PIONEER NATURAL RESOURCES CO - Quarter Report: 2018 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________



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

For the quarterly period ended June 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: 1-13245

______________________________

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

______________________________



Delaware		75-2702753
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5205 N. O'Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

______________________________

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 ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ý 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	ý	Accelerated filer	¨

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

Number of shares of Common Stock outstanding as of August 6, 2018 170,401,224

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

TABLE OF CONTENTS



		Page
Cautionary Statement Concerning Forward-Looking Statements		3

Definitions of Certain Terms and Conventions Used Herein		4

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	5

	Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017	7

	Consolidated Statement of Equity for the six months ended June 30, 2018	8

	Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017	9

	Notes to Consolidated Financial Statements	10

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	40

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 4.	Mine Safety Disclosures	41

Item 6.	Exhibits	42

Signatures		43

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PIONEER NATURAL RESOURCES COMPANY

Cautionary Statement Concerning Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (this "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "forecasts," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate" or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company ("Pioneer" or the "Company") are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control.

These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company's drilling and operating activities, access to and availability of transportation, processing, fractionation, refining and export facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer's credit facility, investment instruments and derivative contracts and purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves, identification of drilling locations and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, cybersecurity risks, ability to implement planned stock repurchases, the risks associated with the ownership and operation of the Company's industrial sand mining and oilfield services businesses, and acts of war or terrorism. These and other risks are described in the Company's Annual Report on Form 10-K, this and other Quarterly Reports on Form 10-Q and other filings with the United States Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Part I, Item 1. Business — Competition, Markets 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 the Company's Annual Report on Form 10-K for the year ended December 31, 2017 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

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PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

Within this Report, the following terms and conventions have specific meanings:


•	"Bbl" means a standard barrel containing 42 United States gallons.


•	"BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid.


•	"BOEPD" means BOE per day.


•	"Btu" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.


•	"Conway" means the daily average natural gas liquids components as priced in Oil Price Information Service ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.


•	"DD&A" means depletion, depreciation and amortization.


•	"GAAP" means accounting principles that are generally accepted in the United States of America.


•	"HH" means Henry Hub, a distribution hub on the natural gas pipeline in Louisiana that serves as the delivery location for futures contracts on the NYMEX.


•	"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.


•	"LLS" means Louisiana Light Sweet oil, a light, sweet blend of oil produced from the Gulf of Mexico.


•	"Mcf" means one thousand cubic feet and is a measure of gas volume.


•	"MMBtu" means one million Btus.


•	"Mont Belvieu" means the daily average natural gas liquids components as priced in OPIS in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.


•	"NGL" means natural gas liquid.


•	"NYMEX" means the New York Mercantile Exchange.


•	"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.

•

"Proved reserves" mean the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons ("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.


•	"U.S." means United States.

•

With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by the Company's working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.


•	Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.


•	"WTI" means West Texas Intermediate oil, a light, sweet blend of oil produced from the fields in western Texas.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)



	June 30, 2018			December 31, 2017
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	792		$	896
Short-term investments	391			1,213
Accounts receivable:
Trade, net	853			644
Due from affiliates	—			1
Income taxes receivable	7			7
Inventories	236			212
Assets held for sale	155			—
Derivatives	2			11
Other	23			23
Total current assets	2,459			3,007
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	19,990			20,404
Unproved properties	570			558
Accumulated depletion, depreciation and amortization	(8,070		)	(9,196		)
Total property, plant and equipment	12,490			11,766
Long-term investments	313			66
Goodwill	269			270
Other property and equipment, net	1,805			1,762
Other assets, net	113			132
	$	17,449		$	17,003

The financial information included as of June 30, 2018 has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in millions, except share data)



	June 30, 2018			December 31, 2017
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,432		$	1,174
Due to affiliates	91			108
Interest payable	53			59
Current portion of long-term debt	—			449
Liabilities held for sale	74			—
Derivatives	512			232
Other	100			106
Total current liabilities	2,262			2,128
Long-term debt	2,285			2,283
Derivatives	89			23
Deferred income taxes	947			899
Other liabilities	382			391
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 174,294,691 and 173,796,743 shares issued as of June 30, 2018 and December 31, 2017, respectively	2			2
Additional paid-in capital	9,015			8,974
Treasury stock at cost: 3,893,965 and 3,608,132 shares as of June 30, 2018 and December 31, 2017, respectively	(299		)	(249		)
Retained earnings	2,764			2,547
Total equity attributable to common stockholders	11,482			11,274
Noncontrolling interests in consolidated subsidiaries	2			5
Total equity	11,484			11,279
Commitments and contingencies
	$	17,449		$	17,003

The financial information included as of June 30, 2018 has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Revenues and other income:
Oil and gas	$	1,286		$	768		$	2,552		$	1,577
Sales of purchased oil and gas	1,095			349			2,166			664
Interest and other	9			16			26			30
Derivative gains (losses), net	(358		)	135			(566		)	286
Gain on disposition of assets, net	79			194			83			205
	2,111			1,462			4,261			2,762
Costs and expenses:
Oil and gas production	243			147			456			288
Production and ad valorem taxes	70			51			146			99
Depletion, depreciation and amortization	378			341			735			678
Purchased oil and gas	1,026			363			2,080			697
Impairment of oil and gas properties	77			—			77			285
Exploration and abandonments	28			26			63			59
General and administrative	95			81			185			165
Accretion of discount on asset retirement obligations	4			5			8			10
Interest	32			35			68			81
Other	76			59			133			119
	2,029			1,108			3,951			2,481
Income before income taxes	82			354			310			281
Income tax provision	(19		)	(121		)	(69		)	(90		)
Net income	63			233			241			191
Net loss attributable to noncontrolling interests	3			—			3			—
Net income attributable to common stockholders	$	66		$	233		$	244		$	191

Basic and diluted net income per share attributable to common stockholders	$	0.38		$	1.36		$	1.42		$	1.11

Weighted average shares outstanding:
Basic	170			170			170			170
Diluted	171			170			171			170

Dividends declared per share	$	—		$	—		$	0.16		$	0.04

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(in millions, except share data and dividends per share)

(Unaudited)



			Equity Attributable To Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital		Treasury Stock			Retained Earnings			Noncontrolling Interests			Total Equity
	(in thousands)
Balance as of December 31, 2017	170,189		$	2	$	8,974	$	(249	)	$	2,547		$	5		$	11,279
Dividends declared ($0.16 per share)	—		—		—		—			(27		)	—			(27		)
Exercise of long-term incentive stock options and employee stock purchases	7		—		—		1			—			—			1
Purchases of treasury stock	(293	)	—		—		(51		)	—			—			(51		)
Compensation costs:
Vested compensation awards	498		—		—		—			—			—			—
Compensation costs included in net income	—		—		41		—			—			—			41
Net income	—		—		—		—			244			(3		)	241
Balance as of June 30, 2018	170,401		$	2	$	9,015	$	(299	)	$	2,764		$	2		$	11,484

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(Unaudited)



	Six Months Ended June 30,
	2018			2017
Cash flows from operating activities:
Net income	$	241		$	191
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	735			678
Impairment of oil and gas properties	77			285
Impairment of inventory and other property and equipment	6			1
Exploration expenses, including dry holes	9			18
Deferred income taxes	69			90
Gain on disposition of assets, net	(83		)	(205		)
Accretion of discount on asset retirement obligations	8			10
Interest expense	2			2
Derivative related activity	355			(251		)
Amortization of stock-based compensation	41			43
Other	39			40
Change in operating assets and liabilities:
Accounts receivable	(208		)	27
Income taxes receivable	—			2
Inventories	(35		)	(11		)
Investments	6			1
Other current assets	(7		)	1
Accounts payable	218			(42		)
Interest payable	(5		)	(9		)
Other current liabilities	(12		)	(24		)
Net cash provided by operating activities	1,456			847
Cash flows from investing activities:
Proceeds from disposition of assets	111			345
Proceeds from investments	1,049			878
Purchase of investments	(482		)	(750		)
Additions to oil and gas properties	(1,588		)	(1,074		)
Additions to other assets and other property and equipment, net	(116		)	(176		)
Net cash used in investing activities	(1,026		)	(777		)
Cash flows from financing activities:
Principal payments on long-term debt	(450		)	(485		)
Exercise of long-term incentive plan stock options and employee stock purchases	1			—
Purchases of treasury stock	(51		)	(36		)
Payments of other liabilities	(7		)	—
Dividends paid	(27		)	(7		)
Net cash used in financing activities	(534		)	(528		)
Net decrease in cash and cash equivalents	(104		)	(458		)
Cash and cash equivalents, beginning of period	896			1,118
Cash and cash equivalents, end of period	$	792		$	660

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

NOTE 1. Organization and Nature of Operations

Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company that explores for, develops and produces oil, natural gas liquids ("NGLs") and gas within the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton Basin field in southeast Colorado and the West Panhandle field in the Texas Panhandle.


•	In April 2018, the Company completed the sale of approximately 10,200 net acres in the western portion of the Eagle Ford Shale ("West Eagle Ford Shale") to an unaffiliated third party for cash proceeds of $103 million, before normal closing adjustments.


•	In June 2018, the Company entered into a purchase and sale agreement with an unaffiliated third party to sell all of its assets in the Raton Basin for cash proceeds of $79 million, before normal closing adjustments. The sale closed in July 2018.


•	In July 2018, the Company announced it signed a purchase and sale agreement to sell its assets in the West Panhandle field to an unaffiliated third party for cash proceeds of $201 million, before normal closing adjustments.

See Note 3 for further information regarding the sale of the Company's West Eagle Ford Shale and Raton Basin assets and Note 16 for further information regarding the Company's sale of its West Panhandle field assets.

No assurance can be given that the remaining planned asset divestitures will be completed in accordance with the Company's plan or on terms and at prices acceptable to the Company.

NOTE 2. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2018 and for the three and six months ended June 30, 2018 and 2017 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed in or omitted from this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.

Certain reclassifications have been made to the 2017 financial statement and footnote amounts in order to conform to the 2018 presentation.

Assets held for sale. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale in the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell. See Note 3 for additional information about the Company's divestitures.

