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 September 30, 2016

or

¨ 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 or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting 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	¨

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 October 28, 2016169,720,677

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 September 30, 2016 and December 31, 2015	5
	Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015	7
	Consolidated Statement of Equity for the nine months ended September 30, 2016	8
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	9
	Notes to Consolidated Financial Statements	10
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 4.	Controls and Procedures	39
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 4.	Mine Safety Disclosures	41
Item 6.	Exhibits	42
Signatures		43
Exhibit Index		44

2

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, derivative contracts and the 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 and other Quarterly Reports on Form 10-Q and other filings with the United States Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Part I, Item 1. Business — Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors," "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Company's Annual Report on Form 10-K for the year ended December 31, 2015 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.

3

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.

4

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)

	September 30, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	891		$	1,391
Short-term investments	1,733			—
Accounts receivable:
Trade, net	447			384
Due from affiliates	—			1
Income taxes receivable	26			43
Inventories	159			155
Prepaid expenses	21			17
Notes receivable	—			498
Derivatives	172			694
Other	5			11
Total current assets	3,454			3,194
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	18,049			16,631
Unproved properties	486			169
Accumulated depletion, depreciation and amortization	(7,866		)	(6,778		)
Total property, plant and equipment	10,669			10,022
Long-term investments	319			—
Goodwill	272			272
Other property and equipment, net	1,514			1,523
Derivatives	8			64
Other assets, net	89			79
	$	16,325		$	15,154

The financial information included as of September 30, 2016 has been prepared by management

without audit by independent registered public accountants.

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

5

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in millions, except share data)

	September 30, 2016			December 31, 2015
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	685		$	798
Due to affiliates	98			85
Interest payable	39			65
Income taxes payable	—			2
Current portion of long-term debt	485			448
Derivatives	7			—
Other	63			64
Total current liabilities	1,377			1,462
Long-term debt	2,726			3,207
Derivatives	20			1
Deferred income taxes	1,437			1,776
Other liabilities	334			333
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 173,212,412 and 152,775,920 shares issued as of September 30, 2016 and December 31, 2015, respectively	2			2
Additional paid-in capital	8,867			6,267
Treasury stock at cost: 3,495,288 and 3,396,220 shares as of September 30, 2016 and December 31, 2015, respectively	(217		)	(199		)
Retained earnings	1,772			2,298
Total equity attributable to common stockholders	10,424			8,368
Noncontrolling interests in consolidated subsidiaries	7			7
Total equity	10,431			8,375
Commitments and contingencies
	$	16,325		$	15,154

The financial information included as of September 30, 2016 has been prepared by management

without audit by independent registered public accountants.

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

6

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Revenues and other income:
Oil and gas	$	643		$	557		$	1,665		$	1,670
Sales of purchased oil and gas	444			326			1,062			665
Interest and other	7			2			21			16
Derivative gains (losses), net	91			573			(95		)	617
Gain on disposition of assets, net	1			779			4			782
	1,186			2,237			2,657			3,750
Costs and expenses:
Oil and gas production	141			189			438			532
Production and ad valorem taxes	32			36			97			112
Depletion, depreciation and amortization	386			364			1,123			1,003
Purchased oil and gas	458			339			1,113			684
Impairment of oil and gas properties	—			72			32			210
Exploration and abandonments	19			25			96			79
General and administrative	82			81			235			246
Accretion of discount on asset retirement obligations	5			3			14			9
Interest	50			46			161			138
Other	69			79			223			186
	1,242			1,234			3,532			3,199
Income (loss) from continuing operations before income taxes	(56		)	1,003			(875		)	551
Income tax benefit (provision)	78			(355		)	362			(195		)
Income (loss) from continuing operations	22			648			(513		)	356
Loss from discontinued operations, net of tax	—			(2		)	—			(6		)
Net income (loss) attributable to common stockholders	$	22		$	646		$	(513	)	$	350
Basic earnings per share attributable to common stockholders:
Income (loss) from continuing operations	$	0.13		$	4.29		$	(3.10	)	$	2.36
Loss from discontinued operations	—			(0.01		)	—			(0.04		)
Net income (loss)	$	0.13		$	4.28		$	(3.10	)	$	2.32
Diluted earnings per share attributable to common stockholders:
Income (loss) from continuing operations	$	0.13		$	4.28		$	(3.10	)	$	2.36
Loss from discontinued operations	—			(0.01		)	—			(0.04		)
Net income (loss)	$	0.13		$	4.27		$	(3.10	)	$	2.32
Weighted average shares outstanding:
Basic	170			149			165			149
Diluted	170			150			165			149
Dividends declared per share	$	0.04		$	0.04		$	0.08		$	0.08

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.

7

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, 2015	149,380		$	2	$	6,267		$	(199	)	$	2,298		$	7	$	8,375
Issuance of common stock	19,838		—		2,534			—			—			—		2,534
Dividends declared ($0.08 per share)	—		—		—			—			(13		)	—		(13		)
Exercise of long-term incentive stock options and employee stock purchases	98		—		1			6			—			—		7
Purchases of treasury stock	(197	)	—		—			(24		)	—			—		(24		)
Tax provision related to stock-based compensation	—		—		(1		)	—			—			—		(1		)
Compensation costs:
Vested compensation awards, net	598		—		—			—			—			—		—
Compensation costs included in net loss	—		—		66			—			—			—		66
Net loss	—		—		—			—			(513		)	—		(513		)
Balance as of September 30, 2016	169,717		$	2	$	8,867		$	(217	)	$	1,772		$	7	$	10,431

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.

8

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(Unaudited)

	Nine Months Ended September 30,
	2016			2015
Cash flows from operating activities:
Net income (loss)	$	(513	)	$	350
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	1,123			1,003
Impairment of oil and gas properties	32			210
Impairment of inventory and other property and equipment	6			21
Exploration expenses, including dry holes	41			22
Deferred income taxes	(340		)	146
Gain on disposition of assets, net	(4		)	(782		)
Accretion of discount on asset retirement obligations	14			9
Discontinued operations	—			(4		)
Interest expense	11			14
Derivative related activity	628			(22		)
Amortization of stock-based compensation	66			70
Other	51			13
Change in operating assets and liabilities:
Accounts receivable	(64		)	26
Income taxes receivable	17			23
Inventories	(7		)	(29		)
Prepaid expenses	(4		)	(3		)
Derivatives	(24		)	—
Other current assets	1			(6		)
Accounts payable	(8		)	(266		)
Interest payable	(26		)	(4		)
Income taxes payable	(2		)	26
Other current liabilities	(38		)	(28		)
Net cash provided by operating activities	960			789
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	503			556
Payments for acquisitions	(429		)	—
Proceeds from investment securities	255			—
Purchase of investment securities	(2,300		)	—
Additions to oil and gas properties	(1,387		)	(1,573		)
Additions to other assets and other property and equipment, net	(156		)	(191		)
Net cash used in investing activities	(3,514		)	(1,208		)
Cash flows from financing activities:
Principal payments on long-term debt	(455		)	—
Proceeds from issuance of common stock, net of issuance costs	2,534			—
Distributions to noncontrolling interests	—			(1		)
Exercise of long-term incentive plan stock options and employee stock purchases	7			6
Purchases of treasury stock	(24		)	(31		)
Tax (provision) benefits related to stock-based compensation	(1		)	10
Payments of financing fees	—			(3		)
Dividends paid	(7		)	(6		)
Net cash provided by (used in) financing activities	2,054			(25		)
Net decrease in cash and cash equivalents	(500		)	(444		)
Cash and cash equivalents, beginning of period	1,391			1,025
Cash and cash equivalents, end of period	$	891		$	581

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.

9

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(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 operating in 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 September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015 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, 2015.

Certain reclassifications have been made to the 2015 financial statement and footnote amounts in order to conform to the 2016 presentation.

Restructuring. In February 2016, the Company announced plans to restructure its pressure pumping operations in South Texas, including relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. In connection therewith, the Company offered severance to certain employees and relocated a number of other employees from its South Texas locations to its operations in the Permian Basin. This initiative was substantially complete as of June 30, 2016.

In connection therewith, during the three and nine months ended September 30, 2016, the Company recognized nil and $4 million, respectively, of restructuring charges in other expense in the accompanying consolidated statements of operations. The restructuring charges for the nine months ended September 30, 2016 included approximately $3 million in cash employee severance costs and $1 million in employee relocation and other costs.

In May 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pressure pumping operations. The restructuring plan was substantially complete as of December 31, 2015. In connection therewith, during the three and nine months ended September 30, 2015, the Company recognized $9 million and $24 million, respectively, of restructuring charges in other expense in the accompanying consolidated statements of operations.

As of September 30, 2016, the Company had $2 million of restructuring liabilities recorded in other current and noncurrent liabilities in the accompanying consolidated balance sheet, primarily related to future lease obligations associated with its Denver, Colorado office.

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 underwriting and offering expenses.

New accounting pronouncements. In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-13, "Financial Instruments - Credit Losses." ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company does not believe this standard will have a material impact on its consolidated financial statements.

10

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Company does not believe this standard will have a material impact on its consolidated financial statements.

In February 2016, 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 is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

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 rescinds 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. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

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 $429 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 preliminary allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date, pending final post-close adjustments:

Assets acquired:
Proved properties	$	79
Unproved properties	348
Other property and equipment	5
Liabilities assumed:
Asset retirement obligations	(3		)
Net assets acquired	$	429

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

11

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

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.

In connection with the acquisition, the Company incurred acquisition related costs (primarily consulting, advisory and legal fees) of approximately $1.0 million. The operating results included in the Company's accompanying consolidated statements of operations from the date of acquisition to September 30, 2016, and the operating results that would have been recognized had the acquisition occurred on January 1, 2016, are not material to the Company's accompanying consolidated statements of operations.

EFS Midstream Divestiture. In July 2015, the Company sold its 50.1 percent equity interest in EFS Midstream LLC ("EFS Midstream") to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion, of which $530 million was received in cash and the remaining $501 million was in the form of a note, which was payable to the Company in July 2016. The Company recorded a net gain on the disposition of $777 million during the three and nine months ended September 30, 2015. In July 2016, the Company received the remaining cash payment of $501 million, which settled the outstanding note receivable.

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.

12

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(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 September 30, 2016 for each of the fair value hierarchy levels:

	Fair Value Measurement at September 30, 2016 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 September 30, 2016
	(in millions)
Assets:
Commodity derivatives	$	—	$	180	$	—	$	180
Deferred compensation plan assets	81		—		—		81
Total assets	81		180		—		261
Liabilities:
Commodity derivatives	—		19		—		19
Interest rate derivatives	—		8		—		8
Total liabilities	—		27		—		27
Total recurring fair value measurements	$	81	$	153	$	—	$	234

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("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 September 30, 2016, 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 that are 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.The Company recognized noncash impairment charges of $6 million and $21 million for the nine months ended September 30, 2016 and 2015, respectively, attributable to inventory and other property and equipment.

13

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

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 West Panhandle field during the three months ended March 31, 2016 and (ii) the Eagle Ford Shale field, the West Panhandle field and the South Texas - Other field during the year ended December 31, 2015 to their estimated fair values.

The Company calculated the fair values of the West Panhandle field, the Eagle Ford Shale field and the South Texas - Other field 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 estimated fair value.

The following table presents the fair value and fair value adjustments (in millions) for the Company's 2016 and 2015 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in respective Management's Price Outlooks:

							Management's Price Outlooks
	Impairment Date	Fair Value		Fair Value Adjustment			Oil		Gas
West Panhandle	March 2016	$	33	$	(32	)	$	49.77	$	3.24
South Texas - Eagle Ford Shale	December 2015	$	483	$	(846	)	$	52.82	$	3.34
South Texas - Other	September 2015	$	88	$	(72	)	$	57.41	$	3.46
West Panhandle	March 2015	$	61	$	(138	)	$	65.02	$	3.83

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 September 30, 2016 and December 31, 2015 are as follows:

	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Commercial paper, corporate bonds and time deposits	$	2,052	$	2,052	$	275	$	275
Current portion of long-term debt	$	485	$	496	$	448	$	462
Long-term debt	$	2,726	$	3,022	$	3,207	$	3,206

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, which approximates fair value, and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The net carrying value of held-to-maturity investments is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the investments. Income related to these investments is recorded in interest and other income in the Company's consolidated statement of operations. The investments represent Level

14

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

2 inputs in the hierarchy. Commercial paper, corporate bonds 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, they 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 September 30, 2016:

	September 30, 2016
Consolidated Balance Sheet Location	Cash		Commercial Paper		Corporate Bonds		Time Deposits		Total
	(in millions)
Cash and cash equivalents	$	891	$	—	$	—	$	—	$	891
Short-term investments	—		742		459		532		1,733
Long-term investments	—		—		319		—		319
	$	891	$	742	$	778	$	532	$	2,943

Debt obligations. Current and noncurrent long-term debt includes the Company's credit facility and the Company's 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, prepaid expenses, 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.

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

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

15

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of September 30, 2016 and the weighted average oil prices for those contracts:

	2016			Year Ending December 31,
	Fourth Quarter			2017
Collar contracts:
Volume (Bbl)	—			6,000
Price per Bbl:
Ceiling	$	—		$	70.40
Floor	$	—		$	50.00
Collar contracts with short puts:
Volume (Bbl) (a)	112,000			94,973
Price per Bbl:
Ceiling	$	75.94		$	62.36
Floor	$	65.41		$	49.07
Short put	$	47.03		$	41.30
Basis swap contracts:
Midland-Cushing index swap volume (Bbl)	6,630			—
Price differential ($/Bbl) (b)	$	(0.80	)	$	—

____________________

(a) During the nine months ended September 30, 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl.

(b) Represents the basis differential between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma.

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 the NGL component price volatility.

16

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of September 30, 2016 and the weighted average NGL prices for those contracts:

	2016		Year Ending December 31,
	Fourth Quarter		2017
Propane swap contracts (a):
Volume (Bbl)	6,000		—
Price per Bbl	$	21.51	$	—
Ethane collar contracts (b):
Volume (Bbl)	—		3,000
Price per Bbl:
Ceiling	$	—	$	11.83
Floor	$	—	$	8.68
Ethane basis swap contracts (c):
Volume (MMBtu)	2,768		—
Price differential ($/MMBtu)	$	0.91	$	—

 ____________________

(a) Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas posted prices.

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

(c) 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 swaps 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 2,768 MMBtu per day, which is equivalent to 1,000 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 the actual index prices at which the gas is sold.

