PIONEER NATURAL RESOURCES CO - Quarter Report: 2017 March (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 March 31, 2017



¨	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 May 1, 2017 170,094,162

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 March 31, 2017 and December 31, 2016	5

	Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016	7

	Consolidated Statement of Equity for the three months ended March 31, 2017	8

	Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016	9

	Notes to Consolidated Financial Statements	10

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	37

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 4.	Mine Safety Disclosures	39

Item 6.	Exhibits	40

Signatures		41

Exhibit Index		42

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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, 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 and refining 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, 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 Report 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, 2016 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.


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


•	"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.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)



	March 31, 2017			December 31, 2016
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	663		$	1,118
Short-term investments	1,546			1,441
Accounts receivable:
Trade, net	426			517
Due from affiliates	1			1
Income taxes receivable	3			3
Inventories	200			181
Derivatives	73			14
Other	28			23
Total current assets	2,940			3,298
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	18,780			18,566
Unproved properties	448			486
Accumulated depletion, depreciation and amortization	(8,546		)	(8,211		)
Total property, plant and equipment	10,682			10,841
Long-term investments	168			420
Goodwill	272			272
Other property and equipment, net	1,577			1,529
Derivatives	9			—
Other assets, net	101			99
	$	15,749		$	16,459

The financial information included as of March 31, 2017 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)



	March 31, 2017			December 31, 2016
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	751		$	741
Due to affiliates	51			134
Interest payable	39			68
Current portion of long-term debt	—			485
Derivatives	9			77
Other	102			61
Total current liabilities	952			1,566
Long-term debt	2,729			2,728
Derivatives	2			7
Deferred income taxes	1,366			1,397
Other liabilities	352			350
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 173,779,363 and 173,221,845 shares issued as of March 31, 2017 and December 31, 2016, respectively	2			2
Additional paid-in capital	8,914			8,892
Treasury stock at cost: 3,685,461 and 3,497,742 shares as of March 31, 2017 and December 31, 2016, respectively	(254		)	(218		)
Retained earnings	1,679			1,728
Total equity attributable to common stockholders	10,341			10,404
Noncontrolling interests in consolidated subsidiaries	7			7
Total equity	10,348			10,411
Commitments and contingencies
	$	15,749		$	16,459

The financial information included as of March 31, 2017 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 March 31,
	2017			2016
Revenues and other income:
Oil and gas	$	809		$	409
Sales of purchased oil and gas	484			223
Interest and other	13			8
Derivative gains, net	151			43
Gain on disposition of assets, net	11			2
	1,468			685
Costs and expenses:
Oil and gas production	141			156
Production and ad valorem taxes	47			29
Depletion, depreciation and amortization	337			353
Purchased oil and gas	503			243
Impairment of oil and gas properties	285			32
Exploration and abandonments	33			59
General and administrative	84			74
Accretion of discount on asset retirement obligations	5			5
Interest	46			55
Other	60			87
	1,541			1,093
Loss before income taxes	(73		)	(408		)
Income tax benefit	31			141
Net loss attributable to common stockholders	$	(42	)	$	(267	)

Basic and diluted net loss per share attributable to common stockholders	$	(0.25	)	$	(1.65	)
Weighted average shares outstanding:
Basic	170			162
Diluted	170			162

Dividends declared per share	$	0.04		$	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, 2016	169,724		$	2	$	8,892	$	(218	)	$	1,728		$	7	$	10,411
Dividends declared ($0.04 per share)	—		—		—		—			(7		)	—		(7		)
Purchases of treasury stock	(188	)	—		—		(36		)	—			—		(36		)
Compensation costs:
Vested compensation awards	558		—		—		—			—			—		—
Compensation costs included in net loss	—		—		22		—			—			—		22
Net loss	—		—		—		—			(42		)	—		(42		)
Balance as of March 31, 2017	170,094		$	2	$	8,914	$	(254	)	$	1,679		$	7	$	10,348

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)



	Three Months Ended March 31,
	2017			2016
Cash flows from operating activities:
Net loss	$	(42	)	$	(267	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	337			353
Impairment of oil and gas properties	285			32
Impairment of inventory and other property and equipment	—			4
Exploration expenses, including dry holes	10			40
Deferred income taxes	(31		)	(141		)
Gain on disposition of assets, net	(11		)	(2		)
Accretion of discount on asset retirement obligations	5			5
Interest expense	1			5
Derivative related activity	(141		)	175
Amortization of stock-based compensation	22			21
Other	25			17
Change in operating assets and liabilities:
Accounts receivable	92			33
Income taxes receivable	—			40
Inventories	(19		)	—
Investments	4			—
Other current assets	(6		)	(3		)
Accounts payable	(153		)	(169		)
Interest payable	(29		)	(16		)
Other current liabilities	15			(17		)
Net cash provided by operating activities	364			110
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	78			1
Proceeds from investments	458			—
Purchase of investments	(315		)	(914		)
Additions to oil and gas properties	(433		)	(471		)
Additions to other assets and other property and equipment, net	(86		)	(79		)
Net cash used in investing activities	(298		)	(1,463		)
Cash flows from financing activities:
Principal payments on long-term debt	(485		)	—
Proceeds from issuance of common stock, net of issuance costs	—			1,597
Purchases of treasury stock	(36		)	(23		)
Net cash provided by (used in) financing activities	(521		)	1,574
Net increase (decrease) in cash and cash equivalents	(455		)	221
Cash and cash equivalents, beginning of period	1,118			1,391
Cash and cash equivalents, end of period	$	663		$	1,612

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

March 31, 2017

(Unaudited)

NOTE A. 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 field in southeast Colorado and the West Panhandle field in the Texas Panhandle.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of March 31, 2017 and for the three months ended March 31, 2017 and 2016 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, 2016.

Certain reclassifications have been made to the 2016 financial statement and footnote amounts in order to conform to the 2017 presentation.

Issuance of common stock. During the first and second quarters of 2016, the Company issued 13.8 million and 6.0 million shares of common stock, respectively, and received cash proceeds of $1.6 billion and $937 million, respectively, net of associated underwriter discounts and offering expenses.

New accounting pronouncements. In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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 M for additional discussion on the impact of the adoption to the Company's income tax provision.

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 way lease expenses are accounted for. 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.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU 2016-11, which rescinded guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. Entities have the option of using either a full retrospective or modified approach to adopt the new standards and the Company plans to utilize the modified approach to adopt the new standard upon its effective date. The Company is evaluating the new guidance, including identifying revenue

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

streams and reviewing contracts and procedures currently in place. The Company does not anticipate this standard will have a material impact on its consolidated financial statements.

NOTE C. Acquisitions and Divestitures

Permian Basin Acquisition. In August 2016, the Company acquired approximately 28,000 net acres in the Permian Basin, with net production of approximately 1,400 barrels of oil equivalent per day ("BOEPD"), from an unaffiliated third party for $428 million, including normal closing adjustments. The acquisition was accounted for using the acquisition method under ASC 805, "Business Combinations," which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date.