Accounting policy changes. During the second quarter of 2018, the Company made a voluntary change in accounting policy to account for its materials and supplies inventory on a weighted average cost basis, versus using the previous accounting policy of the first-in-first-out (“FIFO”) basis. The Company made this voluntary change in accounting policy because it believes this method is preferable, as the weighted average cost basis more closely aligns with the physical flow of material and supplies inventory and is more widely utilized in the oil and gas industry. This voluntary change in accounting policy did not have a material

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

effect on the Company’s consolidated financial statements for prior periods or for the current period. As such, prior periods have not been restated.

Adoption of new accounting standards. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09 ("ASC 606"), "Revenue from Contracts with Customers," which supersedes the revenue recognition requirements in ASC 605, “Revenue Recognition” ("ASC 605"), and requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method. See Note 11 for a discussion of the impact to the Company's recognition of revenue associated with the adoption of ASC 606.

In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. The Company adopted this standard on January 1, 2017. See Note 14 for a discussion of the impact to the Company's income tax provision associated with the adoption of ASU 2016-09.

New accounting pronouncements. In February 2016, the FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company anticipates that the adoption of ASU 2016-02 for its leasing arrangements will likely (i) increase the Company's recorded assets and liabilities, (ii) increase depreciation, depletion and amortization expense, (iii) increase interest expense and (iv) decrease lease/rental expense. The Company is currently evaluating each of its lease arrangements and has not determined the aggregate amount of change expected for each category.

NOTE 3. Divestitures

In April 2018, the Company completed the sale of approximately 10,200 net acres in the West Eagle Ford Shale to an unaffiliated third party for cash proceeds of $103 million, before normal closing adjustments. During the second quarter of 2018, the Company recognized a gain of $78 million associated with this divestiture.

In June 2018, the Company entered into a purchase and sale agreement with an unaffiliated third party to sell all of its assets in the Raton Basin for cash proceeds of $79 million, before normal closing adjustments. Associated with the sale, the Company recorded a noncash impairment charge of $77 million in June 2018 to reduce the carrying value of its Raton Basin assets to their estimated fair value less costs to sell. See Note 4 for additional information about the Raton Basin impairment charge. The Company classified its Raton Basin assets and liabilities as held for sale in the accompanying consolidated balance sheet as of June 30, 2018. The sale closed in July 2018.

In July 2018, the Company signed a purchase and sale agreement to sell its assets in the West Panhandle field to an unaffiliated third party for cash proceeds of $201 million, before normal closing adjustments. See Note 16 for further information regarding the Company's sale of its West Panhandle field assets.

The held for sale assets and liabilities in the accompanying consolidated balance sheet as of June 30, 2018 relate primarily to the Raton Basin assets. The Company had no assets held for sale as of December 31, 2017.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)



	June 30, 2018
	(in millions)
Composition of assets included in assets held for sale:
Inventories	$	4
Other current assets	1
Oil and gas properties, net	122
Other property and equipment, net	27
Goodwill	1
Total assets	$	155

Composition of liabilities included in liabilities held for sale:
Other current liabilities	3
Other noncurrent liabilities	71
Total liabilities	$	74

No assurance can be given that the remaining planned asset divestitures during 2018 will be completed in accordance with the Company's plan or on terms and at prices acceptable to the Company.

In April 2017, the Company completed the sale of approximately 20,500 acres in the Martin County region of the Permian Basin, with net production of approximately 1,500 BOEPD, to an unaffiliated third party for cash proceeds of $264 million. The sale resulted in a gain of $194 million. In conjunction with this divestiture, the Company reduced the carrying value of goodwill by $2 million, reflecting the portion of the Company's goodwill related to the assets sold.

During the six months ended June 30, 2017, the Company completed the sales of nonstrategic proved and unproved properties in the Permian Basin for cash proceeds of $72 million, which resulted in a gain of $10 million.

NOTE 4. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. 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. The three input levels of the fair value hierarchy are as follows:


•	Level 1 – quoted prices for identical assets or liabilities in active markets.


•	Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.


•	Level 3 – unobservable inputs for the asset or liability.

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2018 and December 31, 2017 for each of the fair value hierarchy levels:



	Fair Value Measurement as of June 30, 2018 Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value as of June 30, 2018
	(in millions)
Assets:
Commodity derivatives	$	—	$	2		$	—	$	2
Deferred compensation plan assets	94		—			—		94
Total assets	94		2			—		96
Liabilities:
Commodity derivatives	—		601			—		601
Total liabilities	—		601			—		601
Total recurring fair value measurements	$	94	$	(599	)	$	—	$	(505	)



	Fair Value Measurement as of December 31, 2017 Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair value as of December 31, 2017
	(in millions)
Assets:
Commodity derivatives	$	—	$	11		$	—	$	11
Deferred compensation plan assets	95		—			—		95
Total assets	95		11			—		106
Liabilities:
Commodity derivatives	—		255			—		255
Total liabilities	—		255			—		255
Total recurring fair value measurements	$	95	$	(244	)	$	—	$	(149	)

Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represent Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.

The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts and collar contracts with short puts, which is based on active and independent market-quoted volatility factors.

Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of June 30, 2018 and December 31, 2017, the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs.

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.

Proved oil and gas properties. As a result of the Company's proved property impairment assessments, the Company recognized a noncash impairment charge of $285 million to reduce the carrying value of the Raton Basin field during the three months ended March 31, 2017 to its estimated fair value of $186 million.

The Company calculated the fair value of the Raton Basin field as of March 31, 2017 using a discounted future cash flow model. Significant Level 3 assumptions associated with the calculation of the Raton Basin field's discounted future cash flows as of March 31, 2017 included management's longer-term commodity price outlook ("Management's Price Outlook") for oil of $53.65 per barrel ("Bbl") and gas of $3.00 per million British Thermal units ("MMBtu") and management's outlook for (i) production, (ii) capital expenditures, (iii) production costs and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value.

It is reasonably possible that the Company's estimate of undiscounted future net cash flows attributable to other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future adjustments, both positive and negative, to proved and risk-adjusted probable and possible oil and gas reserves, (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these reserves.

Assets held for sale. During the three and six months ended June 30, 2018, the Company recognized an impairment charge of $77 million to reduce the carrying value of its Raton Basin field assets to the agreed upon sales price for these assets. See Note 3 for additional information about the Company's sale of its Raton Basin field assets.

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of June 30, 2018 and December 31, 2017 are as follows:



	June 30, 2018				December 31, 2017
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Commercial paper, corporate bonds and time deposits	$	704	$	702	$	1,279	$	1,277
Current portion of long-term debt	$	—	$	—	$	449	$	457
Long-term debt	$	2,285	$	2,397	$	2,283	$	2,479

Commercial paper, corporate bonds and time deposits. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. The investments are carried at amortized cost and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The carrying values of held-to-maturity investments are adjusted for amortization of premiums and accretion of discounts over the remaining life of the investment. Income related to these investments is recorded in interest and other income in the Company's consolidated statements of operations. The Company's investments in corporate bonds represent Level 1 inputs in the hierarchy, while other investments represent Level 2 inputs in the hierarchy. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, such investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

The following tables provide the components of the Company's cash and cash equivalents and investments as of June 30, 2018 and December 31, 2017:



	June 30, 2018
Consolidated Balance Sheet Location	Cash		Commercial Paper		Corporate Bonds		Time Deposits		Total
	(in millions)
Cash and cash equivalents	$	707	$	35	$	—	$	50	$	792
Short-term investments	—		101		239		51		391
Long-term investments	—		—		313		—		313
	$	707	$	136	$	552	$	101	$	1,496



	December 31, 2017
Consolidated Balance Sheet Location	Cash		Commercial Paper		Corporate Bonds		Time Deposits		Total
	(in millions)
Cash and cash equivalents	$	846	$	—	$	—	$	50	$	896
Short-term investments	—		124		642		447		1,213
Long-term investments	—		—		66		—		66
	$	846	$	124	$	708	$	497	$	2,175

Debt obligations. The Company's debt obligations are composed of its senior notes whose fair value is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy. The Company's senior notes represent debt securities that are quoted but not actively traded on major exchanges; therefore, fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.

The Company has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.

NOTE 5. Derivative Financial Instruments

The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness.

Periodically, the Company may pay a premium to enter into commodity contracts. Premiums paid, if any, have been nominal in relation to the value of the underlying asset in the contract. The Company recognizes the nominal premium payments as an increase to the value of derivative assets when paid. All derivatives are adjusted to fair value as of each balance sheet date.

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and the actual index prices at which the oil is sold.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of June 30, 2018 and the weighted average oil prices for those contracts:



	2018				Year Ending December 31, 2019
	Third Quarter		Fourth Quarter		Year Ending December 31, 2019
Collar contracts:
Volume (Bbl)	3,000		3,000		—
Price per Bbl:
Ceiling	$	58.05	$	58.05	$	—
Floor	$	45.00	$	45.00	$	—
Collar contracts with short puts:
Volume (Bbl)	154,000		159,000		65,000
Price per Bbl:
Ceiling	$	57.70	$	57.62	$	60.74
Floor	$	47.34	$	47.26	$	52.69
Short put	$	37.31	$	37.23	$	42.69

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu, Texas or Conway, Kansas NGL component product prices. The Company uses derivative contracts to manage NGL component price volatility.

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of June 30, 2018 and the weighted average NGL prices for those contracts:



	2018				Year Ending December 31, 2019
	Third Quarter		Fourth Quarter		Year Ending December 31, 2019
Ethane basis swap contracts (a):
Volume (MMBtu)	6,920		6,920		6,920
Price differential ($/MMBtu)	$	1.60	$	1.60	$	1.60

____________________


(a)	The ethane basis swap contracts reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The ethane basis swap contracts fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane.

Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to HH gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of June 30, 2018 and the weighted average gas prices for those contracts:



	2018						Year Ending December 31, 2019
	Third Quarter			Fourth Quarter			Year Ending December 31, 2019
Swap contracts:
Volume (MMBtu)	100,000			100,000			—
Price per MMBtu	$	3.00		$	3.00		$	—
Collar contracts with short puts:
Volume (MMBtu)	50,000			50,000			—
Price per MMBtu:
Ceiling	$	3.40		$	3.40		$	—
Floor	$	2.75		$	2.75		$	—
Short put	$	2.25		$	2.25		$	—
Basis swap contracts:
Permian Basin index swap volume (MMBtu) (a)	60,000			60,000			44,877
Price differential ($/MMBtu)	$	(1.46	)	$	(1.46	)	$	(1.46	)
Southern California index swap volume (MMBtu) (b)	80,000			66,522			84,932
Price differential ($/MMBtu)	$	0.30		$	0.50		$	0.33

____________________


(a)	The referenced basis swap contracts fix the basis differentials between the index price at which the Company sells its Permian Basin gas and the HH price used in swap contracts and collar contracts with short puts.