17

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of September 30, 2016 and the weighted average gas prices for those contracts:

	2016			Year Ending December 31,
	Fourth Quarter			2017			2018
Swap contracts:
Volume (MMBtu)	70,000			—			—
Price per MMBtu	$	4.06		$	—		$	—
Collar contracts with short puts:
Volume (MMBtu) (a)	180,000			130,000			50,000
Price per MMBtu:
Ceiling	$	4.01		$	3.39		$	3.40
Floor	$	3.24		$	2.85		$	2.75
Short put	$	2.78		$	2.41		$	2.25
Basis swap contracts:
Gulf Coast index swap volume (b)	10,000			—			—
Price differential ($/MMBtu)	$	—		$	—		$	—
Mid-Continent index swap volume (b)	15,000			45,000			—
Price differential ($/MMBtu)	$	(0.32	)	$	(0.32	)	$	—
Permian Basin index swap volume (c)	34,946			9,863			—
Price differential ($/MMBtu)	$	0.41		$	0.37		$	—

____________________

(a) During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu.

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

(c) Represent swaps 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 September 30, 2016, 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 its drilling rigs and fracture stimulation fleet equipment. As of September 30, 2016, the Company was party to derivative swap contracts for 1,000 Bbls per day of diesel for 2017 at an average per Bbl fixed price of $60.48.

Interest rate derivative activities. As of September 30, 2016, the Company was a party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 to December 2027 in exchange for paying a weighted average fixed interest rate of 1.94 percent on a notional amount of $250 million on December 15, 2017.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives 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.

18

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(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 September 30, 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	$	190	$	(18	)	$	172
Commodity price derivatives	Derivatives - noncurrent	$	11	$	(3	)	8
							$	180
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	25	$	(18	)	$	7
Commodity price derivatives	Derivatives - noncurrent	$	15	$	(3	)	12
Interest rate derivatives	Derivatives - noncurrent	$	8	$	—		8
							$	27

Fair Value of Derivative Instruments as of December 31, 2015
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	$	695	$	(1	)	$	694
Commodity price derivatives	Derivatives - noncurrent	$	64	$	—		64
							$	758
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	1	$	(1	)	$	—
Commodity price derivatives	Derivatives - noncurrent	$	1	$	—		1
							$	1

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.

19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(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 September 30,					Nine Months Ended September 30,
Hedging Instruments	Earnings on Derivatives	2016		2015			2016			2015
		(in millions)
Commodity price derivatives	Derivative gains (losses), net	$	91	$	575		$	(87	)	$	614
Interest rate derivatives	Derivative gains (losses), net	—		(2		)	(8		)	3
Total		$	91	$	573		$	(95	)	$	617

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 and nine months ended September 30, 2016:

	Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
	(in millions)
Beginning capitalized exploratory costs	$	357		$	306
Additions to exploratory costs pending the determination of proved reserves	328			991
Reclassification due to determination of proved reserves	(286		)	(898		)
Exploratory well costs charged to exploration expense	(1		)	(1		)
Ending capitalized exploratory costs	$	398		$	398

The following table provides an aging, as of September 30, 2016 and December 31, 2015 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:

	September 30, 2016		December 31, 2015
	(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	396	$	303
More than one year	2		3
	$	398	$	306
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year	1		1

The well that was suspended for a period greater than one year as of September 30, 2016 is in the Eagle Ford Shale area.The Company expects to complete this well in 2017.

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 September 30, 2016, the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants.

20

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

Senior notes. The Company's 5.875% senior notes (the "5.875% Senior Notes") matured and were repaid in July 2016. The Company funded the $455 million repayment of the 5.875% Senior Notes with cash on hand. The Company's 6.65% senior notes, with an outstanding debt principal balance of $485 million, will mature in March 2017 and are classified as current in the accompanying consolidated balance sheets as of September 30, 2016.

NOTE H. Incentive Plans

Stock-based compensation

For the three and nine months ended September 30, 2016, the Company recorded $31 million and $84 million, respectively, of stock-based compensation expense for all plans, as compared to $26 million and $87 million for the same respective periods in 2015. As of September 30, 2016, there was $138 million of unrecognized compensation expense related to unvested share-based compensation plan awards, including $36 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 over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of September 30, 2016 and December 31, 2015, accounts payable – due to affiliates included $17 million and $16 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the nine months ended September 30, 2016 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, 2015	1,081,650		271,031		148,547		199,058
Awards granted	520,980		180,383		104,114		—
Awards vested	(459,833	)	(141,441	)	(8,670	)	—
Awards forfeited	(43,996	)	(14,067	)	(4,821	)	—
Outstanding as of September 30, 2016	1,098,801		295,906		239,170		199,058

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 and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)
Beginning asset retirement obligations	$	281		$	187		$	285		$	189
Liabilities assumed in acquisitions	3			—			3			—
New wells placed on production	—			1			—			2
Liabilities settled	(8		)	(9		)	(21		)	(18		)
Accretion of discount	5			3			14			9
Ending asset retirement obligations	$	281		$	182		$	281		$	182

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 September 30, 2016 and December 31, 2015, the current portion of the Company's asset retirement obligations was $40 million.

21

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(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 and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in millions)
Interest income	$	5	$	2	$	14	$	2
Deferred compensation plan income	—		—		2		4
Equity interest in income of EFS Midstream (a)	—		—		—		5
Other income	2		—		5		5
Total interest and other income	$	7	$	2	$	21	$	16

 ____________________

(a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream.

22

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

NOTE L. Other Expense

The following table provides the components of the Company's other expense for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in millions)
Transportation commitment charges (a)	$	27	$	11	$	77	$	38
Loss from vertical integration services (b)	17		20		46		16
Idle drilling and well service equipment charges (c)	10		22		42		73
Terminated drilling rig charges (d)	—		—		15		—
Impairment of inventory and other property and equipment (e)	1		13		6		21
Restructuring charges (f)	—		9		4		24
Other	14		4		33		14
Total other expense	$	69	$	79	$	223	$	186

 ____________________

(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 service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three and nine months ended September 30, 2016, these vertical integration net margins included $19 million and $144 million, respectively, of revenues and $36 million and $190 million, respectively, of costs and expenses. For the same respective periods in 2015, these vertical integration net margins included $66 million and $264 million of revenues and $86 million and $280 million of costs and expenses.

(c) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations.

(d) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

(e) Primarily represents charges to reduce excess material and supplies inventories to their market values. See Note D for additional information on the fair value of materials and supplies inventory.

(f) Represents costs associated with the Company's restructuring of its pressure pumping operations in South Texas in 2016 and its operations in Colorado in 2015. See Note B for additional information on the restructuring charges.

NOTE M. Income Taxes

The Company's income tax benefit attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
	(in millions)
Current tax benefit (provision)	$	22	$	(48	)	$	22	$	(49	)
Deferred tax benefit (provision)	56		(307		)	340		(146		)
Income tax benefit (provision)	$	78	$	(355	)	$	362	$	(195	)

For the three and nine months ended September 30, 2016, the Company's effective tax rates, excluding income attributable to noncontrolling interests, were 140 percent and 41 percent, respectively, as compared to an effective rate of 35 percent for each of the the same respective periods in 2015. The Company's effective tax rates for the three and nine months ended September 30, 2016 differ from the U.S. statutory rate of 35 percent primarily due to recognizing research and experimental expenditures credits of $59 million in the third quarter of 2016, and, to a lesser extent, state income tax apportionments and nondeductible expenses.

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 September 30, 2016, the Company had unrecognized tax benefits of $94 million resulting from research and experimental expenditures related to horizontal drilling and completions innovations. If all of, or a portion of, the unrecognized tax benefit is sustained upon

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2016

(Unaudited)

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 September 2017. There were no unrecognized tax benefits as of December 31, 2015.

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 2013 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 2010. As of September 30, 2016, 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 Income (Loss) Per Share

The following table reconciles the Company's income (loss) from continuing operations to basic and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016			2015
	(in millions)
Income (loss) from continuing operations	$	22	$	648		$	(513	)	$	356
Participating basic earnings	—		(6		)	—			(3		)
Basic and diluted income (loss) from continuing operations	$	22	$	642		(513		)	353
Basic and diluted loss from discontinued operations	$	—	$	(2	)	$	—		$	(6	)
Basic and diluted net income (loss) attributable to common stockholders	$	22	$	640		$	(513	)	$	347

Basic and diluted weighted average common shares outstanding were 170 million and 165 million, respectively, for the three and nine months ended September 30, 2016. Basic weighted average common shares outstanding were 149 million for both the three and nine months ended September 30, 2015, and diluted weighted average shares outstanding were 150 million and 149 million for the three and nine months ended September 30, 2015, respectively.

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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 third quarter of 2016 included the following highlights:

• Net income attributable to common stockholders for the third quarter of 2016 was $22 million ($0.13 per diluted share), as compared to net income of $646 million ($4.27 per diluted share) for the third quarter of 2015. The primary components of the decrease in net income attributable to common stockholders include:

• a $778 million decrease in net gains on disposition of assets as a result of recognizing a $777 million gain in the third quarter of 2015 associated with the sale of EFS Midstream LLC;

• a $482 million decrease in net derivative gains, primarily as a result of changes in forward commodity prices and the Company's portfolio of derivatives;

• a $22 millionincrease in DD&A expense, primarily attributable to a 13 percentincrease in sales volumes; partially offset by

• a $433 million reduction in the Company's income taxes as a result of the reduction in earnings from continuing operations;

• a $86 millionincrease in oil and gas revenues as a result of the aforementioned 13 percentincrease in sales volumes, partially offset by a decrease in oil and gas prices;

• a $72 million decrease in impairment charges as a result of the South Texas - Other impairment charge in September 2015;

• a $48 milliondecrease in total oil and gas production costs, primarily due to the Company's cost saving initiatives; and

• a $10 milliondecrease in other expense, primarily related to decreases in idle drilling and well service equipment charges, inventory impairment charges and restructuring charges.

• During the third quarter of 2016, average daily sales volumes from continuing operations increased by 13 percent to 238,878 BOEPD, as compared to 210,711 BOEPD during the third quarter of 2015. The increase in third quarter 2016 average daily sales volumes, as compared to the third quarter of 2015, is primarily due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.

• Average oil and gas prices decreased during the third quarter of 2016 to $41.44 per Bbl and $2.43 per Mcf, respectively, as compared to $42.46 per Bbl and $2.53 per Mcf, respectively, in the third quarter of 2015. Average NGL prices increased during the third quarter of 2016 to $12.46 per Bbl, as compared to $12.39 per Bbl in the third quarter of 2015.

• Net cash provided by operating activities increased to $441 million for the three months ended September 30, 2016, as compared to $358 million for the three months ended September 30, 2015. The $83 millionincrease 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 September 30, 2016 as a result of increased sales volumes (partially offset by the aforementioned decreases in oil and gas prices) and reductions in operating costs; partially offset by an increase in funds used to satisfy working capital obligations.

• As of September 30, 2016, the Company's net debt to book capitalization decreased to three percent, as compared to 21 percent at December 31, 2015, primarily due to the Company's issuances of 19.8 million shares of common stock during 2016 for cash proceeds of $2.5 billion.

Fourth Quarter 2016 Outlook

Based on current estimates, the Company expects the following operating and financial results from continuing operations for the quarter ending December 31, 2016:

Production is forecasted to average 237,000 to 242,000 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 $17.50 to $19.50 per BOE.

Total exploration and abandonment expense is expected to be $20 million to $30 million. General and administrative expense is expected to be $78 million to $83 million. Interest expense is expected to be $45 million to $50 million, and other expense is

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PIONEER NATURAL RESOURCES COMPANY

expected to be $65 million to $75 million. Other expense is expected to include (i) $5 million to $10 million for stacked drilling rig charges, (ii) $28 million to $33 million of charges associated with excess firm gathering and transportation commitments, (iii) $15 million to $20 million of losses (principally noncash) associated with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company and (iv) 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 nine months ended September 30, 2016:

	Oil (Bbls)	NGLs (Bbls)	Gas (Mcf)	Total (BOE)
Permian Basin	113,383	29,108	136,072	165,169
South Texas - Eagle Ford Shale	13,085	10,740	76,903	36,643
Raton Basin	—	—	97,875	16,312
West Panhandle	2,807	3,195	11,293	7,885
South Texas - Other	1,323	208	21,650	5,139
Other	4	1	35	10
Total	130,602	43,252	343,828	231,158

The Company's total liquids production from continuing operations increased to 75 percent of total production, on a BOE basis, for the nine months ended September 30, 2016, as compared to 70 percent for the same period last year.

During the second quarter of 2016, the Company increased its capital expenditures budget for the year by $100 million to $2.1 billion to fund expected incremental drilling rig expenditures during 2016 (increasing the rig count to 17 rigs from the 12 rigs that were originally planned). The capital expenditures budget excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs. The updated 2016 capital budget includes $1.95 billion for drilling and completions operations (includes tank batteries, salt water disposal facilities and gas processing facilities) and $150 million for water infrastructure, vertical integration, systems upgrades and field facilities. The additional drilling activity in 2016 is pad drilling, with the wells on the new pads expected to be placed on production in early 2017.

The following table summarizes by geographic area the Company's finding and development costs incurred during the nine months ended September 30, 2016:

	Acquisition Costs				Exploration		Development
	Proved		Unproved		Costs		Costs		Total
	(in millions)
Permian Basin	$	82	$	360	$	1,003	$	349	$	1,795
South Texas - Eagle Ford Shale	—		—		35		24		59
West Panhandle	—		—		1		5		6
South Texas - Other	—		—		—		2		2
Other	—		—		4		—		4
Total	$	82	$	360	$	1,043	$	380	$	1,866

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the Company's development and exploration/extension drilling activities for the nine months ended September 30, 2016:

	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Ending Wells in Progress
Permian Basin	27	18	33	12
South Texas - Eagle Ford Shale	6	—	3	3
Total	33	18	36	15

	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Ending Wells in Progress
Permian Basin	77	168	141	104
South Texas - Eagle Ford Shale	23	1	9	15
Total	100	169	150	119

Permian Basin area. In the first half of 2016, the Company reduced its rig count in the Spraberry/Wolfcamp area from 18 rigs at year-end 2015 to 13 rigs at June 30, 2016. During the third quarter of 2016, the Company increased the rig count in the Spraberry/Wolfcamp area to 14 rigs, and it expects to add an additional three rigs during the fourth quarter of 2016. During 2016, the Company expects to complete approximately 230 horizontal wells (190 horizontal wells in the northern portion of the play and 40 horizontal wells in the southern portion of the play). Approximately 60 percent of the horizontal wells are planned to be drilled in the Wolfcamp B interval, 25 percent in the Wolfcamp A interval and 15 percent in the Lower Spraberry Shale interval. The Company continues to drill utilizing two-well and three-well pads and expects to spend $1.87 billion of drilling and completion capital in the Spraberry/Wolfcamp field during 2016. During the first nine months of 2016, the Company completed 134 horizontal wells in the northern portion of the play and 40 horizontal wells in the southern portion of the play. In the northern portion of the play, approximately 60 percent of wells placed on production were Wolfcamp B interval wells, and the remaining 40 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.