The following table represents the allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date (in millions):



Assets acquired:
Proved properties	$	79
Unproved properties	347
Other property and equipment	5
Liabilities assumed:
Asset retirement obligations	(2		)
Other liabilities	(1		)
Net assets acquired	$	428

The fair value measurements of the net assets acquired are based on inputs that are not observable in the market and, therefore, represent Level 3 inputs in the fair value hierarchy (see Note D for a description of the input levels in the fair value hierarchy). The Company calculated the fair values of the acquired proved properties and asset retirement obligations using a discounted future cash flow model that utilizes management's estimates of (i) proved reserves, (ii) forecasted production rates, (iii) future operating, development and plugging and abandonment costs, (iv) future commodity prices and (v) a discount rate of 10 percent for proved properties and seven percent for asset retirement obligations. The Company calculated the fair values of the acquired unproved properties based on the average price per acre in comparable market transactions. The operating results attributable to the acquired assets and liabilities assumed are included in the Company's accompanying consolidated statements of operations since the date of acquisition.

Divestitures. For the three months ended March 31, 2017 and March 31, 2016, the Company recorded net gains on the disposition of assets of $11 million and $2 million, respectively. During the three months ended March 31, 2017, the Company completed the sales of nonstrategic proved and unproved properties in the Permian Basin for cash proceeds of $77 million, which resulted in a gain of $10 million.

NOTE D. 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.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

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.

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



	Fair Value Measurement at March 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 at March 31, 2017
	(in millions)
Assets:
Commodity derivatives	$	—	$	76	$	—	$	76
Interest rate derivatives	—		6		—		6
Deferred compensation plan assets	86		—		—		86
Total assets	86		82		—		168
Liabilities:
Commodity derivatives	—		11		—		11
Total liabilities	—		11		—		11
Total recurring fair value measurements	$	86	$	71	$	—	$	157

Commodity derivatives. The Company's commodity derivatives represent oil, NGL, gas and diesel 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 March 31, 2017, the significant inputs to these asset values represented Level 1 independent active exchange market price inputs.

Interest rate derivatives. The Company's interest rate derivative liabilities represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The derivative values attributable to the Company's interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) forward active market-quoted London Interbank Offered Rates ("LIBOR") and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative fair value measurements represent Level 2 inputs in the hierarchy.

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 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 or liabilities that are acquired or written down to fair value when they are impaired or held for sale. See Note C for information on the fair value of assets and liabilities acquired in the Permian Basin acquisition.

Proved oil and gas properties. As a result of the Company's proved property impairment assessments, the Company recognized noncash impairment charges to reduce the carrying values of (i) the Raton field during the three months ended March 31, 2017 and (ii) the West Panhandle field during the three months ended March 31, 2016 to their estimated fair values.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

The Company calculated the fair values of the Raton and West Panhandle fields using a discounted future cash flow model. Significant Level 3 assumptions associated with the calculations included management's longer-term commodity price outlooks ("Management's Price Outlooks") and management's outlooks for (i) production costs, (ii) capital expenditures, (iii) production 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.

The following table presents the fair value and fair value adjustments (in millions) for the Company's 2017 and 2016 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks:



							Management's Price Outlooks
	Impairment Date	Fair Value		Fair Value Adjustment			Oil		Gas
Raton	March 2017	$	186	$	(285	)	$	53.65	$	3.00
West Panhandle	March 2016	$	33	$	(32	)	$	49.77	$	3.24

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or 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.

Unproved oil and gas properties. During March 2016, the Company recorded an impairment charge of $32 million to write-off the carrying value of its unproved royalty acreage in Alaska (reported in exploration and abandonments in the accompanying consolidated statements of operations) as a result of the operator curtailing operations in the area and Management's Price Outlooks.

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 March 31, 2017 and December 31, 2016 are as follows:



	March 31, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Commercial paper, corporate bonds and time deposits	$	1,724	$	1,721	$	1,906	$	1,901
Current portion of long-term debt	$	—	$	—	$	485	$	490
Long-term debt	$	2,729	$	2,961	$	2,728	$	2,956

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 statement 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, investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates. The following table provides the components of the Company's cash and cash equivalents and investments as of March 31, 2017:

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)



	March 31, 2017
Consolidated Balance Sheet Location	Cash		Commercial Paper		Corporate Bonds		Time Deposits		Total
	(in millions)
Cash and cash equivalents	$	653	$	10	$	—	$	—	$	663
Short-term investments	—		199		813		534		1,546
Long-term investments	—		—		168		—		168
	$	653	$	209	$	981	$	534	$	2,377

Debt obligations. The Company's debt obligations are composed of its credit facility and senior notes. The fair value of the Company's debt obligations is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy. The fair value of the Company's credit facility is calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rates and (iii) the applicable credit-adjustments. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The 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 E. 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.

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

March 31, 2017

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of March 31, 2017 and the weighted average oil prices for those contracts:



	2017									Year Ending December 31,
	Second Quarter			Third Quarter			Fourth Quarter			2018		2019
Collar contracts:
Volume (Bbl)	6,000			6,000			6,000			—		—
Price per Bbl:
Ceiling	$	70.40		$	70.40		$	70.40		$	—	$	—
Floor	$	50.00		$	50.00		$	50.00		$	—	$	—
Collar contracts with short puts (a):
Volume (Bbl)	129,000			147,000			155,000			20,000		—
Price per Bbl:
Ceiling	$	61.19		$	62.03		$	62.12		$	65.14	$	—
Floor	$	48.46		$	49.81		$	49.82		$	50.00	$	—
Short put	$	40.45		$	41.07		$	41.02		$	40.00	$	—
Rollfactor swap contracts (b):
Volume (Bbl)	20,000			20,000			20,000			—		—
NYMEX roll price	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	—	$	—

____________________


(a)	Subsequent to March 31, 2017, the Company entered into additional oil collar contracts with short puts for 26,000 Bbl per day of 2018 production with a ceiling price of $60.49 per Bbl, a floor price of $50.19 per Bbl and a short put price of $40.00 per Bbl.

(b)

Represents swaps that fix the difference between (i) each day's price per Bbl of WTI for the first nearby NYMEX month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby NYMEX month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. Subsequent to March 31, 2017, the Company paid a nominal amount to terminate its oil rollfactor swap contracts for the third quarter of 2017.

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.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of March 31, 2017 and the weighted average NGL prices for those contracts:



	2017						Year Ending December 31,
	Second Quarter		Third Quarter		Fourth Quarter		2018		2019
Butane swap contracts (a):
Volume (Bbl)	2,000		2,000		—		—		—
Price per Bbl:	$	34.86	$	34.86	$	—	$	—	$	—
Butane collar contracts with short puts (b):
Volume (Bbl)	2,000		2,000		—		—		—
Price per Bbl:
Ceiling	$	36.12	$	36.12	$	—	$	—	$	—
Floor	$	29.25	$	29.25	$	—	$	—	$	—
Short put	$	23.40	$	23.40	$	—	$	—	$	—
Ethane collar contracts (c):
Volume (Bbl)	3,000		3,000		3,000		—		—
Price per Bbl:
Ceiling	$	11.83	$	11.83	$	11.83	$	—	$	—
Floor	$	8.68	$	8.68	$	8.68	$	—	$	—
Ethane basis swap contracts (d):
Volume (MMBtu)	6,920		6,920		6,920		6,920		6,920
Price differential ($/MMBtu)	$	1.60	$	1.60	$	1.60	$	1.60	$	1.60

____________________


(a)	Represent swap contracts that reduce the price volatility of butane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. Subsequent to March 31, 2017, the Company terminated its butane swap contracts for cash proceeds of $1 million.