(b)	The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in Arizona and southern California.

Marketing derivatives. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. As of June 30, 2018, the Company was party to July and August 2018 oil basis swap contracts for 3,000 Bbls per day of Permian Basin oil forecasted for sale to a Gulf Coast refinery with a price differential of $3.30 per Bbl between NYMEX WTI and Magellan East Houston oil prices.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of June 30, 2018 and December 31, 2017, and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:



Fair Value of Derivative Instruments as of June 30, 2018
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in millions)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	9	$	(7	)	$	2
Commodity price derivatives	Derivatives - noncurrent	$	2	$	(2	)	—
							$	2
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	519	$	(7	)	$	512
Commodity price derivatives	Derivatives - noncurrent	$	91	$	(2	)	89
							$	601



Fair Value of Derivative Instruments as of December 31, 2017
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in millions)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	13	$	(2	)	$	11
Commodity price derivatives	Derivatives - noncurrent	$	3	$	(3	)	—
							$	11
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	234	$	(2	)	$	232
Commodity price derivatives	Derivatives - noncurrent	$	26	$	(3	)	23
							$	255

The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations:



Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) Recognized in Earnings on Derivatives	Three Months Ended June 30,						Six Months Ended June 30,
Derivatives Not Designated as Hedging Instruments		2018			2017			2018			2017
		(in millions)
Commodity price derivatives	Derivative gains (losses), net	$	(358	)	$	136		$	(566	)	$	287
Interest rate derivatives	Derivative gains (losses), net	—			(1		)	—			(1		)
Total		$	(358	)	$	135		$	(566	)	$	286

Derivative Counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

NOTE 6. Exploratory Costs

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The following table reflects the Company's capitalized exploratory well and project activity during the three and six months ended June 30, 2018:



	Three Months Ended June 30, 2018			Six Months Ended June 30, 2018
	(in millions)
Beginning capitalized exploratory well costs	$	476		$	505
Additions to exploratory well costs pending the determination of proved reserves	631			1,213
Reclassification due to determination of proved reserves	(528		)	(1,135		)
Exploratory well costs charged to exploration and abandonment expense	(4		)	(8		)
Ending capitalized exploratory well costs	$	575		$	575

The following table provides an aging as of June 30, 2018 and December 31, 2017 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:



	June 30, 2018		December 31, 2017
	(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	563	$	493
More than one year	12		12
	$	575	$	505
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year	7		7

All projects with exploratory well costs that have been suspended for a period greater than one year as of June 30, 2018 are in the Eagle Ford Shale area. The Company is evaluating both the well performance of similar wells completed in 2017 and whether to drill additional wells near these wells in order for all of the wells in the area to be fracture stimulated as a package, thereby improving the resource recovery for the area. The Company expects to complete its evaluation of these wells during 2018.

NOTE 7. Long-term Debt

Credit facility. The Company's long-term debt consists of senior notes, a revolving corporate credit facility (the "Credit Facility") and the effects of issuance costs and discounts. The Credit Facility is maintained with a syndicate of financial institutions and has aggregate loan commitments of $1.5 billion that expire in August 2020. As of June 30, 2018, the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants.

Senior notes. The Company's 6.875% senior notes (the "6.875% Senior Notes") and 6.65% senior notes (the "6.65% Senior Notes"), with debt principal balances of $450 million and $485 million, respectively, matured and were repaid in May 2018 and March 2017, respectively. The Company funded the repayments with cash on hand. The 6.875% Senior Notes were classified as current in the accompanying consolidated balance sheet at December 31, 2017.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

NOTE 8. Incentive Plans

Stock-based compensation. For the three and six months ended June 30, 2018, the Company recorded $29 million and $52 million, respectively, of stock-based compensation expense for all plans, as compared to $27 million and $57 million for the same respective periods in 2017. As of June 30, 2018, there was $142 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $32 million attributable to stock-based awards that are expected to be settled on their vesting date in cash, rather than in equity shares ("Liability Awards"). The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of June 30, 2018 and December 31, 2017, accounts payable – due to affiliates included $10 million and $20 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the six months ended June 30, 2018 for restricted stock awards and performance units issued by the Company:



	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units
Outstanding as of December 31, 2017	916,223		252,735		163,158
Awards granted	384,559		108,129		62,541
Awards forfeited	(28,875	)	(8,274	)	(1,285	)
Awards vested	(405,391	)	(122,112	)	(34,778	)
Outstanding as of June 30, 2018	866,516		230,478		189,636

As of June 30, 2018 and December 31, 2017, the Company also had 131,630 and 138,493 stock options outstanding and exercisable. There were 6,863 stock options exercised during the six months ended June 30, 2018.

NOTE 9. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The following table summarizes the Company's asset retirement obligation activity during the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)
Beginning asset retirement obligations	$	263		$	297		$	271		$	297
New wells placed on production	1			1			1			1
Changes in estimates	—			7			2			7
Obligations reclassified to liabilities held for sale	(67		)	—			(73		)	—
Dispositions	(6		)	(7		)	(6		)	(7		)
Liabilities settled	(10		)	(9		)	(18		)	(14		)
Accretion of discount	4			5			8			10
Ending asset retirement obligations	$	185		$	294		$	185		$	294

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of June 30, 2018 and December 31, 2017, the current portion of the Company's asset retirement obligations was $29 million and $41 million, respectively.

NOTE 10. Commitments and Contingencies

Legal actions. The Company is a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's financial position as a whole or on its

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company does not believe these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

Lease agreements. In June 2017, the Company entered into a 20-year operating lease for the Company's new corporate headquarters that is currently being constructed in Irving, Texas. Annual base rent is expected to be $33 million and lease payments are expected to commence once the building is complete, which is anticipated to occur during the second half of 2019. The Company has a variable equity interest in the entity that is constructing the building. The Company is not the primary beneficiary of the variable interest entity and only has a profit sharing interest after certain economic returns are achieved. The Company has no exposure to the variable interest entity's losses or future liabilities, if any. The Company is the deemed owner of the building (for accounting purposes) during the construction period and is following the build-to-suit accounting guidance. Accordingly, as of June 30, 2018, the Company has capitalized $119 million of construction costs, including capitalized interest, within other property and equipment and has recognized a corresponding build-to-suit lease liability. The recording of these assets and liabilities are considered noncash investing and financing items, respectively, for purposes of the consolidated statements of cash flows.

Firm purchase, gathering, processing, transportation, and fractionation commitments. The Company from time to time enters into, and as of June 30, 2018 was a party to, take-or-pay agreements, which include contractual commitments to purchase sand and water for use in the Company's drilling operations and contractual commitments with midstream service companies and pipeline carriers for future gathering, processing, transportation, storage and fractionation. These commitments are normal and customary for the Company's business activities.

NOTE 11. Revenue Recognition

Impact of ASC 606 adoption. On January 1, 2018, the Company adopted ASC 606 by applying the modified retrospective method to all revenue contracts as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with historic accounting under ASC 605. The Company completed a detailed review of its revenue contracts, which represent all of the Company's revenue streams including oil, NGL and gas sales and sales of purchased oil and gas, to determine the effect of the new standard for the three and six months ended June 30, 2018. The Company did not record a change to its opening retained earnings as of January 1, 2018 as there was no material change to the timing or pattern of revenue recognition due to the adoption of ASC 606.

The adoption of ASC 606 as of January 1, 2018 had the following impact on the Company's results of operations for the three and six months ended June 30, 2018:



	Three Months Ended June 30, 2018						Six Months Ended June 30, 2018
	As Reported		ASC 605 (Without Adoption of ASC 606)		Effect of Change Higher (Lower)		As Reported		ASC 605 (Without Adoption of ASC 606)		Effect of Change Higher (Lower)
	(in millions)						(in millions)
Revenues and other income:
Oil and gas	$	1,286	$	1,232	$	54	$	2,552	$	2,455	$	97
Costs and expenses:
Oil and gas production	$	243	$	189	$	54	$	456	$	359	$	97

Changes in oil and gas revenues and oil and gas production costs (specifically gathering, processing and transportation costs) are due to the conclusion under the control model in ASC 606 that the third-party processor or transporter is only providing gas processing or transportation services and that the Company remains the principal owner of the commodity until sold to the ultimate purchaser. This is a change from ASC 605 where the Company historically recorded gas processing fees as a reduction of revenue recognized by the Company, as these fees were considered necessary to separate the wet gas stream into its sellable

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

components (i.e., dry gas and individual NGL components). Under ASC 605, third-party processing and transportation companies were determined to have control of the commodities being processed and transported. As a result of adopting ASC 606, the Company has modified its presentation of revenues and expenses for these arrangements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party purchasers through the marketing process. Gathering, processing and transportation expenses related to these agreements, incurred prior to the transfer of control to the purchaser, are now presented as oil and gas production costs.

Disaggregated revenue from contracts with purchasers. Revenues on sales of oil, NGLs, gas and purchased oil and gas are recognized when control of the product is transferred to the purchaser and payment can be reasonably assured. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, distance from the well to the pipeline or market, commodity quality and prevailing supply and demand conditions. As such, the prices of oil, NGLs and gas generally fluctuate based on the relevant market index rates. The following table provides information about disaggregated revenue from contracts with purchasers by product type:



	Three Months Ended June 30, 2018		Six Months Ended June 30, 2018
	(in millions)
Oil sales	$	1,033	$	2,046
NGL sales	169		334
Gas sales	84		172
Total oil and gas sales	1,286		2,552
Sales of purchased oil and gas	1,095		2,166
Total revenue derived from contracts with purchasers	$	2,381	$	4,718

Oil sales. Sales under the Company's oil contracts are generally considered performed when the Company sells oil production at the wellhead and receives an agreed-upon index price, net of any price differentials. The Company recognizes revenue when control transfers to the purchaser at the wellhead based on the net price received.

