable control premium, we will consider the premiums paid in recent market acquisitions and will analyze current industry, market and economic conditions along with other factors or available information specific to our business. See Note 2 and 4 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding goodwill.

Uncertain tax positions. We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. At September 30, 2018, we had unrecognized tax benefits of approximately $20 million, primarily related to research and development credits. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to our deferred tax liability and will affect our effective tax rate in the period it is recognized. See Note 11 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding uncertain tax positions.

Litigation and environmental contingencies. We make judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if we determine the loss to be both probable and reasonably estimable. See Note 10 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for additional information regarding our commitments and contingencies.

Management’s judgments and estimates in all the areas listed above 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, except those discussed above, in our critical accounting policies and procedures during the nine months ended September 30, 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 U.S. Securities and Exchange Commission (the “SEC”) on February 21, 2018.

New accounting pronouncements issued but not yet adopted. See Note 2 of the Condensed Notes to Consolidated Financial Statements included in “Item 1. Consolidated Financial Statements (Unaudited)” for information regarding new accounting pronouncements issued but not yet adopted.

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 September 30, 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 September 30, 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		$	(405)	$	403
	Natural gas derivatives			(26)		26
		Total	$	(431)	$	429

At September 30, 2018, we had (i) oil price swaps, oil three-way collars and oil costless collars covering future oil production to effectively provide NYMEX price hedges from October 1, 2018 through December 31, 2020 and (ii) oil basis swaps to effectively provide price hedges for our Midland to Cushing basis differential from October 1, 2018 to December 31, 2020. The average NYMEX oil price for the nine months ended September 30, 2018 was $66.83 per Bbl. At October 29, 2018, the NYMEX oil price was $67.04 per Bbl.

At September 30, 2018, we had natural gas price swaps that settle on a monthly basis covering future natural gas production from October 1, 2018 to December 31, 2020. The average NYMEX natural gas price for the nine months ended September 30, 2018 was $2.85 per MMBtu. At October 29, 2018, the NYMEX natural gas price was $3.19 per MMBtu.

A decrease in the average forward NYMEX oil and natural gas prices below those at September 30, 2018 would decrease the fair value liability of our commodity derivative contracts from their recorded balance at September 30, 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 September 30, 2018 would increase the fair value liability of our commodity derivative contracts from their recorded balance at September 30, 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 $793 million for the nine months ended September 30, 2018, compared to a gain of $289 million for the nine months ended September 30, 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 nine months ended September 30, 2018. The following table reconciles the changes that occurred in the fair values of our derivative instruments during the nine months ended September 30, 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)			(793)
	Contract maturities			238
	Fair value of RSP contracts acquired			24
Fair value of contracts outstanding at September 30, 2018			$	(910)


(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 total indebtedness of $193 million outstanding under our Credit Facility at September 30, 2018. The impact of a one percent increase in interest rates on this amount of debt would result in increased annual interest expense of approximately $2 million.

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 September 30, 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.

On July 30, 2018, the owners of certain mineral and surface interests on the Mabee Ranch in Martin and Andrews Counties, Texas filed a lawsuit against us in Martin County District Court. These owners claimed that we breached certain leases by, among other things, exceeding permitted surface uses, failing to obtain required consents and failing to pay certain royalties due to them. We filed our answer to the lawsuit on September 10, 2018; shortly thereafter, we and the plaintiffs entered into settlement negotiations. Effective September 28, 2018, the parties executed a settlement agreement that provides for a dismissal of the lawsuit with prejudice.

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 “Part I, Item 1. Business — Competition,” “— Marketing Arrangements” and “— Applicable Laws and Regulations,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, under the heading “Part II, Item 1A. Risk Factors,” and in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, under the heading “Part II, Item 1A. Risk Factors,” 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, and in our subsequent Quarterly Reports on Form 10-Q, other than the risk factor set forth below. The risks described in our reports filed with the SEC 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 payment of dividends will be at the discretion of our board of directors.

While the Company has announced plans to initiate a regular quarterly dividend in 2019, the payment and amount of future dividend payments, if any, are subject to declaration by our board of directors. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deems relevant. The Company is under no obligation to make dividend payments and may cease such payments at any time in the future.

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

July 1, 2018 - July 31, 2018		214,586	$	149.47	-
August 1, 2018 - August 31, 2018		128	$	135.26	-
September 1, 2018 - September 30, 2018		77	$	143.68	-


(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 No.		Exhibit

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		Sixteenth Supplemental Indenture, dated August 14, 2018, among Concho Resources Inc., the subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on August 15, 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.

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:	October 31, 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)