(b)	Represent collar contracts with short puts that reduce the price volatility of butane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(c)	Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(d)	Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The 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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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of March 31, 2017 and the weighted average gas prices for those contracts:



	2017									Year Ending December 31,
	Second Quarter			Third Quarter			Fourth Quarter			2018		2019
Collar contracts with short puts:
Volume (MMBtu)	270,000			290,000			300,000			62,329		—
Price per MMBtu:
Ceiling	$	3.56		$	3.57		$	3.60		$	3.56	$	—
Floor	$	2.95		$	2.95		$	2.96		$	2.91	$	—
Short put	$	2.47		$	2.47		$	2.47		$	2.37	$	—
Basis swap contracts:
Mid-Continent index swap volume (a)	45,000			45,000			45,000			—		—
Price differential ($/MMBtu)	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	—	$	—
Permian Basin index swap volume (b)	—			—			26,522			9,863		—
Price differential ($/MMBtu)	$	—		$	—		$	0.30		$	0.30	$	—

____________________


(a)	Represent swap contracts that fix the basis differentials between the index price at which the Company sells its Mid-Continent gas and the HH index price used in collar contracts with short puts.


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

Marketing and basis derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of March 31, 2017, the Company did not have any marketing derivatives outstanding.

Diesel derivative activities. Periodically, the Company enters into diesel derivative swap contracts to mitigate fuel price risk. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel drilling rigs and its fracture stimulation fleet equipment. As of March 31, 2017, the Company was party to diesel derivative swap contracts for 1,000 Bbls per day for the remainder of 2017 at an average per Bbl fixed price of $62.98. In early April 2017, the Company terminated its diesel derivative swap contracts that were held at March 31, 2017 for cash proceeds of $1 million. In late April 2017, the Company entered into diesel swap contracts for 1,000 Bbls per day for the remainder of 2017 at an average per Bbl fixed price of $63.00.

Interest rate derivative activities. As of March 31, 2017, the Company was party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.81 percent on a notional amount of $100 million on December 15, 2017.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of March 31, 2017 and December 31, 2016, 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

March 31, 2017

(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 March 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	$	75	$	(8	)	$	67
Interest rate derivatives	Derivatives - current	$	6	$	—		6
Commodity price derivatives	Derivatives - noncurrent	$	9	$	—		9
							$	82
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	17	$	(8	)	$	9
Commodity price derivatives	Derivatives - noncurrent	$	2	$	—		2
							$	11



Fair Value of Derivative Instruments as of December 31, 2016
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	$	33	$	(25	)	$	8
Interest rate derivatives	Derivatives - current	$	6	$	—		6
							$	14
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	102	$	(25	)	$	77
Commodity price derivatives	Derivatives - noncurrent	$	7	$	—		7
							$	84

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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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

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	Location of Gain / (Loss) Recognized in	Three Months Ended March 31,
Hedging Instruments	Earnings on Derivatives	2017		2016
		(in millions)
Commodity price derivatives	Derivative gains, net	$	151	$	45
Interest rate derivatives	Derivative gains, net	—		(2		)
Total		$	151	$	43

NOTE F. 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 months ended March 31, 2017:



	Three Months Ended March 31, 2017
	(in millions)
Beginning capitalized exploratory well costs	$	323
Additions to exploratory well costs pending the determination of proved reserves	406
Reclassification due to determination of proved reserves	(287		)
Exploratory well costs charged to exploration and abandonment expense	(10		)
Ending capitalized exploratory well costs	$	432

The following table provides an aging as of March 31, 2017 and December 31, 2016 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:



	March 31, 2017		December 31, 2016
	(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	411	$	318
More than one year	21		5
	$	432	$	323
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year	12		3

The 12 wells that were suspended for a period greater than one year as of March 31, 2017 are in the Eagle Ford Shale area. The Company expects to complete five of these wells in 2017 and the remaining seven wells in 2018.

NOTE G. 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, issuance discounts and net deferred fair value hedge losses. 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 March 31, 2017, the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

Senior notes. The Company's 6.65% senior notes (the "6.65% Senior Notes") matured and were repaid in March 2017. The Company funded the $485 million repayment of the 6.65% Senior Notes with cash on hand.

NOTE H. Incentive Plans

Stock-based compensation

For the three months ended March 31, 2017, the Company recorded $30 million of stock-based compensation expense for all plans, as compared to $25 million for the same period in 2016. As of March 31, 2017, there was $164 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $42 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 March 31, 2017 and December 31, 2016, accounts payable – due to affiliates included $5 million and $22 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the three months ended March 31, 2017 for each type of share-based incentive award issued by Pioneer:



	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options
Outstanding as of December 31, 2016	1,077,227		290,552		178,556	159,378
Awards granted	300,350		114,287		59,044	—
Awards forfeited	(4,740	)	(1,480	)	—	—
Awards vested	(432,316	)	(128,618	)	—	—
Outstanding as of March 31, 2017	940,521		274,741		237,600	159,378

NOTE I. 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 months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017			2016
	(in millions)
Beginning asset retirement obligations	$	297		$	285
New wells placed on production	1			—
Liabilities settled	(6		)	(5		)
Accretion of discount	5			5
Ending asset retirement obligations	$	297		$	285

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 both March 31, 2017 and December 31, 2016, the current portion of the Company's asset retirement obligations was $39 million.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

NOTE J. Commitments and Contingencies

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

NOTE K. Interest and Other Income

The following table provides the components of the Company's interest and other income for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017		2016
	(in millions)
Interest income	$	6	$	4
Deferred compensation plan income	2		2
Other income	5		2
Total interest and other income	$	13	$	8

NOTE L. Other Expense

The following table provides the components of the Company's other expense for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017		2016
	(in millions)
Transportation commitment charges (a)	$	40	$	24
Loss from vertical integration services (b)	5		13
Idle drilling and well service equipment charges (c)	—		36
Other	15		14
Total other expense	$	60	$	87

____________________


(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 months ended March 31, 2017, these vertical integration net margins included $19 million of revenues and $24 million of costs and expenses. For the same period in 2016, these vertical integration net margins included $69 million of revenues and $82 million of costs and expenses.


(c)	Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations and charges to terminate rig contracts that were not required to meet planned drilling activities.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2017

(Unaudited)

NOTE M. Income Taxes

The Company's income tax benefit consisted of the following for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017		2016
	(in millions)
Deferred tax benefit	$	31	$	141

For the three months ended March 31, 2017, the Company's effective tax rate, excluding income attributable to noncontrolling interests, was 42 percent, as compared to an effective rate of 35 percent for the same respective period in 2016. The Company's effective tax rate for the three months ended March 31, 2017 differs from the U.S. statutory rate 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 March 31, 2017 and December 31, 2016, the Company had unrecognized tax benefits of $115 million and $112 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 Company expects to resolve the uncertainties associated with the unrecognized tax benefit by December 2018.