NGL and gas sales. The Company evaluated whether it was the principal or the agent in natural gas processing transactions and concluded that it is the principal when it has the ability to take-in-kind, which is the case in the majority of the Company's gas processing and transportation contracts. Therefore, beginning January 1, 2018, the Company began recognizing revenue on a gross basis, with the gathering, processing and transportation costs associated with its take-in-kind arrangements being recognized as oil and gas production costs in the Company's accompanying consolidated statement of operations. Gas and NGL processing fees previously reflected as a reduction in the Company's reported gas and NGL revenue are now recognized as an expense in the Company's production costs.

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to the Gulf Coast refinery or international export markets and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The transportation costs associated with these transactions are presented as a component of purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations.

Performance obligations and contract balances. The majority of the Company's product sale commitments are short-term in nature with a contract term of one year or less. The Company typically satisfies its performance obligations upon transfer of control as described above in Disaggregated revenue from contracts with purchasers and records the related revenue in the month production is delivered to the purchaser. Settlement statements for sales of oil, NGLs and gas and sales of purchased oil and gas may not be received for 30 to 60 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The implementation of ASC 606 has not changed existing controls around revenue estimates and the accrual process. Historically, differences between the Company's revenue estimates and actual revenue received have not been significant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

As of June 30, 2018 and December 31, 2017, the accounts receivable balance representing amounts due or billable under the terms of contracts with purchasers was $799 million and $594 million, respectively.

NOTE 12. Interest and Other Income

The following table provides the components of the Company's interest and other income for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)
Interest income	$	7	$	10	$	14	$	16
Seismic data sales	1		—		5		—
Deferred compensation plan income	—		1		3		3
Severance and sales tax refunds	—		5		2		8
Other income	1		—		2		3
Total interest and other income	$	9	$	16	$	26	$	30

NOTE 13. Other Expense

The following table provides the components of the Company's other expense for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)
Transportation commitment charges (a)	$	44	$	43	$	78	$	82
Legal and environmental contingencies	7		—		10		7
Loss from vertical integration services (b)	3		5		9		11
Asset divestiture related charges	9		—		9		—
Other	13		11		27		19
Total other expense	$	76	$	59	$	133	$	119

____________________


(a)	Primarily represents firm transportation payments on excess pipeline capacity commitments.

(b)

Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three and six months ended June 30, 2018, these vertical integration net margins included $30 million and $65 million, respectively, of revenues and $33 million and $74 million, respectively, of costs and expenses. For the same respective periods in 2017, these vertical integration net margins included $23 million and $42 million of revenues and $28 million and $53 million of costs and expenses.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2018

(Unaudited)

NOTE 14. Income Taxes

The Company's income tax provision consisted of the following for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018	2017
	(in millions)
Deferred tax provision	$	19	$	121	69	90

For the three and six months ended June 30, 2018, the Company's effective tax rate, excluding income attributable to noncontrolling interests, was 23 percent and 22 percent, respectively, as compared to an effective rate of 34 percent and 32 percent for the same respective periods in 2017. The U.S. statutory rate for the three and six months ended June 30, 2018 was 21 percent, reflecting the reduction in the federal corporate income tax rate from 35 percent to 21 percent beginning in 2018 as a result of the Tax Cuts and Jobs Act that was enacted in December 2017. The Company's effective tax rate for the six months ended June 30, 2017 differs from the U.S. statutory rate in effect during 2017 of 35 percent primarily due to recognizing excess tax benefits of $8 million associated with the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which requires excess tax benefits or deficiencies associated with the vesting of long-term incentive awards to be recorded as income tax expense or benefit in the statement of operations rather than as an adjustment to additional paid-in capital in the balance sheet.

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 of June 30, 2018 and December 31, 2017, the Company had cumulative unrecognized tax benefits of $129 million and $124 million, respectively, resulting from research and experimental expenditures related to horizontal drilling and completions innovations. 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 it is recognized. The timing as to when the Company will substantially resolve the uncertainties associated with the unrecognized tax benefit is uncertain.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2012 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2012. As of June 30, 2018, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

NOTE 15. Net Income Per Share

The following table reconciles the Company's net income attributable to common stockholders to basic and diluted net income attributable to common stockholders for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,					Six Months Ended June 30,
	2018		2017			2018			2017
	(in millions)
Net income attributable to common stockholders	$	66	$	233		$	244		$	191
Participating share-based earnings	—		(2		)	(2		)	(2		)
Basic and diluted net income attributable to common stockholders	$	66	$	231		$	242		$	189

The following table is a reconciliation of basic weighted average shares outstanding to diluted weighted average shares outstanding for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
	(in millions)
Basic weighted average shares outstanding	170	170	170	170
Dilution attributable to stock-based compensation awards	1	—	1	—
Diluted weighted average shares outstanding	171	170	171	170

Stock repurchase program. In February 2018, the Company's board of directors (the "Board") approved a $100 million common stock repurchase program to offset the impact of dilution associated with annual employee stock awards, of which $78 million remained available for use to purchase shares as of June 30, 2018. During the three and six months ended June 30, 2018, the Company purchased $5 million and $22 million, respectively, of common stock pursuant to the program.

NOTE 16. Subsequent Events

In July 2018, the Company entered in a purchase and sale agreement with an unaffiliated third party to sell its assets in the West Panhandle field in Texas for cash proceeds of $201 million, before normal closing adjustments. The assets being sold represent all of the Company's interests in the field, including all of its producing wells and the associated infrastructure. The sale of the Company's West Panhandle assets is expected to result in a pretax gain of $155 million to $170 million. The transaction is expected to close during the third quarter, subject to the satisfaction of customary closing conditions and receipt of specified regulatory approvals.

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

Financial and Operating Performance

The Company's financial and operating performance for the three months ended June 30, 2018 included the following highlights:


•	Net income attributable to common stockholders for the three months ended June 30, 2018 was $66 million ($0.38 per diluted share), as compared to net income of $233 million ($1.36 per diluted share) for the same period in 2017. The primary components of the decrease in net income attributable to common stockholders include:


•	a $493 million increase in net derivative losses, primarily as a result of changes in forward commodity prices and the Company's portfolio of derivatives;

•

a $115 million decrease in gain on disposition of assets, net, primarily due to recognizing a gain of $194 million on the sale of approximately 20,500 acres in the Martin County region of the Permian Basin during the second quarter of 2017 versus recognizing a gain of $78 million on the sale of approximately 10,200 net acres in western portion of the Eagle Ford Shale ("West Eagle Ford Shale") in April 2018;


•	a $115 million increase in total oil and gas production costs and production and ad valorem taxes, primarily due to a 26 percent increase in sales volumes and a 32 percent increase in average realized commodity prices per BOE (inclusive of the effect of the adoption of ASC 606 as described below in Adoption of New Accounting Standards);


•	a $77 million increase in impairment charges as a result of the impairment recorded in 2018 to reduce the carrying value of the Company's Raton Basin field;


•	a $37 million increase in DD&A expense, primarily due the aforementioned increase in sales volumes;


•	a $17 million increase in other expense, primarily due to increases in legal and environmental contingencies and asset divestiture related charges;


•	a $14 million increase in general and administrative expense, primarily due to an increase in compensation costs, including benefits expense, as a result of an increase in headcount due to the Company's continued growth; and


•	a $7 million decrease in interest and other income, primarily due to a decrease in interest income as a result of a decrease in short-term investments; partially offset by


•	a $518 million increase in oil and gas revenues as a result of the aforementioned increase in sales volumes and average realized commodity prices per BOE;


•	an $83 million increase in net sales of purchased oil and gas, primarily due to favorable downstream oil margins on the Company's Gulf Coast refinery and export sales; and


•	a $102 million decrease in the Company's income tax provision as a result of the lower net income during the three months ended June 30, 2018, as compared to the same period in 2017.


•	During the three months ended June 30, 2018, average daily sales volumes increased by 26 percent to 327,704 BOEPD, as compared to 259,087 BOEPD during the same period in 2017. The increase in average daily sales volumes for the three months ended June 30, 2018, as compared to the same period in 2017, is primarily due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.

•

Average oil and NGL prices increased during the three months ended June 30, 2018 to $61.20 per Bbl and $28.83 per Bbl, respectively, as compared to $45.00 per Bbl and $16.91 per Bbl, respectively, for the same period in 2017. Average gas prices decreased during the three months ended June 30, 2018 to $1.97 per Mcf, as compared to $2.62 per Mcf for the same period in 2017. Pricing is inclusive of the effect of the adoption of ASC 606 as described below in Adoption of New Accounting Standards.

•

Net cash provided by operating activities increased to $902 million for the three months ended June 30, 2018, as compared to $483 million for the same period in 2017. The $419 million increase in net cash provided by operating activities for the three months ended June 30, 2018, as compared to the same period in 2017, is primarily due to increases in the Company's oil and gas revenues as a result of increases in commodity prices and sales volumes, partially offset by increases in oil and gas production costs, production and ad valorem taxes and cash derivative payments.


•	As of June 30, 2018, the Company's net debt to book capitalization was six percent, as compared to five percent at December 31, 2017.

PIONEER NATURAL RESOURCES COMPANY

Adoption of New Accounting Standard

On January 1, 2018, the Company adopted Financial Accounting Standards Board ("FASB") Accounting Standards Update ("ASU") No. 2014-09 (ASC 606) "Revenue from Contracts with Customers." ASC 606 requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. As a result of adopting ASC 606, the Company has modified its presentation of revenues and expenses for certain processing and transportation contracts that were previously netted in oil and gas revenues. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts are not adjusted and continue to be reported in accordance with historical accounting under ASC 605.

Changes in oil and gas revenues, gas production volumes and oil and gas production costs (specifically gathering, processing and transportation costs) are due to the conclusion under the control model in ASC 606 that the third-party processor or transporter is only providing gas processing or transportation services and the Company remains the principal owner of the commodity until sold to the ultimate purchaser. This is a change from ASC 605 where the Company historically recorded gas processing fees, including gas volumes that were used to satisfy certain costs, as a reduction of revenue and gas production volumes recognized by the Company, as these fees and volumes were considered necessary to separate the wet gas stream into its sellable components (i.e. dry gas and individual NGL components). Under ASC 605, third-party processing and transportation companies were determined to have control of the commodities being processed and transported. As a result, the Company has modified its presentation of revenues, production and expenses for these arrangements. Sales to third-party purchasers are now presented on a gross basis and gathering, processing, transportation and other expenses related to these agreements, incurred prior to the transfer of control to the purchaser, are now presented as oil and gas production costs.