In August 2016, the Company completed the acquisition of approximately 28,000 net acres in the Permian Basin, with net production of approximately 1,400 BOEPD, from an unaffiliated third party for $429 million, including normal closing adjustments. The fair value of the assets acquired included $348 million of unproved property, $79 million of proved property and $5 million of other property and equipment. The fair value of the asset retirement obligations assumed was $3 million.

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 field. During the third quarter of 2016, the Company utilized five Company-owned fracture stimulation fleets totaling approximately 330,000 horsepower to support its drilling operations in the Spraberry/Wolfcamp field. The Company has idled three of its eight fracture stimulation fleets since the second quarter of 2016 due to reduced demand for fracture stimulation services as a result of the Company's reduced rig count. 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 by the Company to fracture stimulate horizontal wells in the Spraberry and Wolfcamp Shale intervals.

The Company has been and continues to aggressively 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 optimizing completions in the Spraberry and Wolfcamp Shale intervals.

The Company's long-term growth plan continues to be focused on optimizing the development of the field and addressing future requirements for water, field infrastructure, gas processing, sand, pipeline takeaway, oilfield services, tubulars, electricity, buildings and roads. However, much of the Company's front-end loaded infrastructure plans, which were expected to provide significant future cost savings and support the Company's long-term growth plan in the Spraberry/Wolfcamp area, have been minimized given the significant decline in oil prices. The Company expects to continue to invest in infrastructure for a field-wide water distribution network, additional gas processing facilities and expansion of Premier Silica's Brady sand mine based on the Company's outlook for commodity prices and expected activity levels.

Eagle Ford Shale area. In the Eagle Ford Shale play in South Texas, the rig count has been reduced to zero rigs given current commodity prices that continue to adversely affect well returns. The Company completed 12 Eagle Ford Shale wells during

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PIONEER NATURAL RESOURCES COMPANY

2016. The Company does not plan to complete any additional Eagle Ford Shale wells during the remainder of the year. Due to the reduction in drilling activity, the Company expects to continue to incur fees associated with unused firm transportation, gathering, processing, and fractionation commitments over the term of the obligations.

In July 2015, the Company closed on the sale of its 50.1 percent interest in EFS Midstream to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining $501 million was in the form of a note, which was payable to the Company in July 2016. The note receivable was paid in full in July 2016.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $643 million and $1.7 billion for the three and nine months ended September 30, 2016, respectively, as compared to $557 million and $1.7 billion for the same respective periods in 2015.

The increase in oil and gas revenues during the three months ended September 30, 2016, as compared to the same period in 2015, is primarily due to 23 percent and 18 percent increases in daily oil and NGL sales volumes, respectively, partially offset by an eight percent decline in daily gas sales volumes and declines of two percent and four percent in average oil and gas prices, respectively. Oil and gas revenues for the nine months ended September 30, 2016, as compared to the same period in 2015, reflected increases of 27 percent and 14 percent in daily oil and NGL sales volumes, respectively, offset by a four percent decline in daily gas sales volumes and declines of 18 percent, 10 percent and 23 percent in average oil, NGL and gas prices, respectively.

The following table provides average daily sales volumes for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Oil (Bbls)	134,240	109,101	130,602	102,780
NGLs (Bbls)	49,235	41,617	43,252	37,903
Gas (Mcf)	332,415	359,957	343,828	358,594
Total (BOEs)	238,878	210,711	231,158	200,448

Average daily BOE sales volumes increased by 13 percent and 15 percent for the three and nine months ended September 30, 2016, respectively, as compared to the same periods in 2015, principally due to the Company's successful Spraberry/Wolfcamp horizontal drilling program. Production for the nine months ended September 30, 2016 and September 30, 2015 reflects lower NGL production volumes of approximately 4,900 Bbls per day and 5,200 Bbls per day, respectively, due to voluntary reductions in recoveries of ethane since it had 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 and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Oil (per Bbl)	$	41.44	$	42.46	$	37.27	$	45.63
NGL (per Bbl)	$	12.46	$	12.39	$	12.37	$	13.72
Gas (per Mcf)	$	2.43	$	2.53	$	1.96	$	2.53
Total (per BOE)	$	29.24	$	28.75	$	26.29	$	30.52

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure 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 oil 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 responsibility to deliver the commodities sold. The net effect of third party purchases and sales of oil and gas for the three and nine months ended September 30, 2016 was a loss of $14 million and $51 million, respectively, as compared to a loss of $13 million and $19 million for the same respective periods in 2015. 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.

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PIONEER NATURAL RESOURCES COMPANY

Interest and other income. Interest and other income for the three and nine months ended September 30, 2016 was $7 million and $21 million, respectively, as compared to $2 million and $16 million for the same respective periods in 2015. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Derivative gains (losses), net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three and nine months ended September 30, 2016, the Company recorded $91 million of net derivative gains and $95 million of net derivative losses, respectively, on commodity price and interest rate derivatives, of which $184 million and $533 million represented net cash receipts, respectively. During the three and nine months ended September 30, 2015, the Company recorded $573 million and $617 million of net derivative gains, respectively, of which $238 million and $595 million represented net cash receipts, respectively.

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 and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30, 2016					Nine Months Ended September 30, 2016
	Net cash receipts		Price impact			Net cash receipts		Price impact
	(in millions)					(in millions)
Oil derivative receipts	$	168	$	13.59	per Bbl	$	471	$	13.16	per Bbl
NGL derivative receipts	2		$	0.40	per Bbl	6		$	0.54	per Bbl
Gas derivative receipts	14		$	0.48	per Mcf	56		$	0.59	per Mcf
Total net commodity derivative receipts	$	184				$	533

	Three Months Ended September 30, 2015					Nine Months Ended September 30, 2015
	Net cash receipts		Price impact			Net cash receipts		Price impact
	(in millions)					(in millions)
Oil derivative receipts	$	205	$	20.47	per Bbl	$	505	$	17.98	per Bbl
NGL derivative receipts	5		$	1.28	per Bbl	7		$	0.65	per Bbl
Gas derivative receipts	29		$	0.87	per Mcf	85		$	0.87	per Mcf
Total net commodity derivative receipts	$	239				$	597

See Notes D and 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 activities and market risks associated with those activities.

Gain on disposition of assets, net. The Company recorded net gains on the disposition of assets of $1 million and $4 million for the three and nine months ended September 30, 2016, respectively, as compared to $779 million and $782 million for the same respective periods in 2015. The net gains on the disposition of assets for the three and nine months ended September 30, 2015 are primarily due to the gain of $777 million recorded on the sale of EFS Midstream in July 2015. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's EFS Midstream divestiture.

Oil and gas production costs. The Company recognized oil and gas production costs of $141 million and $438 million during the three and nine months ended September 30, 2016, respectively, as compared to $189 million and $532 million during the same respective periods in 2015. 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 (income) charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from the gathering and processing of third-party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the three and nine months ended September 30, 2016 decreased by 34 percent and 29 percent, as compared to the same respective periods in 2015. The decrease in lease operating expenses per BOE during the three and nine months ended September 30, 2016, as compared to the same respective periods in 2015, was primarily due to

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PIONEER NATURAL RESOURCES COMPANY

a greater proportion of the Company's production coming from horizontal wells in Spraberry/Wolfcamp area that have lower per BOE lease operating costs, cost reduction initiatives and lower electricity and fuel costs, which were impacted by lower commodity prices. The decline in workover costs per BOE during the three and nine months ended September 30, 2016, as compared to the same respective periods in 2015, was primarily due to most workover activity being uneconomical as a result of the lower commodity price environment.

The following table provides the components of the Company's oil and gas production costs per BOE for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Lease operating expenses	$	4.72	$	7.08		$	5.03	$	7.42
Third-party transportation charges	1.31		2.04			1.51		1.55
Net natural gas plant (income) charges	0.02		(0.01		)	0.07		0.12
Workover costs	0.37		0.64			0.30		0.63
Total production costs	$	6.42	$	9.75		$	6.91	$	9.72

Production and ad valorem taxes. The Company's production and ad valorem taxes were $32 million and $97 million during the three and nine months ended September 30, 2016, respectively, as compared to $36 million and $112 million for the same respective periods in 2015. 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 and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Production taxes	$	1.07	$	1.11	$	1.03	$	1.23
Ad valorem taxes	0.36		0.76		0.50		0.82
Total production and ad valorem taxes	$	1.43	$	1.87	$	1.53	$	2.05

Depletion, depreciation and amortization expense. The Company's DD&A expense was $386 million ($17.54 per BOE) and $1.1 billion ($17.73 per BOE) for the three and nine months ended September 30, 2016, respectively, as compared to $364 million ($18.77 per BOE) and $1.0 billion ($18.32 per BOE) during the same respective periods in 2015. The change in per BOE DD&A expense during the three and nine months ended September 30, 2016, as compared to the same respective periods in 2015, is primarily due to a decrease in depletion expense per BOE on oil and gas properties. Depletion expense on oil and gas properties was $17.05 and $17.21 per BOE during the three and nine months ended September 30, 2016, respectively, as compared to $18.22 and $17.72 per BOE during the same respective periods in 2015.

An extended commodity price decline could adversely affect the amount of oil, NGLs and gas that the Company can economically produce, which could result in the Company having to make downward adjustments to its estimated proved reserves. Reductions in estimated proved reserves could increase the amount of depletion expense the Company recognizes as a result of shortening the economic productive lives of the Company's producing wells.

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.

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PIONEER NATURAL RESOURCES COMPANY

As a result of the Company's proved property impairment assessments, the Company recognized noncash impairment charges to reduce the carrying values of (i) its West Panhandle Field during the three months ended March 31, 2016 ($32 million impairment charge) and (ii) the Eagle Ford Shale field ($846 million impairment charge), the West Panhandle field ($138 million impairment charge) and the South Texas - Other field ($72 million impairment charge) during the year ended December 31, 2015 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.

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expenses and lease abandonments and other exploration expenses for the three and nine months ended September 30, 2016 and 2015 (in millions):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Geological and geophysical	$	18	$	18	$	55	$	56
Exploratory dry holes	1		—		1		16
Leasehold abandonments and other	—		7		40		7
	$	19	$	25	$	96	$	79

The geological and geophysical expenses for the three and nine months ended September 30, 2016 and 2015 were principally related to geological and geophysical personnel costs. During the nine months ended September 30, 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 nine months ended September 30, 2016, the Company drilled and evaluated 150 exploration/extension wells, all of which were successfully completed as discoveries. During the same period in 2015, the Company drilled and evaluated 157 exploration/extension wells, 155 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and nine months ended September 30, 2016 was $82 million ($3.72 per BOE) and $235 million ($3.72 per BOE), respectively, as compared to $81 million ($4.18 per BOE) and $246 million ($4.50 per BOE) for the same respective periods in 2015. The decrease in general and administrative expense per BOE during the three and nine months ended September 30, 2016, as compared to the same respective periods in 2015, was primarily due to the Company's cost reduction initiatives, including not replacing personnel who have left the Company and reduced contractor activity, while continuing to increase production.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $5 million and $14 million for the three and nine months ended September 30, 2016, respectively, as compared to $3 million and $9 million for the same respective periods in 2015. 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 $50 million and $161 million for the three and nine months ended September 30, 2016, respectively, as compared to $46 million and $138 million for the same respective periods in 2015. The increase in interest expense during the three and nine months ended September 30, 2016, as compared to the same respective periods in 2015, was primarily due to the Company's December 2015 issuance of $500 million of 3.45% Senior Notes due 2021 and $500 million of 4.45% Senior Notes due 2026. The weighted average interest rates on the Company's indebtedness for the three and nine months ended September 30, 2016, including the effects of capitalized interest, were 5.9 percent and 6.1 percent, respectively, as compared to 7.0 percent for both respective periods in 2015.

Other expense. Other expense was $69 million and $223 million for the three and nine months ended September 30, 2016, respectively, as compared to $79 million and $186 million during the same respective periods in 2015. The decrease in other expense for the three months ended September 30, 2016, as compared to the same respective period in 2015, was primarily due to decreases of (i) $12 million in idle drilling and well service equipment charges, (ii) $12 million in inventory impairment charges, (iii) $9 million in restructuring charges and (iv) $3 million in net losses from Company-provided fracture stimulation and related service operations that are provided to third party working interest owners, partially offset by (v) a $16 million increase in unused firm transportation costs. The increase in other expense for the nine months ended September 30, 2016, as compared to the same respective period in 2015, was primarily due to increases of (i) $39 million in unused firm transportation costs, (ii) $30 million in net losses from Company-provided fracture stimulation and related service operations that are provided to third party working interest owners and (iii) $15 million in terminated rig contract charges, partially offset by decreases of (iv) $31 million in idle drilling and well service equipment charges, (v) $20 million in restructuring charges and (vi) $15 million in inventory impairment charges.

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PIONEER NATURAL RESOURCES COMPANY

The Company expects to continue to incur idle drilling rig charges for the remainder of 2016. Based on current drilling plans for 2017, only minimal, if any, stacked rig charges will be incurred. The Company also 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 the gathering and transportation commitments, the contractual obligations expire. See Notes B and L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax benefit (provision). The Company recorded an income tax benefit from continuing operations of $78 million and $362 million for the three and nine months ended September 30, 2016, respectively, as compared to income tax provisions of $355 million and $195 million for the same respective periods in 2015. The Company's effective tax rate for the three and nine months ended September 30, 2016 was 140 percent and 41 percent, respectively, as compared to 35 percent for the three and nine months ended September 30, 2015. The Company's effective tax rates for the three and nine months ended September 30, 2016 differ from the U.S. statutory rate of 35 percent primarily due to recognizing research and experimental expenditures credits of $59 million in the third quarter of 2016, and, to a lesser extent, state income tax apportionments and nondeductible expenses.

As of September 30, 2016, the Company had unrecognized tax benefits of $94 million resulting from research and experimental expenditures related to horizontal drilling and completions innovations. If all of, 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 September 2017. There were no unrecognized tax benefits as of December 31, 2015. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.