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 2011. As of March 31, 2017, 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 N. Net Loss Per Share

Basic and diluted net loss attributable to common stockholders were $42 million and $267 million for the three months ended March 31, 2017 and 2016, respectively.

Basic and diluted weighted average common shares outstanding were 170 million for the three months ended March 31, 2017 and 162 million for the same period in 2016.

NOTE O. Subsequent Events

Permian Basin Divestiture. In April 2017, the Company completed the sale, effective January 1, 2017, 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 $266 million, before normal closing adjustments. Associated with the sale, the Company expects to record a pretax gain ranging from $215 million to $245 million.

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PIONEER NATURAL RESOURCES COMPANY

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 first quarter of 2017 included the following highlights:


•	Net loss attributable to common stockholders for the first quarter of 2017 was $42 million ($0.25 per diluted share), as compared to a net loss of $267 million ($1.65 per diluted share) for the first quarter of 2016. The primary components of the decrease in net loss attributable to common stockholders include:


•	a $400 million increase in oil and gas revenues as a result of a 78 percent increase in average realized commodity prices per BOE and a 12 percent increase in sales volumes;


•	a $108 million increase in net derivative gains, primarily as a result of changes in forward commodity prices and the Company's portfolio of derivatives;


•	a $27 million decrease in other expense, primarily related to a decrease in idle drilling and well service equipment charges, partially offset by an increase in unused firm transportation costs;


•	a $26 million decrease in exploration and abandonment expense, primarily due to the 2016 write-off of the Company's overriding royalty interest in the Nuna prospect in Alaska; and


•	a $16 million decrease in DD&A expense, primarily attributable to commodity price increases and the Company's cost reduction initiatives, both of which had the effect of adding proved reserves by lengthening the economic lives of the Company's producing wells; offset by

a $253 million increase in impairment charges, principally related to the impairment recorded in 2017 to reduce the carrying value of the Company's Raton field; and


•	a $110 million reduction in the Company's income tax benefit as a result of the improvement in earnings during the three months ended March 31, 2017 as compared to the three months ended March 31, 2016.


•	During the first quarter of 2017, average daily sales volumes increased by 12 percent to 248,881 BOEPD, as compared to 221,809 BOEPD during the first quarter of 2016. The increase in first quarter 2017 average daily sales volumes, as compared to the first quarter of 2016, is primarily due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.


•	Average oil, NGL and gas prices increased during the first quarter of 2017 to $49.05 per Bbl, $19.33 per Bbl and $2.79 per Mcf, respectively, as compared to $28.09 per Bbl, $10.33 per Bbl and $1.79 per Mcf, respectively, in the first quarter of 2016.

•

Net cash provided by operating activities increased to $364 million for the three months ended March 31, 2017, as compared to $110 million for the three months ended March 31, 2016. The $254 million increase in net cash provided by operating activities is primarily due to increases in the Company's oil and gas revenues for the three months ended March 31, 2017 as a result of increases in commodity prices and sales volumes, partially offset by a $208 million reduction in cash provided by commodity derivatives during the three months ended March 31, 2017 as compared to the same period in 2016.


•	As of March 31, 2017, the Company's net debt to book capitalization was three percent, as compared to two percent at December 31, 2016.

Second Quarter 2017 Outlook

Based on current estimates, the Company expects the following operating and financial results for the quarter ending June 30, 2017:

Production is forecasted to average 254,000 to 259,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $7.75 to $9.75 per BOE based on current NYMEX strip commodity prices. DD&A expense is expected to average $15.00 to $17.00 per BOE.

Total exploration and abandonment expense is expected to be $20 million to $30 million. General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $43 million to $48 million, and other expense is expected to be $60 million to $70 million. Other expense is expected to include (i) $40 million to $45 million of charges associated with excess firm gathering and transportation commitments, (ii) $5 million to $10 million of losses (principally noncash) associated

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with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company and (iii) other miscellaneous charges. 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 35 percent to 40 percent assuming current capital spending plans and no significant mark-to-market changes in the Company's derivative position. 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 three months ended March 31, 2017:



	Oil (Bbls)	NGLs (Bbls)	Gas (Mcf)	Total (BOE)
Permian Basin	134,521	36,529	178,587	200,814
South Texas - Eagle Ford Shale	7,871	6,799	45,070	22,182
Raton Basin	—	—	89,959	14,993
West Panhandle	1,997	3,344	5,390	6,240
South Texas - Other	1,226	154	19,565	4,641
Other	4	2	31	11
Total	145,619	46,828	338,602	248,881

The Company's liquids production increased to 77 percent of total production on a BOE basis for the three months ended March 31, 2017, as compared to 73 percent for the same period last year.

The following table summarizes by geographic area the Company's finding and development costs incurred during the three months ended March 31, 2017:



	Acquisition Costs				Exploration		Development
	Proved		Unproved		Costs		Costs		Total
	(in millions)
Permian Basin	$	2	$	8	$	418	$	111	$	539
South Texas - Eagle Ford Shale	—		—		6		3		9
West Panhandle	—		—		—		2		2
Other	—		—		1		—		1
Total	$	2	$	8	$	425	$	116	$	551

The following table summarizes the Company's development and exploration/extension drilling activities for the three months ended March 31, 2017:



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Ending Wells in Progress
Permian Basin	8	5	3	10
South Texas - Eagle Ford Shale	4	—	—	4
Total	12	5	3	14



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	119	62	39	1	141
South Texas - Eagle Ford Shale	14	3	—	1	16
Total	133	65	39	2	157

Permian Basin area. In the first quarter of 2017, the Company increased its rig count in the Spraberry/Wolfcamp area from 17 rigs at year-end 2016 to 18 rigs at March 31, 2017. During 2017, the Company expects to place on production approximately 260 horizontal wells (220 horizontal wells in the northern portion of the play and 40 horizontal wells in the southern portion of

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the play). Approximately 55 percent of the horizontal wells are planned to be drilled in the Wolfcamp B interval, 30 percent in the Wolfcamp A interval and 15 percent in the Lower Spraberry Shale interval. The Company also plans to drill a small number of wells to appraise the shallower Clearfork formation, the Jo Mill interval within the Spraberry formation and the Wolfcamp D interval in the Wolfcamp formation during 2017. The Company expects to spend $2.4 billion of capital in the Spraberry/Wolfcamp field during 2017, including $1.9 billion of horizontal drilling and completion capital, $265 million for tank battery and disposal facilities, $115 million for gas processing facilities and $110 million for land, science and other costs. During the first quarter of 2017, the Company successfully completed 39 horizontal wells in the northern portion of the play and 3 horizontal wells in the southern portion of the play. In the northern portion of the play, approximately 40 percent of wells placed on production were Wolfcamp B interval wells, and the remaining 60 percent were split predominantly between Wolfcamp A interval wells and Lower Spraberry Shale wells. In the southern portion of the play, all wells placed on production were Wolfcamp B interval wells.