The adoption of ASC 606 as of January 1, 2018 had the following impact on the Company's results of operations for the three months ended June 30, 2018:



	As Reported		ASC 605 (Without Adoption of ASC 606)		Effect of Change
	(in millions)
Oil and Gas Sales:
Oil sales	$	1,033	$	1,033	$	—
NGL sales	169		131		38
Gas sales	84		68		16
Oil and gas sales	$	1,286	$	1,232	$	54

Production Costs	$	243	$	189	$	54

See Notes 2 and 11 of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for additional information regarding the Company's adoption of ASC 606.

Third Quarter 2018 Outlook

In February 2018, the Company announced its intention to divest its properties in the South Texas, Raton and West Panhandle fields and focus its efforts and capital resources on its Permian Basin assets. The Raton divestiture closed in July 2018 and the West Panhandle divestiture is expected to close during the third quarter of 2018. As a result, these divestitures will be included in the Company's reported third quarter results for a portion of the quarter. The remaining South Texas divestitures are expected to occur during the second half of 2018.

Based on the Company's ongoing divestiture process, it is only providing Permian Basin specific estimates for production, production costs and DD&A expense for the quarter ending September 30, 2018. All other operating and financial results for the quarter ended September 30, 2018 provided below reflect the expected results of the total Company.

Permian Basin production is forecasted to average between 278 MBOEPD to 288 MBOEPD. Permian Basin production costs (including production and ad valorem taxes and transportation costs) are expected to average $9.50 to $11.50 per BOE, reflecting current NYMEX strip commodity prices and the adoption of ASC 606 (see Adoption of New Accounting Standards above and Notes 2 and 11 of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for additional information

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regarding the adoption of ASC 606). Permian Basin DD&A expense, including the Company's other property and equipment, is expected to average $12.50 to $14.50 per BOE.

Total exploration and abandonment expense is expected to be $20 million to $30 million. General and administrative expense is expected to be $95 million to $100 million. Interest expense is expected to be $30 million to $35 million, and other expense is expected to be $60 million to $70 million, including $45 million to $50 million of charges associated with excess firm gathering and transportation commitments. Accretion of discount on asset retirement obligations is expected to be $4 million to $7 million.

The Company's effective income tax rate is expected to range from 21 percent to 25 percent. Current income taxes are expected to be less than $5 million.

Operations and Drilling Highlights

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during the six months ended June 30, 2018:



	Oil (Bbls)	NGLs (Bbls)	Gas (Mcf)	Total (BOE)
Permian Basin	172,459	53,614	265,051	270,248
South Texas - Eagle Ford Shale (a)	7,754	7,315	43,371	22,297
Raton Basin (b)	1	—	82,661	13,778
West Panhandle	1,567	3,829	13,763	7,690
South Texas - Other (a)	2,225	565	18,025	5,794
Other	9	1	9	12
Total	184,015	65,324	422,880	319,819

____________________

(a)

Includes average daily oil, NGL and gas volumes from January through April 2018 of 510 Bbls of oil, 154 Bbls of NGLs and 1,530 Mcf of gas (total of 920 BOEPD) associated with the acreage and assets in the western portion of the Eagle Ford Shale that were sold in April 2018. See Note 3 of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the sale of these assets and liabilities.


(b)	The Company has classified the Raton Basin assets and liabilities as held for sale in the accompanying consolidated balance sheet as of June 30, 2018. See Note 3 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's sale of its Raton Basin assets.

The Company's liquids production increased to 78 percent of total production on a BOE basis for the six months ended June 30, 2018, as compared to 77 percent for the same period last year.

The following table summarizes by geographic area the Company's finding and development costs incurred during the six months ended June 30, 2018:



	Acquisition Costs				Exploration Costs		Development Costs		Asset Retirement Obligations		Total
	Proved		Unproved		Exploration Costs		Development Costs		Asset Retirement Obligations		Total
	(in millions)
Permian Basin	$	2	$	18	$	1,256	$	414	$	1	$	1,691
South Texas - Eagle Ford Shale	—		—		—		13		—		13
Raton Basin	—		—		—		1		—		1
West Panhandle	—		—		2		1		—		3
Other	—		—		1		—		—		1
Total	$	2	$	18	$	1,259	$	429	$	1	$	1,709

The following table summarizes the Company's development and exploration/extension drilling activities for the six months ended June 30, 2018:



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	14	14	14	1	13



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	125	139	118	1	145
South Texas - Eagle Ford Shale	8	—	1	—	7
West Panhandle	3	—	—	2	1
Total	136	139	119	3	153

Permian Basin area. The Company is currently operating 20 rigs in the Spraberry/Wolfcamp field and expects to place on production in 2018 between 250 and 275 horizontal wells (200 to 225 horizontal wells in the northern portion of the play and

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approximately 50 horizontal wells in the southern portion of the play). Approximately 60 percent of the horizontal wells are planned to be drilled in the Wolfcamp B interval, 25 percent in the Wolfcamp A interval and the remaining 15 percent will be a combination of wells in the Spraberry Shale intervals (Jo Mill, Lower Spraberry and Middle Spraberry) and a limited appraisal program for the Clearfork and Wolfcamp D intervals. The Company's 2018 appraisal program includes appraising: (i) its first Clearfork horizontal well (located in Midland County), (ii) seven wells in the Jo Mill and Middle Spraberry intervals in conjunction with nine Lower Spraberry Shale wells to determine an optimal development strategy for the Spraberry formation (testing different spacing, staggering, sequencing, and completion design) and (iii) three Wolfcamp D interval wells. The Company placed on production 45 higher intensity completions during the first half of 2018. Based on strong well results from the higher intensity completion wells placed on production in 2017 and 2018, the Company expects to add 60 more higher intensity completions to its capital program during the second half of 2018. Additionally, the Company plans to add two additional rigs in August and two during the fourth quarter of 2018 in support of the 2019 plan.

During the first half of 2018, oil prices have steadily increased, which has led to higher industry activity levels in the Permian Basin. As a result, the Company has experienced cost inflation in labor, fuel, mud, chemicals, wireline and steel costs. Furthermore, the industry activity levels in the Permian Basin are also leading to a tight labor market for the Company's service providers, resulting in less experienced personnel performing services for the Company.

As a result of the (i) additional higher intensity completions being added to the second half of 2018, (ii) drilling rig additions in the second half of 2018 to support its 2019 plan and (iii) inflationary pressures associated with the current commodity price environment, the Company has increased its 2018 capital budget from $2.9 billion to $3.3 billion to $3.4 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical general and administrative costs and information technology system upgrades). The Company expects to fund the capital budget increase from forecasted cash flow (based on current NYMEX forward commodity prices) and proceeds from asset divestitures.

During the first six months of 2018, the Company successfully completed 105 horizontal wells in the northern portion of the play and 27 horizontal wells in the southern portion of the play. In the northern portion of the play, approximately 50 percent of wells placed on production were Wolfcamp B interval wells, approximately 45 percent were Wolfcamp A interval wells and the remaining 5 percent were primarily Lower Spraberry Shale wells. In the southern portion of the play, approximately 70 percent of the wells placed on production were Wolfcamp B interval wells, approximately 20 percent were Wolfcamp A interval wells and the remaining 10 percent were Wolfcamp D interval wells.

The Company continues to utilize its integrated services to control well costs and operating costs and to support the execution of its drilling and production activities in the Spraberry/Wolfcamp field. During the six months ended June 30, 2018, the Company utilized six of its eight Company-owned fracture stimulation fleets to support its drilling operations in the Spraberry/Wolfcamp field. The Company also owns other field service equipment that supports its drilling and production operations, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools.

The Company's sand mine in Brady, Texas, which is strategically located within close proximity (approximately 190 miles) of the Spraberry/Wolfcamp field, provides a secure sand source for the Company's horizontal drilling program. In addition, Pioneer has signed a contract for its initial offtake of sand sourced in West Texas where significant new sand supplies are expected to be available in 2018. The Company is evaluating additional contracts for lower cost sand sourced in West Texas.

The Company continues to pursue initiatives to improve drilling and completion efficiencies and reduce costs. The Company's long-term growth plan also continues to focus on optimizing the development of the field and addressing the future requirements for water sourcing and disposal, field infrastructure, gas processing, pipeline takeaway capacity for its products, oilfield services, tubulars, electricity, buildings and roads.

The Company has entered into firm pipeline commitments to deliver over 90 percent of its current Permian Basin oil production to the Gulf Coast for sale into the refinery and export markets. Pioneer's oil volumes under these firm transportation contracts increase through early 2021 commensurate with the Company's forecasted Permian Basin oil production growth. During the second quarter of 2018, the Company delivered 165 thousand barrels per day ("MBOPD") to the Gulf Coast, with 103 MBOPD being exported. These firm pipeline contracts insulate Pioneer from the recent widening of the Midland-Cushing oil price basis differential by selling into markets based on Brent-related pricing. As a result of this pricing benefit, Gulf Coast refinery and export sales added $86 million of incremental cash flow in the first half of 2018.

The Company also remains well positioned to move its Permian Basin gas production. Approximately 75 percent of Pioneer’s Midland Basin gas production is transported under firm pipeline transportation agreements tied to the southern California gas price index. The remainder is primarily sold under term contracts in the Waha market. Additional firm pipeline transportation has been secured on a third-party pipeline to the Gulf Coast, which is anticipated to be placed into service early in the fourth quarter of 2019. Firm transportation on this pipeline will provide access to LNG exports, refineries, petrochemical facilities and Mexican markets.

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Asset Divestitures.

•

South Texas area. In February 2018, the Company announced its intention to divest its properties in South Texas. In April 2018, the Company completed the sale of its West Eagle Ford Shale assets to an unaffiliated third party for cash proceeds of $103 million, before normal closing adjustments. The sale resulted in a gain of $78 million. See Note 3 of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's sale of its West Eagle Ford Shale assets.

The Company's remaining position in South Texas and in the Eagle Ford Shale is approximately 59,000 net acres, all of which is held by production. The Company expects to divest of these assets in 2018. No assurance can be given that the sales will be completed in accordance with the Company's plan or on terms and at prices acceptable to the Company.