Loss from discontinued operations, net of tax. The Company did not have any discontinued operations activity for the three and nine months ended September 30, 2016. For the three and nine months ended September 30, 2015, the Company reported net losses from discontinued operations of $2 million and $6 million, respectively.

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 investments in commercial paper, corporate bonds and time deposits that are classified as short-term and long-term investments in the accompanying consolidated balance sheets, proceeds from divestitures or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2016 is $2.1 billion (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), which includes approximately $1.95 billion for drilling operations and $150 million for water infrastructure, vertical integration, system upgrades and field facilities. The Company's capital expenditures during the nine months ended September 30, 2016 were $1.5 billion, consisting of $1.4 billion for drilling operations (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs) and $154 million for water infrastructure, vertical integration, system upgrades and other plant and equipment additions. Based on results for the nine months ended September 30, 2016 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 and, if necessary, availability under the Credit Facility to be sufficient to fund its planned capital expenditures, acquisitions and contractual obligations for the remainder of 2016 and 2017.

Investing activities. Investing activities used $3.5 billion of cash during the nine months ended September 30, 2016, as compared to $1.2 billion of cash used in investing activities during the nine months ended September 30, 2015. The increase in cash used in investing activities for the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015, is primarily due to the net purchases of $2.0 billion of investment securities (commercial paper, corporate bonds and time deposits) and the purchase of 28,000 net acres in the Permian Basin, with net production of approximately 1,400 BOEPD, from an unaffiliated third party for $429 million. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's Permian Basin acquisition during the third quarter of 2016. During the nine months ended September 30, 2016, the Company's expenditures for investing activities were primarily funded by net cash provided by operating activities, cash on hand and the Company's issuance of 19.8 million shares of common stock during the the first half of 2016 for cash proceeds of $2.5 billion.

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PIONEER NATURAL RESOURCES COMPANY

Dividends/distributions. During March and August of 2016 and 2015, 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 September 30, 2016, 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. There were no material changes to the Company's contractual obligations during the third quarter of 2016.

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 September 30, 2016, these contracts represented net assets of $153 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 September 30, 2016. 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 about the Company's derivative instruments and market risk.

Capital resources. The Company's primary capital resources are cash and cash equivalents, investment securities, 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 using cash on hand, sales of short-term and long-term investments, availability under its Credit Facility, issuances of debt or equity securities or obtain capital from other sources, such as through sales of nonstrategic assets.

Operating activities. Net cash provided by operating activities during the nine months ended September 30, 2016 was $960 million, as compared to $789 million during the same period in 2015. The increase in net cash provided by operating activities for the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015, is primarily due to reductions in operating costs and funds used to satisfy working capital obligations.

Financing activities. Net cash provided by financing activities during the nine months ended September 30, 2016 was $2.1 billion, as compared to net cash used in financing activities of $25 million during the same period in 2015. The change to net cash provided by financing activities during the nine months ended September 30, 2016, as compared to the same period of 2015, is primarily the result of the Company's issuance of 19.8 million shares of common stock during 2016 for cash proceeds of $2.5 billion, partially offset by the principal payment of $455 million for the Company's 5.875% Senior Notes that matured and were repaid in July 2016.

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 on hand, sales of short-term and long-term investments and unused borrowing capacity under its Credit Facility. As of September 30, 2016, 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 September 30, 2016. The Company also had cash on hand of $891 million, short-term investments of $1.7 billion and long-term investments of $319 million as of September 30, 2016. If internal cash flows do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its

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PIONEER NATURAL RESOURCES COMPANY

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. 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 and, if necessary, available capacity under the Company's Credit Facility will be adequate to fund planned 2016 and 2017 capital expenditures, acquisitions, dividend payments and provide adequate liquidity to fund other needs, including debt maturities, 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 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 September 30, 2016 was $10.7 billion, consisting of $891 million of cash and cash equivalents, short-term and long-term investments of $2.1 billion, debt of $3.2 billion and equity of $10.4 billion. The Company's net debt to net book capitalization decreased to three percent at September 30, 2016 from 21 percent at December 31, 2015, primarily due to the Company's issuance of 19.8 million shares of common stock during the the first half of 2016 for cash proceeds of $2.5 billion. The Company's ratio of current assets to current liabilities increased to 2.51 to 1.00 at September 30, 2016, as compared to 2.19 to 1.00 at December 31, 2015, primarily due to the aforementioned issuance of common stock during the first half of 2016.

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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PIONEER NATURAL RESOURCES COMPANY

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, 2015. 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, 2015.

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 nine months ending September 30, 2016:

	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in millions)
Fair value of contracts outstanding as of December 31, 2015	$	757		$	—		$	757
Changes in contract fair value	(87		)	(8		)	(95		)
Contract maturity receipts	(533		)	—			(533		)
Payments associated with entering new contracts	24			—			24
Fair value of contracts outstanding as of September 30, 2016	$	161		$	(8	)	$	153

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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PIONEER NATURAL RESOURCES COMPANY

The following table provides information about financial instruments to which the Company was a party as of September 30, 2016 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 debt's estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of September 30, 2016. Although the Company had no outstanding variable rate debt as of September 30, 2016, the average variable contractual rates for its credit facility projected forward proportionate to the forward yield curve for LIBOR on October 28, 2016 is presented in the table below.

	Three Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at September 30,
	2016			2017			2018			2019			2020			Thereafter			Total		2016
	(dollars in millions)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	485		$	450		$	—		$	450		$	1,850		$	3,235	$	3,518
Weighted average fixed interest rate	5.51		%	5.35		%	5.11		%	5.00		%	4.42		%	5.28		%
Average variable interest rate	1.74		%	2.57		%	2.75		%	2.94		%	3.15		%
Interest Rate Swaps:
Notional debt amount (b)	$	—		$	250		$	—		$	—		$	—		$	—				$	8
Fixed rate payable (%)				1.94		%
Variable rate receivable (%) (c)				1.85		%

 ____________________

(a) Represents maturities of principal amounts excluding debt issuance costs, debt issuance discounts and net deferred fair value hedge losses.

(b) As of September 30, 2016, the Company was a party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 to December 2027 in exchange for paying a weighted average fixed interest rate of 1.94 percent on a notional amount of $250 million on December 15, 2017.

(c) The variable rate receivable represents the October 28, 2016 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 September 30, 2016. 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 Note 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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PIONEER NATURAL RESOURCES COMPANY

	2016			Year Ending December 31,					Asset (Liability) Fair Value at September 30,
	Fourth Quarter			2017			2018		2016 (a)
									(in millions)
Oil Derivatives:
Average daily notional Bbl volumes:
Collar contracts	—			6,000			—		$	9
Weighted average ceiling price per Bbl	$	—		$	70.40		$	—
Weighted average floor price per Bbl	$	—		$	50.00		$	—
Collar contracts with short puts (b)	112,000			94,973			—		$	146
Weighted average ceiling price per Bbl	$	75.94		$	62.36		$	—
Weighted average floor price per Bbl	$	65.41		$	49.07		$	—
Weighted average short put price per Bbl	$	47.03		$	41.30		$	—
Average forward NYMEX oil prices (c)	$	48.70		$	51.51		$	—
Midland-Cushing index swap contracts	6,630			—			—		$	—
Weighted average fixed price per Bbl	$	(0.80	)	$	—		$	—
Average forward basis differential prices (d)	$	(0.15	)	$	—		$	—
NGL Derivatives:
Average daily notional Bbl volumes:
Propane swap contracts (e)	6,000			—			—		$	(1	)
Weighted average fixed price per Bbl	$	21.51		$	—		$	—
Average forward propane prices (c)	$	24.26		$	—		$	—
Ethane collar contracts (f)	—			3,000			—		$	—
Weighted average ceiling price per Bbl	$	—		$	11.83		$	—
Weighted average floor price per Bbl	$	—		$	8.68		$	—
Average forward ethane prices (c)	$	—		$	10.76		$	—
Ethane basis swap contracts (MMBtu) (g)	2,768			—			—		$	—
Weighted average fixed price per MMBtu	$	0.91		$	—		$	—
Average forward basis differential prices (h)	$	0.40		$	—		$	—
Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts	70,000			—			—		$	7
Weighted average fixed price per MMBtu	$	4.06		$	—		$	—
Collar contracts with short puts (i)	180,000			130,000			50,000		$	(1	)
Weighted average ceiling price per MMBtu	$	4.01		$	3.39		$	3.40
Weighted average floor price per MMBtu	$	3.24		$	2.85		$	2.75
Weighted average short put price per MMBtu	$	2.78		$	2.41		$	2.25
Average forward NYMEX gas prices (c)	$	3.11		$	3.19		$	3.03
Basis swap contracts									$	(1	)
Gulf Coast index swap contracts (j)	10,000			—			—
Weighted average fixed price per MMBtu	$	—		$	—		$	—
Average forward basis differential prices (h)	$	(0.05	)	$	—		$	—
Mid-Continent index swap contracts (j)	15,000			45,000			—
Weighted average fixed price per MMBtu	$	(0.32	)	$	(0.32	)	$	—
Average forward basis differential prices (h)	$	(0.07	)	$	(0.24	)	$	—
Permian Basin index swap contracts (k)	34,946			9,863			—
Weighted average fixed price per MMBtu	$	0.41		$	0.37		$	—
Average forward basis differential prices (l)	$	0.41		$	0.21		$	—

___________________

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PIONEER NATURAL RESOURCES COMPANY

(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.

(b) During 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl.

(c) The average forward NYMEX oil, propane, ethane and gas prices are based on October 28, 2016 market quotes.

(d) The average forward basis differential prices are based on October 28, 2016 market quotes for basis differentials between the Midland, Texas oil prices and WTI prices at Cushing, Oklahoma.

(e) Represents swaps that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas-posted prices.

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

(g) Represent derivative contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The basis swaps fix the basis differential on a HH MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 2,768 MMBtu per day, which is equivalent to 1,000 Bbls per day of ethane.

(h) The average forward basis differential prices are based on October 28, 2016 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

(i) During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu.

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

(k) Represent swaps 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 October 28, 2016 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 September 30, 2016, 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 its drilling rigs and fracture stimulation fleet equipment. As of September 30, 2016, the Company was party to derivative swap contracts for 1,000 Bbls per day of diesel for 2017 at an average per Bbl fixed price of $60.48. As of September 30, 2016, these positions had an asset fair value of $2 million. Based on October 28, 2016 market quotes, the respective average forward diesel price was $63.00 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 September 30, 2016 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. 

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, 2015, 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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PIONEER NATURAL RESOURCES COMPANY

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 September 30, 2016:

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
July 2016	4,567	$	151.17	—
August 2016	2,525	$	177.18	—
September 2016	916	$	179.10	—
Total	8,008	$	162.57	—	$	—

 ____________________

(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.

41

PIONEER NATURAL RESOURCES COMPANY

Item 6.Exhibits

Exhibits

Exhibit Number		Description
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.

42

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: November 2, 2016	By:	/s/    RICHARD P. DEALY
		Richard P. Dealy,
		Executive Vice President and Chief Financial Officer
Date: November 2, 2016	By:	/s/    MARGARET M. MONTEMAYOR
		Margaret M. Montemayor,
		Vice President and Chief Accounting Officer

43

PIONEER NATURAL RESOURCES COMPANY

Exhibit Index

Exhibit Number		Description
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.

44

EX-12.1

EXHIBIT 12.1

RATIOS OF EARNINGS TO FIXED CHARGES AND EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

The following table sets forth the Company's ratios of consolidated earnings to fixed charges and earnings to fixed charges and preferred stock dividends for the periods presented:

	Nine Months Ended	Year ended December 31,
	September 30, 2016	2015	2014	2013	2012	2011
Ratio of earnings to fixed charges (a)	(b)	(c)	9.45	(d)	4.52	3.49
Ratio of earnings to fixed charges and preferred stock dividends (e)	(b)	(c)	9.45	(d)	4.52	3.49

____________________

(a)	The ratio has been computed by dividing earnings by fixed charges. For purposes of computing the ratio:
	- earnings consist of income from continuing operations before income taxes, cumulative effect of change in accounting principle, adjustments for net income or loss attributable to the noncontrolling interest and the Company's share of investee's income or loss accounted for under the equity method, and adjustment for capitalized interest, plus fixed charges and the Company's share of distributed income from investees accounted for under the equity method; and
	- fixed charges consist of interest expense, capitalized interest and the portion of rental expense deemed to be representative of the interest component of rental expense.
(b)	The ratio indicates a less than one-to-one coverage because the earnings are inadequate to cover the fixed charges during the nine months ended September 30, 2016 by $878 million.
(c)	The ratio indicates a less than one-to-one coverage because the earnings are inadequate to cover the fixed charges during the year ended December 31, 2015 by $432 million.
(d)	The ratio indicates a less than one-to-one coverage because the earnings are inadequate to cover the fixed charges during the year ended December 31, 2013 by $606 million.
(e)	The ratio has been computed by dividing earnings by fixed charges and preferred stock dividends. For purposes of computing the ratio:
	- earnings consist of income from continuing operations before income taxes, cumulative effect of change in accounting principle, adjustments for net income or loss attributable to the noncontrolling interest and the Company's share of investee's income or loss accounted for under the equity method, and adjustment for capitalized interest, plus fixed charges, the Company's share of distributed income from investees accounted for under the equity method and preferred stock dividends, net of preferred stock dividends of a consolidated subsidiary; and
	- fixed charges and preferred stock dividends consist of interest expense, capitalized interest and the portion of rental expense deemed to be representative of the interest component of rental expense, preferred stock dividends of a consolidated subsidiary and preferred stock dividends.

EX-31.1

EXHIBIT 31.1

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Scott D. Sheffield, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Natural Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 2, 2016

/s/ Scott D. Sheffield

Scott D. Sheffield, Chairman and

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CHIEF FINANCIAL OFFICER CERTIFICATION

I, Richard P. Dealy, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Natural Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

November 2, 2016

/s/ Richard P. Dealy

Richard P. Dealy, Executive Vice President

and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Scott D. Sheffield, Chairman and Chief Executive Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Scott D. Sheffield
Name:	Scott D. Sheffield, Chairman and
	Chief Executive Officer
Date:	November 2, 2016

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Richard P. Dealy
Name:	Richard P. Dealy, Executive Vice
	President and Chief Financial Officer
Date:	November 2, 2016

EX-95.1

EXHIBIT 95.1

Mine Safety Disclosure

The following disclosures are provided pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") and Item 104 of Regulation S-K, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (the "Mine Act").