The Company continues to utilize its integrated services to control well costs and operating costs in addition to supporting the execution of its drilling and production activities in the Spraberry/Wolfcamp field. During the first quarter of 2017, the Company utilized five 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. In addition, Premier Silica (the Company's wholly-owned sand mining subsidiary) is supplying high-quality and logistically advantaged brown sand for proppant, which is being used to fracture stimulate horizontal wells in the Spraberry and Wolfcamp Shale intervals.

The Company has been and continues to pursue initiatives to improve drilling and completion efficiencies and reduce costs. The most significant drilling and completion cost reductions to date have been for casing, tubing, materials for drilling and fracture stimulation, fuel charges, labor and transportation, rental equipment and well services, while efficiency gains include reducing the time needed to drill and complete the wells and optimizing completions in the Spraberry and Wolfcamp Shale intervals.

The Company's long-term growth plan continues to focus on optimizing the development of the field and addressing the future requirements for water sourcing and disposal, field infrastructure, gas processing, sand, pipeline takeaway capacity for its products, oilfield services, tubulars, electricity, buildings, roads and labor.

The Company is constructing a field-wide water distribution system to reduce the cost of water for drilling and completion activities and to ensure that adequate supplies of water are available to support the Company's long-term growth plan for the Spraberry/Wolfcamp field. The 2017 capital program includes $160 million for expansion of the mainline system, subsystems and frac ponds to efficiently deliver water to Pioneer's drilling locations. The Company signed an agreement with the city of Midland to upgrade the city's wastewater treatment plant in return for a dedicated long-term supply of water from the plant. The 2017 program includes $10 million of engineering capital to begin work on this upgrade. Pioneer expects to spend approximately $110 million over the 2017 through 2019 period for the Midland plant upgrade. In return, the Company will receive approximately two billion barrels of low-cost, non-potable water over a 28-year contract period (up to 240 thousand barrels per day) to support its completion operations. The water contract is subject to State of Texas legislative validation during the second quarter of 2017.

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. The 2017 capital program includes $30 million to complete an optimization project for the Company's existing sand mining facilities. This project is expected to improve yields and reduce the Company's overall cost of sand supplies. The 2017 capital program also includes $45 million for upgrades and maintenance to the six Company-owned pressure pumping fleets that the Company plans to operate during 2017.

Eagle Ford Shale area. In the first quarter of 2017, the Company increased its rig count in the Eagle Ford Shale area from zero rigs at year-end 2016 to two rigs at March 31, 2017. During 2017, the Company expects to spend $95 million of capital to drill and complete 11 new Eagle Ford Shale wells and to complete nine wells that were drilled but not completed in 2016. The objective of this drilling program is to test longer laterals with higher intensity completions.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $809 million for the three months ended March 31, 2017, as compared to $409 million for the same period in 2016.

The increase in oil and gas revenues during the three months ended March 31, 2017, as compared to the same period in 2016, is primarily due to increases of 75 percent, 87 percent and 56 percent in oil, NGL and gas prices, respectively, and 19 percent increases in both daily oil and NGL sales volumes, partially offset by a six percent decline in daily gas sales volumes.

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The following table provides average daily sales volumes for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017	2016
Oil (Bbls)	145,619	122,802
NGLs (Bbls)	46,828	39,232
Gas (Mcf)	338,602	358,651
Total (BOEs)	248,881	221,809

Average daily BOE sales volumes increased by 12 percent for the three months ended March 31, 2017, as compared to the same period in 2016, principally due to the Company's successful Spraberry/Wolfcamp horizontal drilling program. NGL production volumes are lower for the three months ended March 31, 2017 and 2016 by approximately 5,000 Bbls per day for each respective period due to voluntary reductions in recoveries of ethane as a result of it having a higher value if sold as part of the gas stream.

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 months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017		2016
Oil (per Bbl)	$	49.05	$	28.09
NGL (per Bbl)	$	19.33	$	10.33
Gas (per Mcf)	$	2.79	$	1.79
Total (per BOE)	$	36.14	$	20.28

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 a Gulf Coast market price 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 the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. The net effect of third party purchases and sales of oil and gas for the three months ended March 31, 2017 was a loss of $19 million, as compared to a loss of $20 million for the same period in 2016. Firm transportation payments on excess pipeline capacity commitments are included in other expense in the accompanying consolidated statements of operations. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information on transportation commitment charges.

Interest and other income. Interest and other income for the three months ended March 31, 2017 was $13 million, as compared to $8 million for the same period in 2016. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Derivative gains, 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 months ended March 31, 2017, the Company recorded $151 million of net derivative gains on commodity price and interest rate derivatives, of which $10 million represented net cash receipts. During the three months ended March 31, 2016, the Company recorded $43 million of net derivative gains on commodity price and interest rate derivatives, of which $218 million represented net cash receipts.

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The following tables detail the net cash receipts on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf) for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31, 2017
	Net cash receipts			Price impact
	(in millions)
Oil derivative receipts	$	11		$	0.84		per Bbl
NGL derivative receipts	—			$	0.04		per Bbl
Gas derivative receipts	(1		)	$	(0.03	)	per Mcf
Total net commodity derivative receipts	$	10



	Three Months Ended March 31, 2016
	Net cash receipts		Price impact
	(in millions)
Oil derivative receipts	$	194	$	17.26	per Bbl
NGL derivative receipts	4		$	1.09	per Bbl
Gas derivative receipts	20		$	0.61	per Mcf
Total net commodity derivative receipts	$	218

The Company's open derivative contracts are subject to continuing market risk. See Note E 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 net gains on the disposition of assets of $11 million for the three months ended March 31, 2017, as compared to $2 million for the same period in 2016.

Oil and gas production costs. The Company recognized oil and gas production costs of $141 million during the three months ended March 31, 2017, as compared to $156 million during the same period in 2016. Lease operating expenses and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from gathering and processing of third-party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the three months ended March 31, 2017 decreased by 18 percent, as compared to the same period in 2016. The decrease in lease operating expenses per BOE during the three months ended March 31, 2017, as compared to the same period in 2016, was 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 and cost reduction initiatives. The decrease in third-party transportation costs per BOE during the three months ended March 31, 2017, as compared to the same period in 2016, was due to a lower proportion of the Company's production being subject to transportation costs (principally due to the decline in Eagle Ford Shale production). The change in net natural gas plant charges per BOE during the three months ended March 31, 2017, as compared to the same period in 2016, is primarily reflective of increased earnings on third-party volumes that are processed in Company-owned facilities due to higher NGL and gas prices. The increase in workover costs per BOE during the three months ended March 31, 2017, as compared to the same period in 2016, was primarily due to an increase in workover activity due to the improvement in commodity prices.