•

Raton Basin. In June 2018, the Company entered into a purchase and sale agreement with an unaffiliated third party to sell all of its assets in the Raton Basin for cash proceeds of $79 million, before normal closing adjustments. Associated with the sale, the Company recorded a noncash impairment charge of $77 million during June 2018 to reduce the carrying value of its Raton Basin assets to their estimated fair value less costs to sell. The Company classified its Raton Basin assets and liabilities as held for sale in the accompanying consolidated balance sheet as of June 30, 2018. The sale was completed in July 2018. See Note 3 of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's sale of its Raton Basin assets.

•

West Panhandle area. In July 2018, the Company entered in a purchase and sale agreement with an unaffiliated third party to sell its assets in the West Panhandle field in Texas for cash proceeds of $201 million, before normal closing adjustments. The assets being sold represent all of Pioneer’s interests in the field, including all of its producing wells and the associated infrastructure. The sale of the Company's West Panhandle assets is expected to result in a pretax gain of $155 million to $170 million. The transaction is expected to close during the third quarter, subject to the satisfaction of customary closing conditions and receipt of specified regulatory approvals. See Note 16 of Notes to the Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's sale of its West Panhandle assets.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $1.3 billion and $2.6 billion for the three and six months ended June 30, 2018, respectively, as compared to $768 million and $1.6 billion for the same respective periods in 2017.

The increase in oil and gas revenues during the three months ended June 30, 2018, as compared to the same period in 2017, is primarily due to increases of 36 percent and 70 percent in oil and NGL prices, respectively, and increases of 26 percent, 21 percent and 32 percent in daily oil, NGL and gas sales volumes, respectively, partially offset by a 25 percent decrease in gas prices. The increase in oil and gas revenues during the six months ended June 30, 2018, as compared to the same period in 2017, is primarily due to increases of 31 percent and 57 percent in oil and NGL prices, respectively, and increases of 26 percent, 30 percent and 22 percent in daily oil, NGL and gas sales volumes, respectively, partially offset by a 17 percent decrease in gas prices. Realized prices are inclusive of the effect of the adoption of ASC 606 as described above in Adoption of New Accounting Standards.

The following table provides average daily sales volumes for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Oil (Bbls)	185,495	146,884	184,015	146,255
NGLs (Bbls)	64,473	53,268	65,324	50,066
Gas (Mcf)	466,414	353,612	422,880	346,149
Total (BOEs)	327,704	259,087	319,819	254,012

Average daily BOE sales volumes increased by 26 percent for both the three and six months ended June 30, 2018, respectively, as compared to the same respective periods in 2017, principally due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.

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The oil, NGL and gas prices that the Company reports are based on the market prices received for each commodity. The following table provides the Company's average prices for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Oil (per Bbl)	$	61.20	$	45.00	$	61.42	$	47.01
NGL (per Bbl)	$	28.83	$	16.91	$	28.28	$	18.03
Gas (per Mcf)	$	1.97	$	2.62	$	2.25	$	2.70
Total (per BOE)	$	43.12	$	32.56	$	44.08	$	34.31

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to the Gulf Coast refinery or international export markets and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming both the risk and rewards of ownership, including credit risk, of the commodities purchased and the responsibility to deliver the commodities sold. The transportation costs associated with these transactions are presented as a component of purchased oil and gas expense. The net effect of third party purchases and sales of oil and gas for the three and six months ended June 30, 2018 was income of $69 million and $86 million, respectively, as compared to a loss of $14 million and $33 million for the same respective periods in 2017. Firm transportation payments on excess pipeline capacity commitments are included in other expense in the accompanying consolidated statements of operations. See Note 13 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information on transportation commitment charges.

Interest and other income. The Company's interest and other income for the three and six months ended June 30, 2018 was $9 million and $26 million, respectively, as compared to $16 million and $30 million for the same respective periods in 2017. The decrease in interest and other income during the three months ended June 30, 2018, as compared to the same period in 2017, was primarily due to decreases of (i) $5 million in severance and sales tax refunds and (ii) $3 million in interest income as a result of a decrease in investments in commercial paper, corporate bonds and time deposits. The decrease in interest and other income during six months ended June 30, 2018, as compared to the same period in 2017, was primarily due to decreases of (i) $6 million in severance and sales tax refunds and (ii) $2 million in interest income as a result of a decrease in investments in commercial paper, corporate bonds and time deposits, partially offset by an increase of (iii) $5 million in seismic data sales. See Note 12 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's interest and other income.

Derivative gains (losses), net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three and six months ended June 30, 2018, the Company recorded $358 million and $566 million, respectively, of net derivative losses, on commodity price and marketing derivatives, of which $140 million and $211 million, respectively, represented net cash payments. During the three and six months ended June 30, 2017, the Company recorded $135 million and $286 million, respectively, of net derivative gains on commodity price, diesel price and interest rate derivatives, of which $24 million and $35 million, respectively, represented net cash receipts.

The following tables detail the net cash receipts (payments) on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf) for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30, 2018							Six Months Ended June 30, 2018
	Net cash receipts (payments)			Price impact				Net cash receipts (payments)			Price impact
	(in millions)							(in millions)
Oil derivative payments	$	(140	)	$	(8.28	)	per Bbl	$	(212	)	$	(6.41	)	per Bbl
NGL derivative receipts	—			$	—		per Bbl	—			$	0.04		per Bbl
Gas derivative receipts	1			$	0.02		per Mcf	2			$	0.03		per Mcf
Total net commodity derivative payments	$	(139	)					$	(210	)

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	Three Months Ended June 30, 2017					Six Months Ended June 30, 2017
	Net cash receipts		Price impact			Net cash receipts		Price impact
	(in millions)					(in millions)
Oil derivative receipts	$	21	$	1.59	per Bbl	$	33	$	1.22	per Bbl
NGL derivative receipts	1		$	0.01	per Bbl	1		$	0.02	per Bbl
Gas derivative receipts	1		$	0.02	per Mcf	—		$	—	per Mcf
Total net commodity derivative receipts	$	23				$	34

The Company's open derivative contracts are subject to continuing market risk. See Note 5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Company's derivative contracts.

Gain on disposition of assets, net. The Company recorded a net gain on the disposition of assets of $79 million and $83 million for the three and six months ended June 30, 2018, respectively, as compared to $194 million and $205 million for the same respective periods in 2017. For the three and six months ended June 30, 2018, the Company's gain on disposition of assets is primarily due to a gain of $78 million recognized on the sale of approximately 10,200 net acres in the West Eagle Ford Shale. For the three and six months ended June 30, 2017, the gain on disposition of assets is primarily due to a gain of $194 million recognized on the sale of approximately 20,500 acres in the Martin County region of the Permian Basin. See Note 3 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's completed divestitures and its plan to sell its South Texas, Raton and West Panhandle assets.

Oil and gas production costs. The Company recognized oil and gas production costs of $243 million and $456 million during the three and six months ended June 30, 2018, respectively, as compared to $147 million and $288 million during the same respective periods in 2017. Gathering, processing and transportation charges are inclusive of the effect of the adoption of ASC 606 as described above in Adoption of New Accounting Standards. Lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control.

The following table provides the components of the Company's total production costs per BOE for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,						Six Months Ended June 30,
	2018			2017			2018			2017
Lease operating expenses	$	4.61		$	4.79		$	4.51		$	4.89
Gathering, processing and transportation charges	3.05			0.82			2.77			0.91
Net natural gas plant (income) charges	(0.30		)	(0.18		)	(0.21		)	(0.23		)
Workover costs	0.79			0.76			0.80			0.68
Total production costs	$	8.15		$	6.19		$	7.87		$	6.25

Total oil and gas production costs per BOE for the three and six months ended June 30, 2018 increased by 32 percent and 26 percent, respectively, as compared to the same respective periods in 2017. Lease operating expenses per BOE decreased during the three and six months ended June 30, 2018, as compared to the same respective periods in 2017, primarily due to a greater proportion of the Company's production coming from horizontal wells in Spraberry/Wolfcamp area that have lower per BOE lease operating costs. Gathering, processing and transportation charges include transportation costs paid to third-party carriers and costs associated with gas processing. The adoption of ASC 606 had the effect of increasing gathering, processing and transportation charges by $1.82 and $1.68 per BOE, respectively, during the three and six months ended June 30, 2018 over what would have been reported if these charges were accounted for under ASC 605. The change in net natural gas plant income per BOE for the three and six months ended June 30, 2018, as compared to the same respective periods in 2017, is primarily reflective of changes in net revenues earned from gathering and processing of third party gas in Company-owned facilities. The increase in workover costs per BOE during the three and six months ended June 30, 2018, as compared to the same respective periods in 2017, was primarily due to an increase in Permian Basin vertical well workover activity as a result of the improvement in oil prices.

Production and ad valorem taxes. The Company's production and ad valorem taxes were $70 million and $146 million during the three and six months ended June 30, 2018, respectively, as compared to $51 million and $99 million for the same respective periods in 2017. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. The increase in production and ad valorem taxes per BOE for the three and six months ended June 30, 2018, as compared to the same respective periods in 2017, is primarily due to the increase in oil and NGL prices during 2018 and,

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for ad valorem tax purposes, the higher valuation attributable to the Company's successful Spraberry/Wolfcamp horizontal drilling program during 2018 and 2017.

The following table provides the Company's production and ad valorem taxes per BOE for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
Production taxes	$	1.72	$	1.45	$	1.86	$	1.52
Ad valorem taxes	0.63		0.74		0.66		0.63
Total production and ad valorem taxes	$	2.35	$	2.19	$	2.52	$	2.15

Depletion, depreciation and amortization expense. The Company's DD&A expense was $378 million ($12.69 per BOE) and $735 million ($12.70 per BOE) for the three and six months ended June 30, 2018, respectively, as compared to $341 million ($14.46 per BOE) and $678 million ($14.74 per BOE) during the same respective periods in 2017. Depletion expense on oil and gas properties was $12.10 and $12.20 per BOE during the three and six months ended June 30, 2018, respectively, as compared to $13.96 and $14.23 per BOE during the same respective periods in 2017.

Depletion expense on oil and gas properties per BOE for the three and six months ended June 30, 2018 decreased 13 percent and 14 percent, respectively. as compared to the same respective periods in 2017, primarily due to (i) additions to proved reserves attributable to the Company's successful Spraberry/Wolfcamp horizontal drilling program and (ii) oil and NGL price increases and cost reduction initiatives, both of which had the effect of adding proved reserves by lengthening the economic lives of the Company's producing wells.