Whenever the Federal Mine Safety and Health Administration ("MSHA") believes a violation of the Mine Act, any health or safety standard or any regulation has occurred, it may issue a citation which describes the alleged violation and fixes a time within which the U.S. mining operator must abate the alleged violation. In some situations, such as when MSHA believes that conditions pose a hazard to miners, MSHA may issue an order removing miners from the area of the mine affected by the condition until the alleged hazards are corrected. When MSHA issues a citation or order, it generally proposes a civil penalty, or fine, as a result of the alleged violation, that the operator is ordered to pay. Citations and orders can be contested and appealed, and as part of that process, are often reduced in severity and amount, and are sometimes dismissed. The number of citations, orders and proposed assessments vary depending on the size and type (underground or surface) of the mine as well as by the MSHA inspector(s) assigned.

The table below sets forth for the three months ended September 30, 2016 for each sand mine of Pioneer Natural Resources Company or its subsidiaries (the "Company"), (i) the total number of citations for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of mine safety or health hazard under section 104 of the Mine Act for which the operator received a citation from MSHA; (ii) the total number of orders issued under section 104(b) of the Mine Act; (iii) the total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act; (iv) the total number of flagrant violations under section 110(b)(2) of the Mine Act; (v) the total number of imminent danger orders issued under section 107(a) of the Mine Act; (vi) the total dollar value of proposed assessments from MSHA; (vii) the total number of mining-related fatalities; (viii) whether or not the mine has received any notices from MSHA of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under section 104(e) of the Mine Act; (ix) whether or not the mine has received any notices from MSHA regarding the potential to have a pattern of violations as referenced in (viii) above; and (x) the total number of pending legal actions before the Federal Mine Safety and Health Review Commission (the "Commission") (as of September 30, 2016) involving such mine, as well as the aggregate number of legal actions instituted and the aggregate number of legal actions resolved during the reporting period. The MSHA citations, orders and assessments are those initially issued or proposed by MSHA. They do not reflect any subsequent changes in the level of severity of a citation or order or the value of an assessment that may occur as a result of proceedings conducted in accordance with MSHA rules.

Mine/MSHA Identification Number(1)	Section  104 S&S Citations	Section 104(b) Orders	Section 104(d) Citations and  Orders	Section 110(b)(2) Violations	Section 107(a) Orders	Total Dollar Value of Proposed Assessments		Mining Related Fatalities	Received Notice of Pattern of Violations under Section 104(e) (yes/no)	Received Notice of Potential to have Pattern under Section 104(e) (yes/no)	Legal Actions Pending as of Last Day of Period	Legal Actions Initiated During Period	Legal Actions Resolved During Period
Riverside Operation / 0404263	—	—	—	—	—	$	—	—	No	No	—	—	—
Colorado Springs Operation / 0503295	—	—	—	—	—	$	—	—	No	No	—	—	—
Millwood Operation / 3301355	3	—	—	—	1	$	727	—	No	No	—	—	—
Voca Pit and Plant / 4101003	3	—	—	—	—	$	355	—	No	No	—	—	—
Brady Plant / 4101371	5	—	—	—	—	$	560	—	No	No	—	—	—
Voca West / 4103618	2	—	—	—	—	$	361	—	No	No	—	—	—

_______________

(1 ) The definition of mine under section three of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools and minerals preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. MSHA assigns an identification number to each mine and may or may not assign separate identification numbers to related facilities such as preparation facilities.

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol	PXD
Entity Registrant Name	PIONEER NATURAL RESOURCES CO
Entity Central Index Key	0001038357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		169,720,677

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents, at Carrying Value	$ 891	$ 1,391
Short-term Investments	1,733	0
Accounts receivable:
Trade, net	447	384
Due from affiliates	0	1
Income taxes receivable	26	43
Inventories	159	155
Prepaid expenses	21	17
Other current assets:
Notes receivable	0	498
Derivatives Assets, Current	172	694
Other	5	11
Total current assets	3,454	3,194
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	18,049	16,631
Unproved properties	486	169
Accumulated depletion, depreciation and amortization	(7,866)	(6,778)
Total property, plant and equipment	10,669	10,022
Long-term Investments	319	0
Goodwill	272	272
Property, Plant and Equipment, Net	1,514	1,523
Other assets:
Derivative Assets, Noncurrent	8	64
Other, net	89	79
Assets, Total	16,325	15,154
Accounts payable:
Trade	685	798
Due to affiliates	98	85
Interest payable	39	65
Income taxes payable	0	2
Current portion of long-term debt	485	448
Other current liabilities:
Derivative Liabilities, Current	7	0
Other	63	64
Total current liabilities	1,377	1,462
Long-term Debt, Excluding Current Maturities	2,726	3,207
Derivative Liabilities, Noncurrent	20	1
Deferred income taxes	1,437	1,776
Other liabilities	334	333
Stockholders' equity:
Common stock, $.01 par value	2	2
Additional paid-in capital	8,867	6,267
Treasury stock at cost	(217)	(199)
Retained earnings	1,772	2,298
Total equity attributable to common stockholders	10,424	8,368
Noncontrolling interests in consolidating subsidiaries	7	7
Total equity	10,431	8,375
Commitments and contingencies
Liabilities and Stockholders' Equity, Total	$ 16,325	$ 15,154

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	173,212,412	152,775,920
Treasury Stock, Shares	3,495,288	3,396,220

XML

Consolidated Statements Of Operations - USD ($) $ in Thousands, shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues and other income:
Oil and gas	$ 643,000	$ 557,000	$ 1,665,000	$ 1,670,000
Sales of purchased oil and gas	444,000	326,000	1,062,000	665,000
Interest and other	7,000	2,000	21,000	16,000
Derivative gains, net	91,000	573,000	(95,000)	617,000
Gain (loss) on disposition of assets, net	1,000	779,000	4,000	782,000
Total revenues and other income	1,186,000	2,237,000	2,657,000	3,750,000
Costs and expenses:
Oil and gas production	141,000	189,000	438,000	532,000
Production and ad valorem taxes	32,000	36,000	97,000	112,000
Depletion, depreciation and amortization	386,000	364,000	1,123,000	1,003,000
Purchased oil and gas	458,000	339,000	1,113,000	684,000
Impairment of oil and gas properties	0	72,000	32,000	210,000
Exploration and abandonments	19,000	25,000	96,000	79,000
General and administrative	82,000	81,000	235,000	246,000
Accretion of discount on asset retirement obligations	5,000	3,000	14,000	9,000
Interest	50,000	46,000	161,000	138,000
Other	69,000	79,000	223,000	186,000
Costs and Expenses	1,242,000	1,234,000	3,532,000	3,199,000
Income (loss) from continuing operations before income taxes	(56,000)	1,003,000	(875,000)	551,000
Income tax provision	78,000	(355,000)	362,000	(195,000)
Income from continuing operations	22,000	648,000	(513,000)	356,000
Loss from discontinued operations, net of tax	0	(2,000)	0	(6,000)
Net income			(513,000)	350,000
Net income (loss) attributable to common stockholders	$ 22,000	$ 646,000	$ (513,000)	$ 350,000
Basic earnings per share:
Income from continuing operations	$ 0.13	$ 4.29	$ (3.10)	$ 2.36
Loss from discontinued operations	0.00	(0.01)	0.00	(0.04)
Net income	0.13	4.28	(3.10)	2.32
Diluted earnings per share:
Income from continuing operations	0.13	4.28	(3.10)	2.36
Income (loss) from discontinued operations	0.00	(0.01)	0.00	(0.04)
Net income	$ 0.13	$ 4.27	$ (3.10)	$ 2.32
Weighted average shares outstanding:
Basic weighted average shares outstanding	170	149	165	149
Diluted	170	150	165	149
Dividends declared per share	$ 0.04	$ 0.04	$ 0.08	$ 0.08
Amounts attributable to common stockholders:
Net income (loss) attributable to common stockholders	$ 22,000	$ 646,000	$ (513,000)	$ 350,000

XML

Consolidated Statement Of Equity - 9 months ended Sep. 30, 2016 - USD ($) shares in Thousands, $ in Millions	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Noncontrolling Interests [Member]
Beginning Balance, shares at Dec. 31, 2015		149,380
Beginning Balance at Dec. 31, 2015	$ 8,375	$ 2	$ 6,267	$ (199)	$ 2,298	$ 7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, New Issues		19,838
Stock Issued During Period, Value, New Issues	2,534	$ 0	2,534
Dividends declared ($0.04 per share)	(13)				(13)
Exercise of long-term incentive plan stock options and employee stock purchases, shares		0
Exercise of long-term incentive plan stock options and employee stock purchases	7		1	6
Treasury stock purchases, shares		(197)
Treasury stock purchases	(24)			(24)
Tax benefit related to stock-based compensation	(1)		(1)
Compensation costs:
Vested compensation awards, net, shares		598
Vested compensation awards, net	0	$ 0	0
Compensation costs included in net income	66		66			0
Net loss	(513)				(513)	0
Ending Balance, shares at Sep. 30, 2016		169,717
Ending Balance at Sep. 30, 2016	$ 10,431	$ 2	$ 8,867	$ (217)	$ 1,772	$ 7

XML

Consolidated Statement Of Equity (Parenthetical) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Stockholders' Equity [Abstract]
Dividends declared per share	$ 0.04	$ 0.04	$ 0.08	$ 0.08

XML

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ (513,000)	$ 350,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	1,123,000	1,003,000
Impairment of oil and gas properties	32,000	210,000
Impairment of Inventory and Other Property and Equipment	6,000	21,000
Exploration expenses, including dry holes	41,000	22,000
Deferred income taxes	(340,000)	146,000
Gain on disposition of assets, net	(4,000)	(782,000)
Accretion of discount on asset retirement obligations	14,000	9,000
Discontinued operations	0	(4,000)
Interest expense	11,000	14,000
Derivative related activity	628,000	(22,000)
Amortization of stock-based compensation	66,000	70,000
Other	51,000	13,000
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(64,000)	26,000
Income taxes receivable	17,000	23,000
Inventories	(7,000)	(29,000)
Prepaid expenses	(4,000)	(3,000)
Derivatives	(24,000)	0
Other current assets	1,000	(6,000)
Accounts payable	(8,000)	(266,000)
Interest payable	(26,000)	(4,000)
Income taxes payable	(2,000)	26,000
Other current liabilities	(38,000)	(28,000)
Net cash provided by operating activities	960,000	789,000
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	503,000	556,000
Business acquisition	(429,000)	0
Proceeds from Sale and Maturity of Held-to-maturity Securities	255,000	0
Purchase of investment securities	(2,300,000)	0
Additions to oil and gas properties	(1,387,000)	(1,573,000)
Additions to other assets and other property and equipment, net	(156,000)	(191,000)
Net cash used in investing activities	(3,514,000)	(1,208,000)
Cash flows from financing activities:
Principal payments on long-term debt	(455,000)	0
Proceeds from issuance of common stock, net of issuance costs	2,534,000	0
Distributions to noncontrolling interests	0	(1,000)
Exercise of long-term incentive plan stock options and employee stock purchases	7,000	6,000
Purchases of treasury stock	(24,000)	(31,000)
Tax (provision) benefits related to stock-based compensation	(1,000)	10,000
Payments of financing fees	0	(3,000)
Dividends paid	(7,000)	(6,000)
Net cash provided by (used in) financing activities	2,054,000	(25,000)
Net increase (decrease) in cash and cash equivalents	(500,000)	(444,000)
Cash and cash equivalents, beginning of period	1,391,000	1,025,000
Cash and cash equivalents, end of period	$ 891,000	$ 581,000

XML

Organization And Nature Of Operations

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization And Nature Of Operations

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 operating in 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.

XML

Basis Of Presentation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis Of Presentation

Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015 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, 2015.

Certain reclassifications have been made to the 2015 financial statement and footnote amounts in order to conform to the 2016 presentation.

Restructuring. In February 2016, the Company announced plans to restructure its pressure pumping operations in South Texas, including relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. In connection therewith, the Company offered severance to certain employees and relocated a number of other employees from its South Texas locations to its operations in the Permian Basin. This initiative was substantially complete as of June 30, 2016.

In connection therewith, during the three and nine months ended September 30, 2016, the Company recognized nil and $4 million, respectively, of restructuring charges in other expense in the accompanying consolidated statements of operations. The restructuring charges for the nine months ended September 30, 2016 included approximately $3 million in cash employee severance costs and $1 million in employee relocation and other costs.

In May 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pressure pumping operations. The restructuring plan was substantially complete as of December 31, 2015. In connection therewith, during the three and nine months ended September 30, 2015, the Company recognized $9 million and $24 million, respectively, of restructuring charges in other expense in the accompanying consolidated statements of operations.

As of September 30, 2016, the Company had $2 million of restructuring liabilities recorded in other current and noncurrent liabilities in the accompanying consolidated balance sheet, primarily related to future lease obligations associated with its Denver, Colorado office.

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 underwriting and offering expenses.

New accounting pronouncements. In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-13, "Financial Instruments - Credit Losses." ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company does not believe this standard will have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Company does not believe this standard will have a material impact on its consolidated financial statements.

In February 2016, 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 is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

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 rescinds 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. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2016

Acquisitions and Divestitures [Abstract]

Acquisition and Divestitures

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 $429 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 preliminary allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date, pending final post-close adjustments:

Assets acquired:
Proved properties	$	79
Unproved properties	348
Other property and equipment	5
Liabilities assumed:
Asset retirement obligations	(3		)
Net assets acquired	$	429

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.

In connection with the acquisition, the Company incurred acquisition related costs (primarily consulting, advisory and legal fees) of approximately $1.0 million. The operating results included in the Company's accompanying consolidated statements of operations from the date of acquisition to September 30, 2016, and the operating results that would have been recognized had the acquisition occurred on January 1, 2016, are not material to the Company's accompanying consolidated statements of operations.

EFS Midstream Divestiture. In July 2015, the Company sold its 50.1 percent equity interest in EFS Midstream LLC ("EFS Midstream") to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion, of which $530 million was received in cash and the remaining $501 million was in the form of a note, which was payable to the Company in July 2016. The Company recorded a net gain on the disposition of $777 million during the three and nine months ended September 30, 2015. In July 2016, the Company received the remaining cash payment of $501 million, which settled the outstanding note receivable.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:

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

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

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

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

The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 for each of the fair value hierarchy levels:

	Fair Value Measurement at September 30, 2016 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 September 30, 2016
	(in millions)
Assets:
Commodity derivatives	$	—	$	180	$	—	$	180
Deferred compensation plan assets	81		—		—		81
Total assets	81		180		—		261
Liabilities:
Commodity derivatives	—		19		—		19
Interest rate derivatives	—		8		—		8
Total liabilities	—		27		—		27
Total recurring fair value measurements	$	81	$	153	$	—	$	234

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("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 September 30, 2016, 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 that are 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.The Company recognized noncash impairment charges of $6 million and $21 million for the nine months ended September 30, 2016 and 2015, respectively, attributable to inventory and other property and equipment.