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The following table provides the components of the Company's oil and gas production costs per BOE for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017			2016
Lease operating expenses	$	4.99		$	5.45
Third-party transportation charges	1.01			1.76
Net natural gas plant (income) charges	(0.28		)	0.22
Workover costs	0.59			0.28
Total production costs	$	6.31		$	7.71

Production and ad valorem taxes. The Company's production and ad valorem taxes were $47 million during the three months ended March 31, 2017, as compared to $29 million for the same period in 2016. In general, production 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 following table provides the Company's production and ad valorem taxes per BOE for the three months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017		2016
Production taxes	$	1.59	$	0.80
Ad valorem taxes	0.52		0.66
Total production and ad valorem taxes	$	2.11	$	1.46

Depletion, depreciation and amortization expense. The Company's DD&A expense was $337 million ($15.04 per BOE) for the three months ended March 31, 2017, as compared to $353 million ($17.49 per BOE) during the same period in 2016. The change in per BOE DD&A expense during the three months ended March 31, 2017, as compared to the same period in 2016, is primarily due to a decrease in depletion expense per BOE on oil and gas properties.

Depletion expense on oil and gas properties was $14.51 per BOE during the three months ended March 31, 2017, as compared to $16.94 per BOE during the same period in 2016. The change in per BOE depletion expense during the three months ended March 31, 2017, as compared to the same period in 2016, is primarily due to (i) commodity 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 and (ii) additions to proved reserves attributable to the Company's successful Spraberry/Wolfcamp horizontal drilling program.

Impairment of oil and gas properties. 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. To the extent such assessments indicate a reduction of the estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their fair value.

The cash flow model the Company uses to assess proved properties for impairment includes numerous assumptions. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) Management's Price Outlook and (iv) increases or decreases in production costs and capital costs associated with those reserves. All inputs to the cash flow model are evaluated at each measurement date.

As a result of the Company's proved property impairment assessments, the Company recognized noncash impairment charges to reduce the carrying values of (i) the Raton field during the three months ended March 31, 2017 ($285 million impairment charge) and (ii) its West Panhandle field during the three months ended March 31, 2016 ($32 million impairment charge) to their estimated fair values. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's proved oil and gas property impairment charges.

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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 months ended March 31, 2017 and 2016:



	Three Months Ended March 31,
	2017		2016
	(in millions)
Geological and geophysical	$	23	$	19
Exploratory well costs	10		1
Leasehold abandonments and other	—		39
	$	33	$	59

The geological and geophysical expenses for the three months ended March 31, 2017 and 2016 were primarily related to geological and geophysical personnel costs. During the three months ended March 31, 2016, the Company incurred leasehold abandonments primarily related to the abandonment of unproved properties in the Permian Basin and unproved acreage in Alaska in which the Company held an overriding royalty interest.

During the three months ended March 31, 2017, the Company drilled and evaluated 41 exploration/extension wells, 39 of which were successfully completed as discoveries. During the same period in 2016, the Company drilled and evaluated 53 exploration/extension wells, all of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three months ended March 31, 2017 was $84 million ($3.74 per BOE), as compared to $74 million ($3.66 per BOE) for the same period in 2016. The increase in general and administrative expense per BOE during the three months ended March 31, 2017, as compared to the same period in 2016, was primarily due to increases in employee-related compensation and benefit costs.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $5 million for both the three months ended March 31, 2017 and 2016, respectively. See Note I 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 $46 million and $55 million for the three months ended March 31, 2017 and 2016, respectively. The decrease in interest expense during the three months ended March 31, 2017, as compared to the same respective period in 2016, was primarily due to the repayment of the Company's 5.875% senior notes, which matured in July 2016. The weighted average interest rates on the Company's indebtedness for the three months ended March 31, 2017, including the effects of capitalized interest, was 5.8 percent, as compared to 6.2 percent for the same period in 2016.

Other expense. Other expense was $60 million for the three months ended March 31, 2017, as compared to $87 million during the same period in 2016. The decrease in other expense for the three months ended March 31, 2017, as compared to the same period in 2016, was primarily due to a decrease of $36 million in idle drilling and well service equipment charges, partially offset by an increase of $16 million in unused firm transportation costs.

The Company expects to continue to incur charges associated with excess firm gathering and transportation commitments and vertical integration operations until commodity prices improve, allowing the Company to increase its drilling activities, or, in the case of gathering and transportation commitments, the contractual obligations expire. Based on current drilling plans for 2017, the Company does not expect to incur any idle drilling rig charges. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax benefit. The Company recognized an income tax benefit of $31 million for the three months ended March 31, 2017, as compared to an income tax benefit of $141 million for the same period in 2016. The Company's effective tax rate for the three months ended March 31, 2017 was 42 percent, as compared to 35 percent for the three months ended March 31, 2016. The Company's effective tax rate for the three months ended March 31, 2017 differs from the U.S. statutory rate 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 March 31, 2017 and December 31, 2016, the Company had unrecognized tax benefits of $115 million and $112 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

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in the period it is recognized. The Company expects to resolve the uncertainties associated with the unrecognized tax benefit by December 2018. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payment of contractual obligations, including debt maturities, dividends and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, cash and cash equivalents on hand, sales of short-term and long-term investments, proceeds from divestitures of nonstrategic assets or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2017 is $2.8 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and information technology system upgrades), consisting of $2.5 billion for drilling operations and $275 million for water infrastructure, vertical integration and field facilities. The Company's capital expenditures during the three months ended March 31, 2017 were $611 million, consisting of $524 million for drilling operations (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs) and $87 million for water infrastructure, vertical integration, system upgrades and other plant and equipment additions. Based on results for the three months ended March 31, 2017 and Management's Price Outlook, the Company expects its net cash flows from operating activities, cash and cash equivalents on hand, sales of short-term and long-term investments, proceeds from divestitures of nonstrategic assets and, if necessary, availability under the Credit Facility to be sufficient to fund its planned capital expenditures, acquisitions and contractual obligations, including debt maturities.

Investing activities. Investing activities used $298 million of cash during the three months ended March 31, 2017, as compared to $1.5 billion of cash used in investing activities during the three months ended March 31, 2016. The decrease in cash used in investing activities for the three months ended March 31, 2017, as compared to the three months ended March 31, 2016, is primarily due to net proceeds from the maturity of investments (commercial paper, corporate bonds and time deposits) of $143 million during the three months ended 2017, as compared to investment purchases of $914 million during the three months ended March 31, 2016. During the three months ended March 31, 2017, the Company's expenditures for investing activities were primarily funded by net cash provided by operating activities and cash on hand.

Dividends/distributions. During March of 2017 and 2016, the Board declared semiannual dividends of $0.04 per common share. 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, including off-balance sheet 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, firm transportation and fractionation commitments, minimum annual gathering, processing and transportation commitments and other liabilities (including postretirement benefit obligations).

From time-to-time, the Company enters into arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of March 31, 2017, 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 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 first quarter of 2017 other than the repayment of the Company's 6.65% Senior Notes in March 2017.

The Company's commodity and interest rate derivative contracts are periodically measured and recorded at fair value and continue to be subject to market or credit risk. As of March 31, 2017, these contracts represented net assets of $71 million. The ultimate liquidation value of the Company's commodity and interest rate derivatives will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives' fair values as of March 31, 2017. See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3.