Impairment of oil and gas properties and other long-lived assets. During the three and six months ended June 30, 2018, the Company recognized an impairment charge of $77 million to reduce the carrying value of its Raton Basin field assets to the agreed upon sales price for these assets.

The Company performs assessments of its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. In order to perform these assessments, management uses various observable and unobservable inputs, including management's outlooks for (i) proved reserves and risk-adjusted probably and possible reserves, (ii) commodity prices, (iii) production costs, (iv) capital expenditures and (v) production. Management's long-term commodity price outlooks are developed based on third-party, longer-term commodity future price outlooks as of a measurement date ("Management's Price Outlooks"). The Company's impairment assessments resulted in a $285 million impairment charge during the six months ended June 30, 2017 to reduce the carrying values of the Raton Basin field to its estimated fair value at that time.

It is reasonably possible that the Company's estimate of undiscounted future net cash flows may change in the future resulting in the need to impair the carrying values of its properties. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) changes in Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these properties.

See Note 3 and 4 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's sale of its Raton Basin assets and proved oil and gas property impairment charges.

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expenses and lease abandonments and other exploration expenses for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)
Geological and geophysical	$	24	$	18	$	51	$	41
Exploratory well costs	4		1		8		10
Leasehold abandonments and other	—		7		4		8
	$	28	$	26	$	63	$	59

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The geological and geophysical expenses for the three and six months ended June 30, 2018 and 2017 were primarily related to acquiring seismic surveys over a portion of the northern Spraberry/Wolfcamp area and geological and geophysical personnel costs.

During the six months ended June 30, 2018, the Company drilled and evaluated 122 exploration/extension wells, 119 of which were successfully completed as discoveries. During the same period in 2017, the Company drilled and evaluated 95 exploration/extension wells, 93 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and six months ended June 30, 2018 was $95 million ($3.18 per BOE) and $185 million ($3.20 per BOE), respectively, as compared to $81 million ($3.43 per BOE) and $165 million ($3.58 per BOE) for the same respective periods in 2017. The increase in general and administrative costs during the three and six months ended June 30, 2018, as compared to the same respective periods in 2017, was primarily due to an increase in compensation costs, including benefits expense, as a result of an increase in headcount due to the Company's continued growth. The decrease in general and administrative expense per BOE during the three and six months ended June 30, 2018, as compared to the same respective periods in 2017, was primarily due to increases in sales volumes of 26 percent for the three and six months ended June 30, 2018, as compared to the same respective periods in 2017.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $4 million and $8 million for the three and six months ended June 30, 2018, as compared to $5 million and $10 million for the same respective periods in 2017. See Note 9 of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $32 million and $68 million for the three and six months ended June 30, 2018, respectively, as compared to $35 million and $81 million for the same respective periods in 2017. The decrease in interest expense during the three and six months ended June 30, 2018, as compared to the same respective periods in 2017, was primarily due to the repayment of the Company's 6.875% senior notes (the "6.875% Senior Notes"), which matured in May 2018, and the Company's 6.65% senior notes (the "6.65% Senior Notes"), which matured in March 2017. The weighted average interest rate on the Company's indebtedness for the three and six months ended June 30, 2018 was 5.4 percent and 5.5 percent, respectively, as compared to 5.6 percent and 5.7 percent for the same respective periods in 2017. See Note 7 of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for additional information about the Company's long-term debt and interest expense.

Other expense. Other expense was $76 million and $133 million for the three and six months ended June 30, 2018, respectively, as compared to $59 million and $119 million for the same respective periods in 2017. The increase in other expense during the three months ended June 30, 2018, as compared to the same period in 2017, was primarily due to increases of (i) $9 million in asset divestiture related charges and (ii) $7 million in legal and environmental expenses. The increase in other expense during the six months ended June 30, 2018, as compared to the same period in 2017, was primarily due to increases of (i) $9 million in asset divestiture related charges and (ii) $3 million in legal and environmental expenses. See Note 13 of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for additional information regarding the Company's other expenses.

Income tax provision. The Company recognized an income tax provision of $19 million and $69 million for the three and six months ended June 30, 2018, respectively, as compared to an income tax provision of $121 million and $90 million for the same respective periods in 2017. The Company's effective tax rate for the three and six months ended June 30, 2018 was 23 percent and 22 percent, respectively, as compared to 34 percent and 32 percent for the same respective periods in 2017. The U.S. statutory rate for the three and six months ended June 30, 2018 was 21 percent, reflecting the reduction in the federal corporate income tax rate from 35 percent to 21 percent beginning in 2018 as a result of the Tax Cuts and Jobs Act that was enacted in December 2017. The Company's effective tax rate for the six months ended June 30, 2017 differs from the U.S. statutory rate in effect during 2017 of 35 percent primarily due to recognizing excess tax benefits of $8 million associated with the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which requires excess tax benefits or deficiencies associated with the vesting of long-term incentive awards to be recorded as income tax expense or benefit in the statement of operations rather than as an adjustment to additional paid-in capital in the balance sheet.

As of June 30, 2018 and December 31, 2017, the Company had cumulative unrecognized tax benefits of $129 million and $124 million, respectively, resulting from research and experimental expenditures related to horizontal drilling and completions innovations. 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 it is recognized.

See Note 14 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income tax rates and tax attributes.

Liquidity and Capital Resources

Liquidity. The Company's primary sources of short-term liquidity are (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) sales of short-term and long-term investments, (iv) proceeds from divestitures and (iv) unused borrowing capacity under its credit facility. Although the Company expects that these sources of funding will be adequate to fund its 2018 capital expenditures, dividend payments and provide adequate liquidity to fund other needs, including previously announced stock repurchases, no assurance can be given that such funding sources will be adequate to meet the Company's future needs.

The Company's primary needs for cash are for (i) capital expenditures, (ii) acquisitions of oil and gas properties, vertical integration assets and facilities, (iii) payments of contractual obligations, including debt maturities, (iv) dividends and share repurchases and (v) working capital obligations. Funding for these cash needs may be provided by any combination of the Company's sources of liquidity.

As of June 30, 2018, the Company had cash on hand of $792 million, short-term investments of $391 million and long-term investments of $313 million. The Company had no outstanding borrowings under its credit facility as of June 30, 2018, leaving $1.5 billion of unused borrowing capacity, and was in compliance with all of its debt covenants.

Capital resources. Cash flows from operating, investing and financing activities, as reflected in the accompanying consolidated statements of cash flows for the six months ended June 30, 2018 and 2017, are summarized below.

Operating activities. Net cash provided by operating activities was $1.5 billion during the six months ended June 30, 2018, as compared to $847 million during the same period in 2017. The increase in net cash provided by operating activities for the six months ended June 30, 2018, as compared to the same period in 2017, is primarily due to increases in the Company's oil and gas revenues for the six months ended June 30, 2018 as a result of increases in commodity prices and sales volumes, partially offset by increases in oil and gas production costs, production and ad valorem taxes and cash derivative payments.

Investing activities. Net cash used in investing activities was $1.0 billion during the six months ended June 30, 2018, as compared $777 million during same period in 2017. The increase in net cash used in investing activities during the six months

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ended June 30, 2018, as compared to the same period in 2017, is primarily due to (i) an increase of $514 million in additions to oil and gas properties and (ii) a decrease of $234 million in proceeds from dispositions of assets, partially offset by (iii) an increase of $439 million in net proceeds from investments and (iv) a decrease of $60 million in additions to other assets and other property and equipment. During the six months ended June 30, 2018, the Company's expenditures for investing activities were primarily funded by net cash provided by operating activities.

Financing activities. Net cash used in financing activities was $534 million during the six months ended June 30, 2018, as compared to $528 million during the same period in 2017. The increase in net cash used in financing activities during the six months ended June 30, 2018, as compared to the same period in 2017, is primarily due (i) an increase of $20 million in dividends paid, (ii) an increase of $15 million in purchases of treasury stock and (iii) an increase of $7 million in payments of other liabilities, partially offset by (iv) a reduction of $35 million in senior note repayments. During the six months ended June 30, 2018 and 2017, the Company repaid $450 million associated with the Company's 6.875% Senior Notes that matured in May 2018 and $485 million associated with the Company's 6.65% Senior Notes that matured in March 2017, respectively. See Note 7 of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for additional information regarding the Company's repayment of the 6.65% and 6.875% Senior Notes.

As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities and preferred or common stock. The Company cannot predict the timing or ultimate outcome of any such actions, as they are subject to market conditions, among other factors. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock, with respect to such matters as dividends and liquidation rights, and may also have other rights and preferences as determined by the Company's Board.

Capital commitments. During 2018, the Company plans to focus its capital spending primarily on oil drilling activities in the Spraberry/Wolfcamp area of the Permian Basin. The Company's capital budget for 2018 has been increased from $2.9 billion to $3.3 billion to $3.4 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and information technology system upgrades) to reflect (i) additional higher intensity completions during the second half of 2018, (ii) drilling rig additions during the second half of 2018 to support its 2019 plan and (iii) inflationary pressures associated with the current commodity price environment. The Company expects to fund the capital budget increase from forecasted cash flow and proceeds from asset divestitures. The Company's capital expenditures during the six months ended June 30, 2018 were $1.8 billion, consisting of $1.7 billion for oil and gas property related expenditures and $109 million for vertical integration, system upgrades and other plant and equipment additions. See Operations and Drilling Highlights above for additional information regarding the Company's planned capital expenditures for 2018.

Based on results for the six months ended June 30, 2018 and the Company's current Management's Price Outlook, the Company expects that it will be able to fund its needs for cash (excluding acquisitions, if any), including the 2018 stock repurchases, with net cash flows from operating activities, cash and cash equivalents on hand, sales of short-term and long-term investments, proceeds from divestitures and, if necessary, availability under the Credit Facility; however, no assurances can be given that such funding will be adequate to meet the Company's future needs.

Dividends/distributions. During February of 2018 and 2017, the Board declared semiannual dividends of $0.16 and $0.04 per common share, respectively. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company's liquidity and capital resources at the time.

Contractual obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments (primarily related to commitments to pay day rates for contracted drilling rigs), capital funding obligations, derivative obligations, gathering, processing. transportation and fractionation commitments, and other liabilities (including postretirement benefit obligations). Other joint interest owners in properties operated by the Company will incur portions of the costs represented by these commitments.