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 West Panhandle field during the three months ended March 31, 2016 and (ii) the Eagle Ford Shale field, the West Panhandle field and the South Texas - Other field during the year ended December 31, 2015 to their estimated fair values.

The Company calculated the fair values of the West Panhandle field, the Eagle Ford Shale field and the South Texas - Other field 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 estimated fair value.

The following table presents the fair value and fair value adjustments (in millions) for the Company's 2016 and 2015 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in respective Management's Price Outlooks:

							Management's Price Outlooks
	Impairment Date	Fair Value		Fair Value Adjustment			Oil		Gas
West Panhandle	March 2016	$	33	$	(32	)	$	49.77	$	3.24
South Texas - Eagle Ford Shale	December 2015	$	483	$	(846	)	$	52.82	$	3.34
South Texas - Other	September 2015	$	88	$	(72	)	$	57.41	$	3.46
West Panhandle	March 2015	$	61	$	(138	)	$	65.02	$	3.83

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 September 30, 2016 and December 31, 2015 are as follows:

	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Commercial paper, corporate bonds and time deposits	$	2,052	$	2,052	$	275	$	275
Current portion of long-term debt	$	485	$	496	$	448	$	462
Long-term debt	$	2,726	$	3,022	$	3,207	$	3,206

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, which approximates fair value, and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The net carrying value of held-to-maturity investments is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the investments. Income related to these investments is recorded in interest and other income in the Company's consolidated statement of operations. The investments represent Level 2 inputs in the hierarchy. Commercial paper, corporate bonds 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, they 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 September 30, 2016:

	September 30, 2016
Consolidated Balance Sheet Location	Cash		Commercial Paper		Corporate Bonds		Time Deposits		Total
	(in millions)
Cash and cash equivalents	$	891	$	—	$	—	$	—	$	891
Short-term investments	—		742		459		532		1,733
Long-term investments	—		—		319		—		319
	$	891	$	742	$	778	$	532	$	2,943

Debt obligations. Current and noncurrent long-term debt includes the Company's credit facility and the Company's 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, prepaid expenses, 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.

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Derivative Financial Instruments

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

Derivative Financial Instruments

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

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

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

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of September 30, 2016 and the weighted average oil prices for those contracts:

	2016			Year Ending December 31,
	Fourth Quarter			2017
Collar contracts:
Volume (Bbl)	—			6,000
Price per Bbl:
Ceiling	$	—		$	70.40
Floor	$	—		$	50.00
Collar contracts with short puts:
Volume (Bbl) (a)	112,000			94,973
Price per Bbl:
Ceiling	$	75.94		$	62.36
Floor	$	65.41		$	49.07
Short put	$	47.03		$	41.30
Basis swap contracts:
Midland-Cushing index swap volume (Bbl)	6,630			—
Price differential ($/Bbl) (b)	$	(0.80	)	$	—

____________________

(a) During the nine months ended September 30, 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl.

(b) Represents the basis differential between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma.

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 the NGL component price volatility.

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of September 30, 2016 and the weighted average NGL prices for those contracts:

	2016		Year Ending December 31,
	Fourth Quarter		2017
Propane swap contracts (a):
Volume (Bbl)	6,000		—
Price per Bbl	$	21.51	$	—
Ethane collar contracts (b):
Volume (Bbl)	—		3,000
Price per Bbl:
Ceiling	$	—	$	11.83
Floor	$	—	$	8.68
Ethane basis swap contracts (c):
Volume (MMBtu)	2,768		—
Price differential ($/MMBtu)	$	0.91	$	—

 ____________________

(a) Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas posted prices.

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

(c) 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 swaps 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 2,768 MMBtu per day, which is equivalent to 1,000 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 the actual index prices at which the gas is sold.

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of September 30, 2016 and the weighted average gas prices for those contracts:

	2016			Year Ending December 31,
	Fourth Quarter			2017			2018
Swap contracts:
Volume (MMBtu)	70,000			—			—
Price per MMBtu	$	4.06		$	—		$	—
Collar contracts with short puts:
Volume (MMBtu) (a)	180,000			130,000			50,000
Price per MMBtu:
Ceiling	$	4.01		$	3.39		$	3.40
Floor	$	3.24		$	2.85		$	2.75
Short put	$	2.78		$	2.41		$	2.25
Basis swap contracts:
Gulf Coast index swap volume (b)	10,000			—			—
Price differential ($/MMBtu)	$	—		$	—		$	—
Mid-Continent index swap volume (b)	15,000			45,000			—
Price differential ($/MMBtu)	$	(0.32	)	$	(0.32	)	$	—
Permian Basin index swap volume (c)	34,946			9,863			—
Price differential ($/MMBtu)	$	0.41		$	0.37		$	—

____________________

(a) During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu.

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

(c) Represent swaps 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 September 30, 2016, 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 its drilling rigs and fracture stimulation fleet equipment. As of September 30, 2016, the Company was party to derivative swap contracts for 1,000 Bbls per day of diesel for 2017 at an average per Bbl fixed price of $60.48.

Interest rate derivative activities. As of September 30, 2016, the Company was a party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 to December 2027 in exchange for paying a weighted average fixed interest rate of 1.94 percent on a notional amount of $250 million on December 15, 2017.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives 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.

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 September 30, 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	$	190	$	(18	)	$	172
Commodity price derivatives	Derivatives - noncurrent	$	11	$	(3	)	8
							$	180
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	25	$	(18	)	$	7
Commodity price derivatives	Derivatives - noncurrent	$	15	$	(3	)	12
Interest rate derivatives	Derivatives - noncurrent	$	8	$	—		8
							$	27

Fair Value of Derivative Instruments as of December 31, 2015
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	$	695	$	(1	)	$	694
Commodity price derivatives	Derivatives - noncurrent	$	64	$	—		64
							$	758
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	1	$	(1	)	$	—
Commodity price derivatives	Derivatives - noncurrent	$	1	$	—		1
							$	1

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.

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 September 30,					Nine Months Ended September 30,
Hedging Instruments	Earnings on Derivatives	2016		2015			2016			2015
		(in millions)
Commodity price derivatives	Derivative gains (losses), net	$	91	$	575		$	(87	)	$	614
Interest rate derivatives	Derivative gains (losses), net	—		(2		)	(8		)	3
Total		$	91	$	573		$	(95	)	$	617

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Exploratory Costs

9 Months Ended

Sep. 30, 2016

Exploratory Cost Disclosure [Abstract]

Exploratory Costs

Exploratory Costs

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

The following table reflects the Company's capitalized exploratory well and project activity during the three and nine months ended September 30, 2016:

	Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
	(in millions)
Beginning capitalized exploratory costs	$	357		$	306
Additions to exploratory costs pending the determination of proved reserves	328			991
Reclassification due to determination of proved reserves	(286		)	(898		)
Exploratory well costs charged to exploration expense	(1		)	(1		)
Ending capitalized exploratory costs	$	398		$	398

The following table provides an aging, as of September 30, 2016 and December 31, 2015 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:

	September 30, 2016		December 31, 2015
	(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	396	$	303
More than one year	2		3
	$	398	$	306
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year	1		1

The well that was suspended for a period greater than one year as of September 30, 2016 is in the Eagle Ford Shale area.The Company expects to complete this well in 2017.

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Long-Term Debt

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt

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 September 30, 2016, the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants.

Senior notes. The Company's 5.875% senior notes (the "5.875% Senior Notes") matured and were repaid in July 2016. The Company funded the $455 million repayment of the 5.875% Senior Notes with cash on hand. The Company's 6.65% senior notes, with an outstanding debt principal balance of $485 million, will mature in March 2017 and are classified as current in the accompanying consolidated balance sheets as of September 30, 2016.

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Incentive Plans

9 Months Ended

Sep. 30, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Incentive Plans

Incentive Plans

Stock-based compensation

For the three and nine months ended September 30, 2016, the Company recorded $31 million and $84 million, respectively, of stock-based compensation expense for all plans, as compared to $26 million and $87 million for the same respective periods in 2015. As of September 30, 2016, there was $138 million of unrecognized compensation expense related to unvested share-based compensation plan awards, including $36 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 over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of September 30, 2016 and December 31, 2015, accounts payable – due to affiliates included $17 million and $16 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the nine months ended September 30, 2016 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, 2015	1,081,650		271,031		148,547		199,058
Awards granted	520,980		180,383		104,114		—
Awards vested	(459,833	)	(141,441	)	(8,670	)	—
Awards forfeited	(43,996	)	(14,067	)	(4,821	)	—
Outstanding as of September 30, 2016	1,098,801		295,906		239,170		199,058

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The following table summarizes the Company's asset retirement obligation activity during the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)
Beginning asset retirement obligations	$	281		$	187		$	285		$	189
Liabilities assumed in acquisitions	3			—			3			—
New wells placed on production	—			1			—			2
Liabilities settled	(8		)	(9		)	(21		)	(18		)
Accretion of discount	5			3			14			9
Ending asset retirement obligations	$	281		$	182		$	281		$	182

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 September 30, 2016 and December 31, 2015, the current portion of the Company's asset retirement obligations was $40 million.

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

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.

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Interest And Other Income

9 Months Ended

Sep. 30, 2016

Interest and Other Income [Abstract]

Interest And Other Income

Interest and Other Income

The following table provides the components of the Company's interest and other income for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in millions)
Interest income	$	5	$	2	$	14	$	2
Deferred compensation plan income	—		—		2		4
Equity interest in income of EFS Midstream (a)	—		—		—		5
Other income	2		—		5		5
Total interest and other income	$	7	$	2	$	21	$	16

 ____________________

(a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream.

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Other Expense

9 Months Ended

Sep. 30, 2016

Other Expense [Abstract]

Other Expense

Other Expense

The following table provides the components of the Company's other expense for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in millions)
Transportation commitment charges (a)	$	27	$	11	$	77	$	38
Loss from vertical integration services (b)	17		20		46		16
Idle drilling and well service equipment charges (c)	10		22		42		73
Terminated drilling rig charges (d)	—		—		15		—
Impairment of inventory and other property and equipment (e)	1		13		6		21
Restructuring charges (f)	—		9		4		24
Other	14		4		33		14
Total other expense	$	69	$	79	$	223	$	186

 ____________________

(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 service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three and nine months ended September 30, 2016, these vertical integration net margins included $19 million and $144 million, respectively, of revenues and $36 million and $190 million, respectively, of costs and expenses. For the same respective periods in 2015, these vertical integration net margins included $66 million and $264 million of revenues and $86 million and $280 million of costs and expenses.

(c) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations.

(d) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

(e) Primarily represents charges to reduce excess material and supplies inventories to their market values. See Note D for additional information on the fair value of materials and supplies inventory.

(f) Represents costs associated with the Company's restructuring of its pressure pumping operations in South Texas in 2016 and its operations in Colorado in 2015. See Note B for additional information on the restructuring charges.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company's income tax benefit attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
	(in millions)
Current tax benefit (provision)	$	22	$	(48	)	$	22	$	(49	)
Deferred tax benefit (provision)	56		(307		)	340		(146		)
Income tax benefit (provision)	$	78	$	(355	)	$	362	$	(195	)

For the three and nine months ended September 30, 2016, the Company's effective tax rates, excluding income attributable to noncontrolling interests, were 140 percent and 41 percent, respectively, as compared to an effective rate of 35 percent for each of the the same respective periods in 2015. The Company's effective tax rates for the three and nine months ended September 30, 2016 differ from the U.S. statutory rate of 35 percent primarily due to recognizing research and experimental expenditures credits of $59 million in the third quarter of 2016, and, to a lesser extent, state income tax apportionments and nondeductible expenses.

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 September 30, 2016, the Company had unrecognized tax benefits of $94 million resulting from research and experimental expenditures related to horizontal drilling and completions innovations. If all of, 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 September 2017. There were no unrecognized tax benefits as of December 31, 2015.

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 2013 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 2010. As of September 30, 2016, 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.

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Net Income Per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Net Income Per Share

Net Income (Loss) Per Share

The following table reconciles the Company's income (loss) from continuing operations to basic and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016			2015
	(in millions)
Income (loss) from continuing operations	$	22	$	648		$	(513	)	$	356
Participating basic earnings	—		(6		)	—			(3		)
Basic and diluted income (loss) from continuing operations	$	22	$	642		(513		)	353
Basic and diluted loss from discontinued operations	$	—	$	(2	)	$	—		$	(6	)
Basic and diluted net income (loss) attributable to common stockholders	$	22	$	640		$	(513	)	$	347

Basic and diluted weighted average common shares outstanding were 170 million and 165 million, respectively, for the three and nine months ended September 30, 2016. Basic weighted average common shares outstanding were 149 million for both the three and nine months ended September 30, 2015, and diluted weighted average shares outstanding were 150 million and 149 million for the three and nine months ended September 30, 2015, respectively.

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Basis Of Presentation (Policies)

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2016 and for the three and nine months ended September 30, 2016 and 2015 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, 2015.

Certain reclassifications have been made to the 2015 financial statement and footnote amounts in order to conform to the 2016 presentation.

New Accounting Pronouncements, Policy [Policy Text Block]

New accounting pronouncements. In June 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-13, "Financial Instruments - Credit Losses." ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard's provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company does not believe this standard will have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Company does not believe this standard will have a material impact on its consolidated financial statements.

