PIONEER NATURAL RESOURCES CO - Quarter Report: 2014 September (Form 10-Q)

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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, 2014



¨	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.

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 30, 2014 143,147,890

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

TABLE OF CONTENTS



		Page
Cautionary Statement Concerning Forward-Looking Statements		3

Definitions of Certain Terms and Conventions Used Herein		4

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	5

	Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013	7

	Consolidated Statement of Equity for the nine months ended September 30, 2014	8

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013	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	37

Item 4.	Controls and Procedures	41

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42

Item 4.	Mine Safety Disclosures	42

Item 6.	Exhibits	43

Signatures		44

Exhibit Index		45

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PIONEER NATURAL RESOURCES COMPANY

Cautionary Statement Concerning Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (the "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. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control.

These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company's drilling and operating activities, access to and availability of transportation, processing, fractionation 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 and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves 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, 2013 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

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PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

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


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


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


•	"BOEPD" means BOE per day.


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


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


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


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


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


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


•	"MMBTU" means one million BTUs.


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


•	"NGL" means natural gas liquid.


•	"NYMEX" means the New York Mercantile Exchange.


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


•	"Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. 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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)



	September 30, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	550		$	393
Accounts receivable:
Trade, net	483			431
Due from affiliates	7			3
Income taxes receivable	22			5
Inventories	237			220
Prepaid expenses	23			16
Deferred income taxes	2			—
Assets held for sale	—			584
Other current assets:
Derivatives	128			76
Other	39			2
Total current assets	1,491			1,730
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	14,856			13,406
Unproved properties	154			123
Accumulated depletion, depreciation and amortization	(5,183		)	(4,903		)
Total property, plant and equipment	9,827			8,626
Goodwill	272			274
Other property and equipment, net	1,303			1,224
Other assets:
Investment in unconsolidated affiliate	221			225
Derivatives	57			91
Other, net	101			124
	$	13,272		$	12,294

The financial information included as of September 30, 2014 has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in millions)



	September 30, 2014			December 31, 2013
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,228		$	910
Due to affiliates	102			150
Interest payable	36			62
Income taxes payable	1			—
Deferred income taxes	—			19
Liabilities held for sale	—			39
Other current liabilities:
Derivatives	1			12
Other	71			58
Total current liabilities	1,439			1,250
Long-term debt	2,662			2,653
Derivatives	—			10
Deferred income taxes	1,734			1,473
Other liabilities	284			293
Equity:
Common stock, $.01 par value; 500 million shares authorized; 146 million shares issued as of September 30, 2014 and December 31, 2013, respectively	1			1
Additional paid-in capital	5,162			5,080
Treasury stock at cost: 3 million shares as of September 30, 2014 and December 31, 2013, respectively	(170		)	(144		)
Retained earnings	2,152			1,665
Total equity attributable to common stockholders	7,145			6,602
Noncontrolling interests in consolidating subsidiaries	8			13
Total equity	7,153			6,615
Commitments and contingencies
	$	13,272		$	12,294

The financial information included as of September 30, 2014 has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues and other income:
Oil and gas	$	967		$	820		$	2,795		$	2,296
Sales of purchased oil and gas	202			82			554			194
Interest and other	2			8			9			3
Derivative gains (losses), net	341			(102		)	19			—
Gain (loss) on disposition of assets, net	1			(1		)	11			206
	1,513			807			3,388			2,699
Costs and expenses:
Oil and gas production	168			150			493			440
Production and ad valorem taxes	58			49			169			147
Depletion, depreciation and amortization	274			222			734			650
Purchased oil and gas	194			85			535			196
Exploration and abandonments	22			30			80			65
General and administrative	81			72			244			200
Accretion of discount on asset retirement obligations	3			3			9			9
Interest	46			45			138			139
Other	20			24			55			65
	866			680			2,457			1,911
Income from continuing operations before income taxes	647			127			931			788
Income tax provision	(236		)	(48		)	(319		)	(281		)
Income from continuing operations	411			79			612			507
Income (loss) from discontinued operations, net of tax	(37		)	19			(113		)	52
Net income	374			98			499			559
Net income attributable to noncontrolling interests	—			(7		)	—			(30		)
Net income attributable to common stockholders	$	374		$	91		$	499		$	529

Basic earnings per share attributable to common stockholders:
Income from continuing operations	$	2.84		$	0.51		$	4.24		$	3.49
Income (loss) from discontinued operations	(0.26		)	0.14			(0.79		)	0.38
Net income	$	2.58		$	0.65		$	3.45		$	3.87
Diluted earnings per share attributable to common stockholders:
Income from continuing operations	$	2.84		$	0.51		$	4.23		$	3.44
Income (loss) from discontinued operations	(0.26		)	0.14			(0.79		)	0.38
Net income	$	2.58		$	0.65		$	3.44		$	3.82
Weighted average shares outstanding:
Basic	143			139			143			135
Diluted	143			139			143			137

Dividends declared per share	$	0.04		$	0.04		$	0.08		$	0.08

Amounts attributable to common stockholders:
Income from continuing operations	$	411		$	72		$	612		$	477
Income (loss) from discontinued operations, net of tax	(37		)	19			(113		)	52
Net income	$	374		$	91		$	499		$	529