Firm purchase, gathering, transportation and fractionation commitments represent take-or-pay agreements, which include (i) contractual commitments to purchase sand and water for use in the Company's drilling operations and (ii) fees on volume delivery or throughput obligations for gathering, processing, transportation and fractionation services. The Company plans to purchase third party volumes to satisfy its commitments if it is economic to do so; otherwise, it will pay the contracted fees for any commitment shortfalls.

Off-balance sheet arrangements. From time-to-time, the Company enters into arrangements and transactions that can give rise to material off-balance sheet obligations. As of June 30, 2018, the material off-balance sheet arrangements and transactions that the Company had entered into included (i) operating lease agreements, (ii) drilling commitments, (iii) firm purchase, transportation and fractionation commitments, (iv) open purchase commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable. The contractual obligations for which the ultimate settlement amounts

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are not fixed and determinable include (i) derivative contracts that are sensitive to future changes in commodity prices or interest rates, (ii) gathering, processing (primarily treating and fractionation) and transportation commitments on uncertain volumes of future throughput, (iii) open delivery commitments and (iv) indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other parties that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. The Company expects to enter into similar contractual arrangements in the future, including incremental derivative contracts and additional firm purchase and transportation arrangements, in order to support the Company's business plans. There were no material changes to the Company's contractual obligations during the six months ended June 30, 2018 other than the repayment of the Company's 6.875% Senior Notes in May 2018.

See Note 10 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's Commitments and Contingencies.

The Company's commodity derivative contracts are periodically measured and recorded at fair value and continue to be subject to market and credit risk. As of June 30, 2018, these contracts represented net liabilities of $599 million. The ultimate settlement value of the Company's commodity derivatives will be dependent upon actual future commodity prices, which may differ materially from the inputs used to determine the derivatives' fair values as of June 30, 2018.

See Note 5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Company's derivative instruments and market risk.

New Accounting Pronouncements

The effects of new accounting pronouncements are discussed in Note 2 and Note 11 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements."

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2017. As such, the information contained herein should be read in conjunction with the related disclosures in the Company's Annual Report on Form 10-K for the year ended December 31, 2017.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company's potential exposure to market risks. The term "market risks," insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators regarding how the Company views and manages ongoing market risk exposures. None of the Company's market risk sensitive instruments are entered into for speculative purposes.

The Company had no interest rate derivative activity during the six months ended June 30, 2018. The following table reconciles the changes that occurred in the fair values of the Company's open commodity derivative contracts during the six months ended June 30, 2018:



	Derivative Contract Net Assets (Liabilities)
	(in millions)
Fair value of contracts outstanding as of December 31, 2017	$	(244	)
Changes in contract fair value	(566		)
Contract maturity payments	211
Fair value of contracts outstanding as of June 30, 2018	$	(599	)

Interest rate sensitivity. See Note 7 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and Capital Commitments, Capital Resources and Liquidity included in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding the Company's outstanding debt and debt transactions.

The following table provides information about financial instruments to which the Company was a party as of June 30, 2018 and that are sensitive to changes in interest rates. The table presents debt maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the aggregate estimated fair value of the Company's outstanding debt. For fixed rate debt, the weighted average interest rates represent the contractual fixed rates that the Company was obligated to periodically pay on the debt as of June 30, 2018. Although the Company had no outstanding variable rate debt as of June 30, 2018, the average variable contractual rates for its credit facility (that matures in August 2020) projected forward proportionate to the forward yield curve for LIBOR on August 6, 2018 is presented in the table below.



	Six Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at June 30,
	2018			2019			2020			2021			2022			Thereafter			Total		2018
	(dollars in millions)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	450		$	500		$	600		$	750		$	2,300	$	2,397
Weighted average fixed interest rate	5.00		%	5.00		%	4.42		%	4.72		%	4.94		%	5.70		%
Average variable interest rate	3.79		%	4.19		%	4.28		%

____________________


(a)	Represents maturities of principal amounts, excluding debt issuance costs and debt issuance discounts.

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Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of June 30, 2018. Although mitigated by the Company's derivative activities, declines in oil, NGL and gas prices would reduce the Company's revenues.

The Company manages commodity price risk with derivative contracts, such as swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum ("floor" or "long put") and maximum ("ceiling") prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company's realized price will exceed the variable market prices by the long put-to-short put price differential.

See Notes 4 and 5 of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for a description of the accounting procedures followed by the Company for its derivative financial instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

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	2018						Year Ending December 31, 2019			Asset (Liability) Fair Value at June 30, 2018 (a)
	Third Quarter			Fourth Quarter			Year Ending December 31, 2019			Asset (Liability) Fair Value at June 30, 2018 (a)
										(in millions)
Oil Derivatives:
Average daily notional Bbl volumes:
Collar contracts	3,000			3,000			—			$	(7	)
Weighted average ceiling price per Bbl	$	58.05		$	58.05		$	—
Weighted average floor price per Bbl	$	45.00		$	45.00		$	—
Collar contracts with short puts	154,000			159,000			65,000			$	(560	)
Weighted average ceiling price per Bbl	$	57.70		$	57.62		$	60.74
Weighted average floor price per Bbl	$	47.34		$	47.26		$	52.69
Weighted average short put price per Bbl	$	37.31		$	37.23		$	42.69
Average forward NYMEX oil prices (b)	$	69.01		$	67.51		$	64.86
NGL Derivatives:
Ethane basis swap contracts (MMBtu) (c)	6,920			6,920			6,920			$	—
Weighted average price differential per MMBtu	$	1.60		$	1.60		$	1.60
Average forward NYMEX gas prices (b)	$	2.86		$	2.92		$	2.76
Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts	100,000			100,000			—			$	1
Weighted average fixed price per MMBtu	$	3.00		$	3.00		$	—
Collar contracts with short puts	50,000			50,000			—			$	—
Weighted average ceiling price per MMBtu	$	3.40		$	3.40		$	—
Weighted average floor price per MMBtu	$	2.75		$	2.75		$	—
Weighted average short put price per MMBtu	$	2.25		$	2.25		$	—
Average forward NYMEX gas prices (b)	$	2.86		$	2.92
Basis swap contracts:
Permian Basin index swap volume (d)	60,000			60,000			44,877			$	(37	)
Weighted average fixed price per MMBtu	$	(1.46	)	$	(1.46	)	$	(1.46	)
Average forward basis differential prices (e)	$	(0.94	)	$	(1.10	)	$	(1.15	)
Southern California index swap contracts (f)	80,000			66,522			84,932			$	6
Weighted average fixed price per MMBtu	$	0.30		$	0.50		$	0.33
Average forward basis differential prices (g)	$	1.65		$	1.35		$	1.09

___________________

(a)

In accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 210-20 and ASC 815-10, the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements classifications.


(b)	The average forward NYMEX oil and gas prices are based on August 6, 2018 market quotes.


(c)	The ethane basis swap contracts reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The ethane basis swap contracts fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane.


(d)	The referenced swap contracts fix the basis differential between the index prices at which the Company sells its Permian Basin gas and the HH index price used in swap contracts and collar contracts with short puts.


(e)	The average forward basis differential prices are based on August 6, 2018 market quotes for basis differentials between Permian Basin index prices and the HH index price.


(f)	The referenced swap contracts fix the basis differential between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in Arizona and southern California.


(g)	The average forward basis differential prices are based on August 6, 2018 market quotes for basis differentials between Permian Basin index prices and southern California index prices.

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PIONEER NATURAL RESOURCES COMPANY

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PIONEER NATURAL RESOURCES COMPANY

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. During the three months ended June 30, 2018, the Company implemented a new enterprise resource planning ("ERP") system. Accordingly, the Company modified the design and documentation of certain internal control processes and procedures relating to the new ERP system, which resulted in changes to the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). The Company expects the new ERP system to strengthen its internal financial controls by automating certain manual processes and standardizing business processes and reporting across the organization.

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PIONEER NATURAL RESOURCES COMPANY

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. See Note 10 of Notes to Consolidated Financial Statements included in "Part I, Item 1. Financial Statements" for additional information regarding legal proceedings involving the Company.

Item 1A. Risk Factors

In addition to the information set forth in this Report, the risks that are discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2017, under the headings "Part I, Item 1. Business – Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" should be carefully considered as such risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of treasury stock under plans or programs during the three months ended June 30, 2018:



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased under Plans or Programs (b)
April 2018	458	$	182.84	—	$	82,995,111
May 2018	375	$	208.47	—	$	82,995,111
June 2018	30,130	$	178.31	30,000	$	77,647,626
Total	30,963			30,000

____________________


(a)	Includes 458 shares, 375 shares and 130 shares purchased from employees during April, May and June 2018, respectively, in order for the employee to satisfy tax withholding payments related to share-based awards that vested during the period.


(b)	In February 2008, the Company's board of directors approved a common stock repurchase program to offset the impact of dilution associated with annual employee stock awards. The stock repurchase program allows for up to $100 million of common stock to be repurchased during 2018.

Item 4. Mine Safety Disclosures

The Company's sand mines are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Report.

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PIONEER NATURAL RESOURCES COMPANY

Item 6. Exhibits

Exhibits



Exhibit Number		Description

10.1	(a) —	Eleventh Amendment to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan dated June 29, 2018.

12.1	(a) —	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.

18.1	(a) —	Ernst & Young LLP Preferability Letter

31.1	(a) —	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

31.2	(a) —	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

32.1	(b) —	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

32.2	(b) —	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

95.1	(a) —	Mine Safety Disclosures.

101.INS	(a) —	XBRL Instance Document.

101.SCH	(a) —	XBRL Taxonomy Extension Schema.

101.CAL	(a) —	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF	(a) —	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB	(a) —	XBRL Taxonomy Extension Label Linkbase Document.

101.PRE	(a) —	XBRL Taxonomy Extension Presentation Linkbase Document.

_____________


(a)	Filed herewith.


(b)	Furnished herewith.

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PIONEER NATURAL RESOURCES COMPANY

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 hereto duly authorized.



	PIONEER NATURAL RESOURCES COMPANY

Date: August 9, 2018	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy,
		Executive Vice President and Chief Financial Officer

Date: August 9, 2018	By:	/s/ MARGARET M. MONTEMAYOR
		Margaret M. Montemayor,
		Vice President and Chief Accounting Officer