In February 2016, 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 is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

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 rescinds 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. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 30, 2016

Acquisitions and Divestitures [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The following table represents the preliminary allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date, pending final post-close adjustments:

Assets acquired:
Proved properties	$	79
Unproved properties	348
Other property and equipment	5
Liabilities assumed:
Asset retirement obligations	(3		)
Net assets acquired	$	429

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Schedule of assets and liabilities measured at fair value on a recurring basis

The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2016 for each of the fair value hierarchy levels:

	Fair Value Measurement at September 30, 2016 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 September 30, 2016
	(in millions)
Assets:
Commodity derivatives	$	—	$	180	$	—	$	180
Deferred compensation plan assets	81		—		—		81
Total assets	81		180		—		261
Liabilities:
Commodity derivatives	—		19		—		19
Interest rate derivatives	—		8		—		8
Total liabilities	—		27		—		27
Total recurring fair value measurements	$	81	$	153	$	—	$	234

Fair Value Measurements, Nonrecurring [Table Text Block]

The following table presents the fair value and fair value adjustments (in millions) for the Company's 2016 and 2015 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in respective Management's Price Outlooks:

							Management's Price Outlooks
	Impairment Date	Fair Value		Fair Value Adjustment			Oil		Gas
West Panhandle	March 2016	$	33	$	(32	)	$	49.77	$	3.24
South Texas - Eagle Ford Shale	December 2015	$	483	$	(846	)	$	52.82	$	3.34
South Texas - Other	September 2015	$	88	$	(72	)	$	57.41	$	3.46
West Panhandle	March 2015	$	61	$	(138	)	$	65.02	$	3.83

Schedule of carrying values and 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 September 30, 2016 and December 31, 2015 are as follows:

	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Commercial paper, corporate bonds and time deposits	$	2,052	$	2,052	$	275	$	275
Current portion of long-term debt	$	485	$	496	$	448	$	462
Long-term debt	$	2,726	$	3,022	$	3,207	$	3,206

Cash, Cash Equivalents and Investments [Table Text Block]

The following table provides the components of the Company's cash and cash equivalents and investments as of September 30, 2016:

	September 30, 2016
Consolidated Balance Sheet Location	Cash		Commercial Paper		Corporate Bonds		Time Deposits		Total
	(in millions)
Cash and cash equivalents	$	891	$	—	$	—	$	—	$	891
Short-term investments	—		742		459		532		1,733
Long-term investments	—		—		319		—		319
	$	891	$	742	$	778	$	532	$	2,943

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Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of oil derivative contracts volume and weighted average price

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of September 30, 2016 and the weighted average oil prices for those contracts:

	2016			Year Ending December 31,
	Fourth Quarter			2017
Collar contracts:
Volume (Bbl)	—			6,000
Price per Bbl:
Ceiling	$	—		$	70.40
Floor	$	—		$	50.00
Collar contracts with short puts:
Volume (Bbl) (a)	112,000			94,973
Price per Bbl:
Ceiling	$	75.94		$	62.36
Floor	$	65.41		$	49.07
Short put	$	47.03		$	41.30
Basis swap contracts:
Midland-Cushing index swap volume (Bbl)	6,630			—
Price differential ($/Bbl) (b)	$	(0.80	)	$	—

____________________

(a) During the nine months ended September 30, 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl.

(b) Represents the basis differential between Midland, Texas oil prices and WTI prices at Cushing, Oklahoma.

Schedule of NGL derivative volumes and weighted average prices

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of September 30, 2016 and the weighted average NGL prices for those contracts:

	2016		Year Ending December 31,
	Fourth Quarter		2017
Propane swap contracts (a):
Volume (Bbl)	6,000		—
Price per Bbl	$	21.51	$	—
Ethane collar contracts (b):
Volume (Bbl)	—		3,000
Price per Bbl:
Ceiling	$	—	$	11.83
Floor	$	—	$	8.68
Ethane basis swap contracts (c):
Volume (MMBtu)	2,768		—
Price differential ($/MMBtu)	$	0.91	$	—

 ____________________

(a) Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas posted prices.

Schedule of gas derivative volume and weighted average prices

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of September 30, 2016 and the weighted average gas prices for those contracts:

	2016			Year Ending December 31,
	Fourth Quarter			2017			2018
Swap contracts:
Volume (MMBtu)	70,000			—			—
Price per MMBtu	$	4.06		$	—		$	—
Collar contracts with short puts:
Volume (MMBtu) (a)	180,000			130,000			50,000
Price per MMBtu:
Ceiling	$	4.01		$	3.39		$	3.40
Floor	$	3.24		$	2.85		$	2.75
Short put	$	2.78		$	2.41		$	2.25
Basis swap contracts:
Gulf Coast index swap volume (b)	10,000			—			—
Price differential ($/MMBtu)	$	—		$	—		$	—
Mid-Continent index swap volume (b)	15,000			45,000			—
Price differential ($/MMBtu)	$	(0.32	)	$	(0.32	)	$	—
Permian Basin index swap volume (c)	34,946			9,863			—
Price differential ($/MMBtu)	$	0.41		$	0.37		$	—

____________________

(a) During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu.

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

(c) Represent swaps 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.

Offsetting Asset and Liability

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 September 30, 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	$	190	$	(18	)	$	172
Commodity price derivatives	Derivatives - noncurrent	$	11	$	(3	)	8
							$	180
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	25	$	(18	)	$	7
Commodity price derivatives	Derivatives - noncurrent	$	15	$	(3	)	12
Interest rate derivatives	Derivatives - noncurrent	$	8	$	—		8
							$	27

Fair Value of Derivative Instruments as of December 31, 2015
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	$	695	$	(1	)	$	694
Commodity price derivatives	Derivatives - noncurrent	$	64	$	—		64
							$	758
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	1	$	(1	)	$	—
Commodity price derivatives	Derivatives - noncurrent	$	1	$	—		1
							$	1

Schedule of derivative gains and losses recognized on statement of operations

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 September 30,					Nine Months Ended September 30,
Hedging Instruments	Earnings on Derivatives	2016		2015			2016			2015
		(in millions)
Commodity price derivatives	Derivative gains (losses), net	$	91	$	575		$	(87	)	$	614
Interest rate derivatives	Derivative gains (losses), net	—		(2		)	(8		)	3
Total		$	91	$	573		$	(95	)	$	617

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Exploratory Costs (Tables)

9 Months Ended

Sep. 30, 2016

Exploratory Cost Disclosure [Abstract]

Capitalized exploratory well and project activity

The following table reflects the Company's capitalized exploratory well and project activity during the three and nine months ended September 30, 2016:

	Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
	(in millions)
Beginning capitalized exploratory costs	$	357		$	306
Additions to exploratory costs pending the determination of proved reserves	328			991
Reclassification due to determination of proved reserves	(286		)	(898		)
Exploratory well costs charged to exploration expense	(1		)	(1		)
Ending capitalized exploratory costs	$	398		$	398

Capitalized Exploratory Costs And The Number Of Projects For Which Exploratory Costs Have Been Capitalized

The following table provides an aging, as of September 30, 2016 and December 31, 2015 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:

	September 30, 2016		December 31, 2015
	(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	396	$	303
More than one year	2		3
	$	398	$	306
Number of wells or projects with exploratory well costs that have been suspended for a period greater than one year	1		1

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Incentive Plans (Tables)

9 Months Ended

Sep. 30, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Share Based Incentive Award Activity

The following table summarizes the activity that occurred during the nine months ended September 30, 2016 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, 2015	1,081,650		271,031		148,547		199,058
Awards granted	520,980		180,383		104,114		—
Awards vested	(459,833	)	(141,441	)	(8,670	)	—
Awards forfeited	(43,996	)	(14,067	)	(4,821	)	—
Outstanding as of September 30, 2016	1,098,801		295,906		239,170		199,058

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation [Abstract]

Schedule of asset retirement obligations

The following table summarizes the Company's asset retirement obligation activity during the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)
Beginning asset retirement obligations	$	281		$	187		$	285		$	189
Liabilities assumed in acquisitions	3			—			3			—
New wells placed on production	—			1			—			2
Liabilities settled	(8		)	(9		)	(21		)	(18		)
Accretion of discount	5			3			14			9
Ending asset retirement obligations	$	281		$	182		$	281		$	182

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Interest And Other Income (Tables)

9 Months Ended

Sep. 30, 2016

Interest and Other Income [Abstract]

Components of interest and other income

The following table provides the components of the Company's interest and other income for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in millions)
Interest income	$	5	$	2	$	14	$	2
Deferred compensation plan income	—		—		2		4
Equity interest in income of EFS Midstream (a)	—		—		—		5
Other income	2		—		5		5
Total interest and other income	$	7	$	2	$	21	$	16

 ____________________

(a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream.

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Other Expense (Tables)

9 Months Ended

Sep. 30, 2016

Other Expense [Abstract]

Schedule of components of other expense

The following table provides the components of the Company's other expense for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(in millions)
Transportation commitment charges (a)	$	27	$	11	$	77	$	38
Loss from vertical integration services (b)	17		20		46		16
Idle drilling and well service equipment charges (c)	10		22		42		73
Terminated drilling rig charges (d)	—		—		15		—
Impairment of inventory and other property and equipment (e)	1		13		6		21
Restructuring charges (f)	—		9		4		24
Other	14		4		33		14
Total other expense	$	69	$	79	$	223	$	186

 ____________________

(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 service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three and nine months ended September 30, 2016, these vertical integration net margins included $19 million and $144 million, respectively, of revenues and $36 million and $190 million, respectively, of costs and expenses. For the same respective periods in 2015, these vertical integration net margins included $66 million and $264 million of revenues and $86 million and $280 million of costs and expenses.

(c) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations.

(d) Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

(e) Primarily represents charges to reduce excess material and supplies inventories to their market values. See Note D for additional information on the fair value of materials and supplies inventory.

(f) Represents costs associated with the Company's restructuring of its pressure pumping operations in South Texas in 2016 and its operations in Colorado in 2015. See Note B for additional information on the restructuring charges.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income tax (provisions) benefits attributable to income from continuing operations

The Company's income tax benefit attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
	(in millions)
Current tax benefit (provision)	$	22	$	(48	)	$	22	$	(49	)
Deferred tax benefit (provision)	56		(307		)	340		(146		)
Income tax benefit (provision)	$	78	$	(355	)	$	362	$	(195	)

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Net Income Per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Reconciliation of earnings attributable to common stockholders, basic and diluted

The following table reconciles the Company's income (loss) from continuing operations to basic and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2016 and 2015:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016			2015
	(in millions)
Income (loss) from continuing operations	$	22	$	648		$	(513	)	$	356
Participating basic earnings	—		(6		)	—			(3		)
Basic and diluted income (loss) from continuing operations	$	22	$	642		(513		)	353
Basic and diluted loss from discontinued operations	$	—	$	(2	)	$	—		$	(6	)
Basic and diluted net income (loss) attributable to common stockholders	$	22	$	640		$	(513	)	$	347

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Basis Of Presentation Basis of Presentation (Narrative) (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2016	Sep. 30, 2015
Summary Of Significant Accounting Policies [Line Items]
Stock Issued During Period, Shares, New Issues	6.0	13.8
Proceeds from issuance of common stock, net of issuance costs	$ 937	$ 1,600	$ 2,534	$ 0

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Basis Of Presentation Basis of Presentation (Restructuring) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Restructuring Cost and Reserve [Line Items]
Restructuring Charges	$ 0	$ 9	$ 4	$ 24
Restructuring Reserve	$ 2		2
Employee Severance [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Charges			3
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Charges			$ 1

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Acquisitions and Divestitures Acquisitions and Divestitures (Business Combination) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($) a Boe	Sep. 30, 2015 USD ($)
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired	$ 429.0	$ 0.0
Permian Basin [Member]
Business Acquisition [Line Items]
Oil and gas acres acquired | a	28,000
Production, Barrels of Oil Equivalents | Boe	1,400
Payments to Acquire Businesses, Net of Cash Acquired	$ 429.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	79.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	348.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Buildings	5.0
AssetRetirementObligationLiabilitiesAcquiredInBusinessCombination	(3.0)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	429.0
Business Acquisition, Transaction Costs	$ 1.0

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Acquisitions and Divestitures (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Ownership Percentage			50.10%
Equity Method Investment, Net Sales Proceeds		$ 1,000
Equity Method Investment, Realized Gain (Loss) on Disposal		777
Proceeds Received Prior Year [Member]
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Net Sales Proceeds		530
Proceeds Received Current Year [Member]
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Net Sales Proceeds	$ 501
Proceeds To Be Received In Future Year [Member] [Member]
Acquisitions and Divestitures [Line Items]
Equity Method Investment, Net Sales Proceeds		$ 501

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Fair Value Measurements (Schedule Of Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) $ in Millions	Sep. 30, 2016 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	$ 81
Assets, Fair Value Disclosure	261
Liabilities, Fair Value Disclosure	27
Recurring Measurements, (Fair Value, Total)	234
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	81
Assets, Fair Value Disclosure	81
Liabilities, Fair Value Disclosure	0
Recurring Measurements, (Fair Value, Total)	81
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	0
Assets, Fair Value Disclosure	180
Liabilities, Fair Value Disclosure	27
Recurring Measurements, (Fair Value, Total)	153
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Deferred Compensation Plan Assets	0
Assets, Fair Value Disclosure	0
Liabilities, Fair Value Disclosure	0
Recurring Measurements, (Fair Value, Total)	0
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	180
Derivative Liability, Fair Value, Net	19
Commodity Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	0
Derivative Liability, Fair Value, Net	0
Commodity Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	180
Derivative Liability, Fair Value, Net	19
Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Net	0
Derivative Liability, Fair Value, Net	0
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	8
Interest Rate Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	0
Interest Rate Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	8
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Fair Value, Net	$ 0

XML

Fair Value Measurements Fair Value Measurements (Nonrecurring Fair Value Measurements) (Details) $ in Thousands		3 Months Ended					9 Months Ended
		Sep. 30, 2016 USD ($)	Mar. 31, 2016 USD ($) $ / MMBTU $ / bbl	Dec. 31, 2015 USD ($) $ / MMBTU $ / bbl	Sep. 30, 2015 USD ($) $ / MMBTU $ / bbl	Mar. 31, 2015 USD ($) $ / MMBTU $ / bbl	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Tangible Asset Impairment Charges	[1]	$ 1,000			$ 13,000		$ 6,000	$ 21,000
Impairment of oil and gas properties		$ 0			$ (72,000)		$ (32,000)	(210,000)
Management oil price outlook | $ / bbl			49.77	52.82	57.41	65.02
Management gas price outlook | $ / MMBTU			3.24	3.34	3.46	3.83
Impairment of Long-Lived Assets Held-for-use			$ 32,000
West Panhandle [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group			33,000			$ 61,000
Impairment of oil and gas properties			$ (32,000)			$ (138,000)
South Texas Eagle Ford Shale [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group				$ 483,000
Impairment of oil and gas properties				$ (846,000)
South Texas Edwards And Austin Chalk [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Asset Group					$ 88,000			$ 88,000
Impairment of oil and gas properties					$ (72,000)

[1] Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

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Fair Value Measurements (Schedule Of Carrying Values And Financial Instruments Not Carried At Fair Value) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Excluding Current Maturities	$ 2,726	$ 3,207
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	2,052	275
Debt, Current	485	448
Long-term Debt, Excluding Current Maturities	2,726	3,207
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	2,052	275
Debt, Current	496	462
Long-term Debt, Excluding Current Maturities	$ 3,022	$ 3,206