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Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Company's derivative instruments and market risk.

Capital resources. The Company's primary capital resources are cash and cash equivalents, short-term and long-term investments, net cash provided by operating activities, proceeds from divestitures and proceeds from financing activities (principally borrowings under the Company's Credit Facility or issuances of debt or equity securities). If internal cash flows do not meet the Company's expectations, the Company may reduce its level of capital expenditures, and/or fund a portion of its capital expenditures (i) using cash on hand, (ii) through sales of short-term and long-term investments, (iii) with borrowings under the Company's Credit Facility, (iv) through issuances of debt or equity securities or (v) through other sources, such as sales of nonstrategic assets.

Operating activities. Net cash provided by operating activities during the three months ended March 31, 2017 was $364 million, as compared to $110 million during the same period in 2016. The increase in net cash provided by operating activities for the three months ended March 31, 2017, as compared to the three months ended March 31, 2016, is primarily due to increases in the Company's oil and gas revenues for the three months ended March 31, 2017 as a result of increases in commodity prices and sales volumes, partially offset by a $208 million reduction in cash provided by commodity derivatives during the three months ended March 31, 2017, as compared to the same period in 2016.

Financing activities. Net cash used by financing activities during the three months ended March 31, 2017 was $521 million, as compared to net cash provided by financing activities of $1.6 billion during the same period in 2016. The decrease in net cash provided by financing activities during the three months ended March 31, 2017, as compared to the same period in 2016, is primarily the result of the Company's issuance of 13.8 million shares of common stock during the first quarter of 2016 for cash proceeds of $1.6 billion and the principal repayment of $485 million attributable to the Company's 6.65% Senior Notes that matured in March 2017.

As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock 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 Board.

Liquidity. The Company's principal sources of short-term liquidity are cash and cash equivalents, sales of short-term and long-term investments and unused borrowing capacity under its Credit Facility. As of March 31, 2017, the Company had no outstanding borrowings under its Credit Facility, leaving $1.5 billion of unused borrowing capacity. The Company was in compliance with all of its debt covenants as of March 31, 2017. The Company also had cash on hand of $663 million, short-term investments of $1.5 billion and long-term investments of $168 million as of March 31, 2017. If internal cash flows do not meet the Company's expectations, the Company may fund a portion of its capital expenditures using cash on hand, sales of short-term and long-term investments, availability under its Credit Facility, issuances of debt or equity securities or other sources, such as sales of nonstrategic assets and/or reduce its level of capital expenditures or reduce dividend payments. The Company cannot provide any assurance that needed short- term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that the combination of internal operating cash flows, cash and cash equivalents on hand, sales of short-term and long-term investments, proceeds from divestitures of nonstrategic assets and, if necessary, available capacity under the Company's Credit Facility will be adequate for the remainder of 2017 to fund planned capital expenditures, acquisitions, dividend payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

Debt ratings. The Company is rated as mid-investment grade by three credit rating agencies. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factors in determining the Company's ratings including: (i) production growth opportunities, (ii) liquidity, (iii) debt levels, (iv) asset composition and (v) proved reserve mix. A reduction in the Company's debt ratings could increase the interest rates that the Company incurs on Credit Facility borrowings and could negatively impact the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Book capitalization and current ratio. The Company's net book capitalization at March 31, 2017 was $10.7 billion, consisting of $663 million of cash and cash equivalents, short-term and long-term investments of $1.7 billion, debt of $2.7 billion and equity of $10.3 billion. The Company's net debt to net book capitalization increased to three percent at March 31, 2017 from two percent at December 31, 2016. The Company's ratio of current assets to current liabilities increased to 3.09 to 1.00 at March 31, 2017, as compared to 2.11 to 1.00 at December 31, 2016, primarily due to the reclassification of investments with maturities of less than one year to short-term and repayment of the Company's 6.65% Senior Notes that matured in March 2017.

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New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B 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, 2016. 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, 2016.

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 following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during the three months ending March 31, 2017:



	Derivative Contract Net Assets
	Commodities			Interest Rates		Total
	(in millions)
Fair value of contracts outstanding as of December 31, 2016	$	(76	)	$	6	$	(70	)
Changes in contract fair value	151			—		151
Contract maturity receipts	(10		)	—		(10		)
Fair value of contracts outstanding as of March 31, 2017	$	65		$	6	$	71

Interest rate sensitivity. See Note G 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 long-term debt.

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The following table provides information about financial instruments to which the Company was a party as of March 31, 2017 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 March 31, 2017. Although the Company had no outstanding variable rate debt as of March 31, 2017, 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 May 1, 2017 is presented in the table below.



	Nine Months Ending December 31,			Year Ending December 31,																	Asset (Liability) Fair Value at March 31,
	2017			2018			2019			2020			2021			Thereafter			Total		2017
	(dollars in millions)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	450		$	—		$	450		$	500		$	1,350		$	2,750	$	(2,961	)
Weighted average fixed interest rate	5.31		%	5.11		%	5.00		%	4.42		%	4.72		%	5.49		%
Average variable interest rate	2.89		%	3.23		%	3.54		%	3.77		%
Interest Rate Swaps:
Notional debt amount (b)	$	100		$	—		$	—		$	—		$	—		$	—				$	6
Fixed rate payable (%)	1.81		%
Variable rate receivable (%) (c)	2.38		%

____________________


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


(b)	As of March 31, 2017, the Company was party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.81 percent on a notional amount of $100 million on December 15, 2017.


(c)	The variable rate receivable represents the May 1, 2017 forecasted three-month LIBOR rate for the 10-year period from December 2017 through December 2027.