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Fair Value Measurements Fair Value Measurements (Schedule of Cash and Cash Equivalents and Investments) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	$ 891	$ 1,391	$ 581	$ 1,025
Short-term Investments	1,733	0
Long-term Investments	319	$ 0
Cash, Cash Equivalents, and Short-term Investments	2,943
Cash and Cash Equivalents [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	891
Short-term Investments	0
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	891
Commercial Paper [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	0
Short-term Investments	742
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	742
Corporate Bond Securities [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	0
Short-term Investments	459
Long-term Investments	319
Cash, Cash Equivalents, and Short-term Investments	778
Bank Time Deposits [Member]
Schedule of Held-to-maturity Securities [Line Items]
Cash and cash equivalents, at Carrying Value	0
Short-term Investments	532
Long-term Investments	0
Cash, Cash Equivalents, and Short-term Investments	$ 532

XML

Derivative Financial Instruments (Narrative) (Details) $ in Millions	Sep. 30, 2016 USD ($) bbl / d $ / bbl Rate
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Fixed Interest Rate | Rate	1.94%
Notional amount of debt | $	$ 250
Diesel Swap Year 2 [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	60.48

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Derivative Financial Instruments (Schedule Of Oil Derivative Contracts Volume And Weighted Average Prices) (Details) $ in Millions		9 Months Ended
		Sep. 30, 2016 USD ($) bbl / d $ / bbl	Oct. 28, 2016 bbl / d $ / bbl
Oil contracts [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		0
Oil contracts [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		6,630
Oil contracts [Member] | Collar Contracts With Short Puts for Year 2 - Converted [Member]
Derivative [Line Items]
Premium Paid on Derivative Contract | $		$ 24
Derivative, Nonmonetary Notional Amount | bbl / d	[1]	33,000
Oil contracts [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	[1]	94,973
Oil contracts [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		6,000
Oil contracts [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d		112,000
Oil contracts, price per bbl [Member] | Basis Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price		0
Oil contracts, price per bbl [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price		(1)
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for Year 2 - Converted [Member]
Derivative [Line Items]
Derivative, Average Cap Price		60.76
Derivative, Average Floor Price		45.00
Derivative, Notional Amount, Price Per Unit		40.00
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price		62.36
Derivative, Average Floor Price		49.07
Derivative, Notional Amount, Price Per Unit		41.30
Oil contracts, price per bbl [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price		70.40
Derivative, Average Floor Price		50.00
Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Average Cap Price		75.94
Derivative, Average Floor Price		65.41
Derivative, Notional Amount, Price Per Unit		47.03
Subsequent Event [Member] | Oil contracts [Member] | Collar Contracts With Short Puts for January to June Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			20,000
Subsequent Event [Member] | Oil contracts [Member] | Collar Contracts With Short Puts for July to December Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			32,000
Subsequent Event [Member] | Oil contracts [Member] | Collar Contracts With Short Puts for Year 3 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d			20,000
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for January to June Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount			39.00
Derivative, Average Cap Price			58.99
Derivative, Average Floor Price			48.50
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for July to December Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount			40.00
Derivative, Average Cap Price			60.77
Derivative, Average Floor Price			50.00
Subsequent Event [Member] | Oil contracts, price per bbl [Member] | Collar Contracts With Short Puts for Year 3 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount			40.00
Derivative, Average Cap Price			65.14
Derivative, Average Floor Price			50.00

[1] During the nine months ended September 30, 2016, the Company paid $24 million to convert 33,000 Bbls per day of 2017 collar contracts with short puts into new 2017 collar contracts with short puts with a ceiling price of $60.76 per Bbl, a floor price of $45.00 per Bbl and a short put price of $40.00 per Bbl. During the period from October 1, 2016 through October 28, 2016, the Company entered into additional oil collar contracts with short puts for (i) 20,000 Bbls per day of January through June 2017 production with a ceiling price of $58.99 per Bbl, a floor price of $48.50 per Bbl and a short put price of $39.00 per Bbl, (ii) 32,000 Bbls per day of July through December 2017 production with a ceiling price of $60.77 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl and (iii) 20,000 Bbls per day of 2018 production with a ceiling price of $65.14 per Bbl, a floor price of $50.00 per Bbl and a short put price of $40.00 per Bbl.

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Derivative Financial Instruments Derivative Financial Instruments (Schedule of NGL Derivative Contracts Volume and Weighted Average Prices) (Details)	Sep. 30, 2016 bbl / d MMBTU / d $ / MMBTU $ / bbl
NGL contract, in BBLS [Member] | Basis Swap Contracts for Current Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	1,000
NGL contract, in BBLS [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	3,000
NGL contract, in BBLS [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	6,000
NGL contracts, price per BBL [Member] | Collar Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Average Cap Price | $ / bbl	11.83
Derivative, Average Floor Price | $ / bbl	8.68
NGL contracts, price per BBL [Member] | Swap Contracts For Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	21.51
NGL contracts, price per BBL [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	0.91
NGL contract, MMBtu Equivalent [Member] | Basis Swap Contracts for Current Year [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	2,768
NGL contract, MMBtu Equivalent [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	2,768
Propane [Member] | NGL contract, in BBLS [Member] | Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl / d	0
Propane [Member] | NGL contracts, price per BBL [Member] | Swap Contracts for Year 2 [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price | $ / bbl	0.00

XML

Derivative Financial Instruments Derivative Financial Instruments (Schedule of Gas Derivative Contracts Volume and Weighted Average Prices) (Details)		Oct. 28, 2016 MMBTU / d $ / MMBTU	Sep. 30, 2016 MMBTU / d $ / MMBTU
Swap Contracts For Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			70,000
Swap Contracts For Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			4.06
Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			130,000
Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			3.39
Derivative, Average Floor Price			2.85
Derivative, Notional Amount, Price Per Unit			2.41
Collar Contracts With Short Puts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			50,000
Collar Contracts With Short Puts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			3.40
Derivative, Average Floor Price			2.75
Derivative, Notional Amount, Price Per Unit			2.25
Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.00
Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.00
Collar Contracts With Short Puts For Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			180,000
Collar Contracts With Short Puts For Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price			4.01
Derivative, Average Floor Price			3.24
Derivative, Notional Amount, Price Per Unit			2.78
Subsequent Event [Member] | Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d		50,000
Subsequent Event [Member] | Collar Contracts With Short Puts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Average Cap Price		3.76
Derivative, Average Floor Price		3.06
Derivative, Notional Amount, Price Per Unit		2.50
Gulf Coast [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			10,000
Gulf Coast [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.00
Gulf Coast [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Gulf Coast [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.00
Gulf Coast [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		0
Gulf Coast [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.00
Mid-Continent [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			15,000
Mid-Continent [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1]		45,000
Mid-Continent [Member] | Basis Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			(0.32)
Mid-Continent [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d	[1],[2]		0
Mid-Continent [Member] | Basis Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.00
Permian Basin [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			34,946
Permian Basin [Member] | Basis Swap Contracts for Fourth Quarter of Year One [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.41
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 2 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			9,863
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 2 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.37
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 3 [Member] | Gas contracts, in MMBTU [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU / d			0
Permian Basin [Member] | So Cal Basis Swap Contracts for Year 3 [Member] | Gas contracts, price per MMBTU [Member]
Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price			0.00

[1] (a)During the period from October 1, 2016 through October 28, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2017 production with a ceiling price of $3.76 per MMBtu, a floor price of $3.06 per MMBtu and a short put price of $2.50 per MMBtu.

[2] Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts.

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Derivative Financial Instruments (Schedule Of Derivative Instruments) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Assets, Current	$ 172	$ 694
Derivative Assets, Noncurrent	8	64
Derivative Liabilities, Current	7	0
Derivative Liabilities, Noncurrent	20	1
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Net	180	758
Derivative Liability, Fair Value, Net	27	1
Not Designated as Hedging Instrument [Member] | Commodity Price Derivatives [Member] | Derivatives - Current [Member]
Derivative [Line Items]
Total derivatives, Asset, Gross	190	695
Derivative Liability, Fair Value, Gross Liability	25	1
Derivative Assets Offset In Balance Sheet	(18)	(1)
Derivative Liabilities Offset In Balance Sheet	(18)	(1)
Derivative Assets, Current	172	694
Derivative Liabilities, Current	7	0
Not Designated as Hedging Instrument [Member] | Commodity Price Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Total derivatives, Asset, Gross	11	64
Derivative Liability, Fair Value, Gross Liability	15	1
Derivative Assets Offset In Balance Sheet	(3)	0
Derivative Liabilities Offset In Balance Sheet	(3)	0
Derivative Assets, Noncurrent	8	64
Derivative Liabilities, Noncurrent	12	$ 1
Not Designated as Hedging Instrument [Member] | Interest Rate Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	8
Derivative Liabilities Offset In Balance Sheet	0
Derivative Liabilities, Noncurrent	$ 8

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Derivative Financial Instruments (Schedule Of Derivative Obligations Under Terminated Hedge Arrangements) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative [Line Items]
Derivative gains, net	$ 91	$ 573	$ (95)	$ 617
Commodity Price Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	91	575	(87)	614
Interest Rate Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Derivative gains, net	$ 0	$ (2)	$ (8)	$ 3

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Exploratory Costs (Schedule Of Capitalized Exploratory Well And Project Activity) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Beginning capitalized exploratory costs	$ 357	$ 306
Additions to exploratory costs pending the determination of proved reserves	328	991
Reclassification due to determination of proved reserves	(286)	(898)
Exploratory well costs charged to exploration expense	(1)	(1)
Ending capitalized exploratory costs	$ 398	$ 398

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Exploratory Costs Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)
Property, Plant and Equipment [Line Items]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period of One Year or Less	$ 396		$ 303
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	2		3
Capitalized Exploratory Well Costs	$ 398	$ 357	$ 306
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects	1		1

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Long-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Jun. 30, 2016
Debt Instrument [Line Items]
Maximum Borrowing Capacity	$ 1,500	$ 1,500
Outstanding borrowing	0	0
Repayments of Long-term Debt		$ 455	$ 0
Five Point Eight Seven Five Percent Senior Notes Due Two Thousand Sixteen [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				5.875%
Repayments of Long-term Debt	$ 455
Six Point Six Five Percent Senior Notes Due Two Thousand Seventeen [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.65%	6.65%
Senior Notes	$ 485	$ 485

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Incentive Plans Incentive Plans (Stock-based compensation) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Arrangement with Individual, Compensation Expense	$ 31	$ 26	$ 84	$ 87
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	138		$ 138
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	36		$ 36
Accounts Payable, Current	$ 17		$ 17		$ 16

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Incentive Plans Incentive Plans (Share Based Incentive Award Activity) (Details) - shares	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,098,801	1,081,650
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	520,980
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(459,833)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(43,996)
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	295,906	271,031
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	180,383
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(141,441)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(14,067)
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	239,170	148,547
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	104,114
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(8,670)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(4,821)
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	199,058	199,058
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested, Number of Shares	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning asset retirement obligations	$ 281	$ 187	$ 285	$ 189
AssetRetirementObligationLiabilitiesAcquiredInBusinessCombination	3	0	3	0
Asset Retirement Obligation, Liabilities Incurred	0	1	0	2
Liabilities settled	(8)	(9)	(21)	(18)
Accretion of discount from continuing operations	5	3	14	9
Ending asset retirement obligations	281	$ 182	281	$ 182
Asset retirement obligations, current portions	$ 40		$ 40		$ 40

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Interest And Other Income (Components Of Interest And Other Income) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Interest and Other Income [Abstract]
Interest income		$ 5	$ 2	$ 14	$ 2
Deferred compensation plan income		0	0	2	4
Equity interest in income of unconsolidated affiliate	[1]	0	0	0	5
Other income		2	0	5	5
Total interest and other income		$ 7	$ 2	$ 21	$ 16

[1] (a)The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream.

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Other Expense (Schedule Of Components Of Other Expense) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Expense [Abstract]
Transportation commitment charges	[1]	$ 27	$ 11	$ 77	$ 38
Third-party vertical integration services		17	20	46	16
Above market and idle drilling and well services equipment charges	[2]	10	22	42	73
Terminated drilling rig contract charges		0	0	15	0
Tangible Asset Impairment Charges	[3]	1	13	6	21
Restructuring Charges		0	9	4	24
Other		14	4	33	14
Total other expense		69	79	223	186
GrossRevenuesIncludedInThirdPartyLossFromVerticalIntegrationServices		19	66	144	264
GrossExpensesIncludedInThirdPartyLossFromVerticalIntegrationServices		$ 36	$ 86	$ 190	$ 280

[1] Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three and nine months ended September 30, 2016, these vertical integration net margins included $19 million and $144 million, respectively, of revenues and $36 million and $190 million, respectively, of costs and expenses. For the same respective periods in 2015, these vertical integration net margins included $66 million and $264 million of revenues and $86 million and $280 million of costs and expenses.

[2] Primarily represents firm transportation payments on excess pipeline capacity commitments.

[3] Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

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Income Taxes (Schedule Of Income Tax (Provisions) Benefits Attributable To Income From Continuing Operations) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Current income taxes	$ 22	$ (48)	$ 22	$ (49)
Deferred income taxes	56	(307)	340	(146)
Income tax benefit (provision)	$ 78	$ (355)	$ 362	$ (195)
Effective Tax Rate	140.00%	35.00%	41.00%	35.00%
Statutory Tax Rate	35.00%		35.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Research, Amount	$ 59		$ 59
Unrecognized Tax Benefits	$ 94		$ 94

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Net Income Per Share (Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement Operating Activities Segment [Line Items]
Basic income (loss) from continuing operations attributable to common stockholders	$ 22	$ 640	$ (513)	$ 347
Diluted income (loss) from continuing operations attributable to common stockholders	22	640	(513)	347
Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations attributable to parent	22	648	(513)	356
Participating Securities, Distributed and Undistributed Earnings, Basic	0	(6)	0	(3)
Basic income (loss) from continuing operations attributable to common stockholders	22	642	(513)	353
Diluted income (loss) from continuing operations attributable to common stockholders	22	642	(513)	353
Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Basic income (loss) from continuing operations attributable to common stockholders	0	(2)	0	(6)
Diluted income (loss) from continuing operations attributable to common stockholders	$ 0	$ (2)	$ 0	$ (6)

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Net Income Per Share (Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding) (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Basic weighted average shares outstanding	170	149	165	149
Diluted	170	150	165	149