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 March 31, 2017. 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 D and E 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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	2017									Year Ending December 31,				Asset (Liability) Fair Value at March 31, 2017 (a)
	Second Quarter			Third Quarter			Fourth Quarter			2018		2019		Asset (Liability) Fair Value at March 31, 2017 (a)
														(in millions)
Oil Derivatives:
Average daily notional Bbl volumes:
Collar contracts	6,000			6,000			6,000			—		—		$	4
Weighted average ceiling price per Bbl	$	70.40		$	70.40		$	70.40		$	—	$	—
Weighted average floor price per Bbl	$	50.00		$	50.00		$	50.00		$	—	$	—
Collar contracts with short puts (b)	129,000			147,000			155,000			20,000		—		$	68
Weighted average ceiling price per Bbl	$	61.19		$	62.03		$	62.12		$	65.14	$	—
Weighted average floor price per Bbl	$	48.46		$	49.81		$	49.82		$	50.00	$	—
Weighted average short put price per Bbl	$	40.45		$	41.07		$	41.02		$	40.00	$	—
Average forward NYMEX oil prices (c)	$	48.84		$	49.40		$	50.02		$	50.21	$	—
Rollfactor swap contracts (d)	20,000			20,000			20,000			—		—		$	—
Weighted average fixed price per Bbl	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	—	$	—
Average forward NYMEX rollfactor prices (c)	$	(0.40	)	$	(0.30	)	$	(0.19	)	$	—	$	—
NGL Derivatives:
Butane swap contracts (Bbl) (e):	2,000			2,000			—			—		—		$	1
Weighted average fixed price per Bbl	$	34.86		$	34.86		$	—		$	—	$	—
Butane collar contracts with short puts (Bbl) (f):	2,000			2,000			—			—		—		$	—
Weighted average ceiling price per Bbl	$	36.12		$	36.12		$	—		$	—	$	—
Weighted average floor price per Bbl	$	29.25		$	29.25		$	—		$	—	$	—
Weighted average short put price per Bbl	$	23.40		$	23.40		$	—		$	—	$	—
Average forward butane prices (c)	$	31.29		$	31.78		$	—		$	—	$	—
Ethane collar contracts (Bbl) (g)	3,000			3,000			3,000			—		—		$	—
Weighted average ceiling price per Bbl	$	11.83		$	11.83		$	11.83		$	—	$	—
Weighted average floor price per Bbl	$	8.68		$	8.68		$	8.68		$	—	$	—
Average forward ethane prices (c)	$	10.50		$	10.82		$	11.29		$	12.35	$	13.39
Ethane basis swap contracts (MMBtu) (h)	6,920			6,920			6,920			6,920		6,920		$	—
Weighted average price differential per MMBtu	$	1.60		$	1.60		$	1.60		$	1.60	$	1.60
Average forward NYMEX gas prices (c)	$	3.22		$	3.30		$	3.39		$	3.08	$	2.87
Gas Derivatives:
Average daily notional MMBtu volumes:
Collar contracts with short puts	270,000			290,000			300,000			62,329		—		$	(9	)
Weighted average ceiling price per MMBtu	$	3.56		$	3.57		$	3.60		$	3.56	$	—
Weighted average floor price per MMBtu	$	2.95		$	2.95		$	2.96		$	2.91	$	—
Weighted average short put price per MMBtu	$	2.47		$	2.47		$	2.47		$	2.37	$	—
Average forward NYMEX gas prices (c)	$	3.22		$	3.30		$	3.39		$	3.08	$	—
Basis swap contracts														$	—
Mid-Continent index swap contracts (i)	45,000			45,000			45,000			—		—
Weighted average fixed price per MMBtu	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	—	$	—
Average forward basis differential prices (j)	$	(0.42	)	$	(0.39	)	$	(0.35	)	$	—	$	—
Permian Basin index swap contracts (k)	—			—			26,522			9,863		—
Weighted average fixed price per MMBtu	$	—		$	—		$	0.30		$	0.30	$	—
Average forward basis differential prices (l)	$	—		$	—		$	0.26		$	0.29	$	—

___________________

(a)

In accordance with Financial Accounting Standards Board 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.

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PIONEER NATURAL RESOURCES COMPANY


(b)	Subsequent to March 31, 2017, the Company entered into additional oil collar contracts with short puts for 26,000 Bbl per day of 2018 production with a ceiling price of $60.49 per Bbl, a floor price of $50.19 per Bbl and a short put price of $40.00 per Bbl.

(c) The average forward NYMEX oil, oil rollfactors, ethane, butane and gas prices are based on May 1, 2017 market quotes.

(d)

Represent swaps that fix the difference between (i) each day's price per Bbl of WTI for the first nearby NYMEX month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby NYMEX month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. Subsequent to March 31, 2017, the Company paid a nominal amount to terminate its oil rollfactor swap contracts for the third quarter of 2017.


(e)	Represent swap contracts that reduce the price volatility of butane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. Subsequent to March 31, 2017, the Company terminated its butane swap contracts for cash proceeds of $1 million.


(f)	Represent collar contracts with short puts that reduce the price volatility of butane forecasted for sale by the Company at Mont Belvieu, Texas-posted price.


(g)	Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(h)	Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The basis swap contracts fix the basis differential on a 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.


(i)	Represent swap contracts that fix the basis differentials between the index prices at which the Company sells its Mid-Continent gas and the NYMEX HH index price used in collar contracts with short puts.


(j)	The average forward basis differential prices are based on May 1, 2017 market quotes for basis differentials between the relevant index prices and the NYMEX-quoted forward prices.


(k)	Represent swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California.


(l)	The average forward basis differential prices are based on May 1, 2017 market quotes for basis differentials between Permian Basin index prices and southern California index prices.

Marketing and basis differential derivatives. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of March 31, 2017, the Company did not have any marketing derivatives outstanding.

Diesel derivatives. Periodically, the Company enters into diesel derivative swap contracts to mitigate fuel price risk. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel drilling rigs and its fracture stimulation fleet equipment. As of March 31, 2017, the Company was party to diesel derivative swap contracts for 1,000 Bbls per day for the remainder of 2017 at an average per Bbl fixed price of $62.98. As of March 31, 2017, these positions had an asset fair value of $1 million. In early April 2017, the Company terminated its diesel derivative swap contracts that were held at March 31, 2017 for cash proceeds of $1 million. In late April 2017, the Company entered into diesel swap contracts for 1,000 Bbls per day for the remainder of 2017 at an average per Bbl fixed price of $63.00. Based on May 1, 2017 market quotes, the respective average forward diesel price was $61.94 per Bbl.

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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. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2017 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

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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.

The Company has been advised by the U.S. Environmental Protection Agency ("EPA") that the agency is considering an enforcement action against the Company seeking monetary sanctions for alleged failures to prevent emissions occurring at the Company's Fain gas plant in the West Panhandle region of Texas on five separate occasions. The Company has asserted defenses to the EPA's allegations and is in discussions with the EPA regarding these matters. Although the Company cannot predict the outcome of these discussions with any certainty, the Company believes such monetary sanctions will not exceed $45,000 for any single event, but could exceed $100,000 in the aggregate.

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, 2016, 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.

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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 March 31, 2017:



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 Amount of Shares that May Yet Be Purchased under Plans or Programs
January 2017	42,640	$	180.07	—
February 2017	144,969	$	194.77	—
March 2017	110	$	191.42	—
Total	187,719	$	191.43	—	$	—

____________________


(a)	Consists of shares purchased from employees in order for the employee to satisfy tax withholding payments related to share-based awards that vested during the period.

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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Item 6. Exhibits

Exhibits



Exhibit Number		Description
10.1	—	Amended and Restated Severance Agreement dated February 27, 2017, between the Company and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 3, 2017).

10.2	(a) —	Form of Performance Unit Award Agreement between the Company and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan.

10.3	(a) —	Form of Restricted Stock Unit Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan.

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

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: May 3, 2017	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy,
		Executive Vice President and Chief Financial Officer

Date: May 3, 2017	By:	/s/ MARGARET M. MONTEMAYOR
		Margaret M. Montemayor,
		Vice President and Chief Accounting Officer

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PIONEER NATURAL RESOURCES COMPANY

Exhibit Index



Exhibit Number		Description
10.1	—	Amended and Restated Severance Agreement dated February 27, 2017, between the Company and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 3, 2017).

10.2	(a) —	Form of Performance Unit Award Agreement between the Company and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan.

10.3	(a) —	Form of Restricted Stock Unit Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan.

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

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.