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(in millions, except 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
Balance as of December 31, 2013	143	$	1	$	5,080		$	(144	)	$	1,665		$	13		$	6,615
Dividends declared ($0.08 per share)	—	—		—			—			(12		)	—			(12		)
Exercise of long-term incentive plan stock options and employee stock purchases	—	—		6			7			—			—			13
Purchases of treasury stock	—	—		—			(33		)	—			—			(33		)
Sendero divestiture	—	—		—			—			—			(4		)	(4		)
Tax benefits related to stock-based compensation	—	—		14			—			—			—			14
Pioneer Southwest merger transaction costs	—	—		(1		)	—			—			—			(1		)
Compensation costs included in net income	—	—		63			—			—			—			63
Cash distributions to noncontrolling interests	—	—		—			—			—			(1		)	(1		)
Net income	—	—		—			—			499			—			499
Balance as of September 30, 2014	143	$	1	$	5,162		$	(170	)	$	2,152		$	8		$	7,153

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

(Unaudited)



	Nine Months Ended September 30,
	2014			2013
Cash flows from operating activities:
Net income	$	499		$	559
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	734			650
Impairment of inventory and other property and equipment	7			8
Exploration expenses, including dry holes	11			10
Deferred income taxes	315			276
Gain on disposition of assets, net	(11		)	(206		)
Accretion of discount on asset retirement obligations	9			9
Discontinued operations	247			114
Interest expense	13			13
Derivative related activity	(39		)	122
Amortization of stock-based compensation	63			53
Other	42			(8		)
Change in operating assets and liabilities:
Accounts receivable, net	(77		)	(89		)
Income taxes receivable	(17		)	(3		)
Inventories	(27		)	(28		)
Prepaid expenses	(11		)	(7		)
Other current assets	(1		)	2
Accounts payable	96			184
Interest payable	(26		)	(32		)
Income taxes payable	1			—
Other current liabilities	(30		)	(22		)
Net cash provided by operating activities	1,798			1,605
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	855			685
Additions to oil and gas properties	(2,259		)	(1,987		)
Additions to other assets and other property and equipment, net	(224		)	(160		)
Net cash used in investing activities	(1,628		)	(1,462		)
Cash flows from financing activities:
Borrowings under long-term debt	523			444
Principal payments on long-term debt	(523		)	(1,323		)
Proceeds from issuance of common stock, net of issuance costs	—			1,281
Distributions to noncontrolling interests	(1		)	(27		)
Exercise of long-term incentive plan stock options and employee stock purchases	13			10
Purchases of treasury stock	(33		)	(20		)
Excess tax benefits from share-based payment arrangements	14			13
Dividends paid	(6		)	(6		)
Net cash provided by (used in) financing activities	(13		)	372
Net increase in cash and cash equivalents	157			515
Cash and cash equivalents, beginning of period	393			229
Cash and cash equivalents, end of period	$	550		$	744

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(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 continuing field operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeastern 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, 2014 and for the three and nine months ended September 30, 2014 and 2013 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, 2013.

Certain reclassifications have been made to the 2013 financial statement and footnote amounts in order to conform to the 2014 presentation.

New accounting pronouncements. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 prospectively changes the criteria for reporting discontinued operations while enhancing disclosures around disposals of assets whether or not the disposal meets the definition of a discontinued operation. ASU 2014-08 is effective for annual and interim periods beginning after December 31, 2014 with early adoption permitted but only for disposals that have not been reported in financial statements previously issued. The adoption of this new guidance is not expected to have a material impact on the Company's consolidated financial statements.

NOTE C. Divestitures

Divestitures Recorded in Continuing Operations

For the three and nine months ended September 30, 2014, the Company recorded net gains on disposition of assets in continuing operations of $1 million and $11 million, respectively, as compared to a net loss of $1 million and a net gain of $206 million for the same respective periods in 2013. The net gains and losses attributable to the disposition of assets were primarily comprised of the following:


•	Vertical drilling rigs. During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner. At December 31, 2013, the assets and liabilities of Sendero were classified as held for sale at their estimated fair value. In March 2014, the Company

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

completed the sale of Sendero for cash proceeds of $31 million and recognized a gain of $1 million associated with the completion of the sale. As part of the sales agreement, the Company committed to a lease agreement with Sendero for 12 vertical rigs through December 31, 2015, and eight vertical rigs in 2016.


•	Permian Basin. During February 2014, the Company completed the sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million, which resulted in a gain of $2 million on the unproved property.

•

Southern Wolfcamp. In May 2013, the Company completed the sale of 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas to Sinochem Petroleum USA LLC ("Sinochem") for cash proceeds of $624 million, which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play.


•	West Panhandle. During the first quarter of 2013, the Company completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for cash proceeds of $38 million, which resulted in a gain of $22 million.

Divestitures Recorded as Discontinued Operations

Hugoton. In September 2014, the Company completed the sale of its net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million, including normal closing adjustments. Associated therewith, the Company reduced the carrying value of goodwill by $2 million, reflecting the portion of the Company's goodwill related to Hugoton field net assets sold. See Note D for information about impairment charges on the Hugoton assets.

Barnett Shale. During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In September 2014, the Company completed the sale of its Barnett Shale net assets for cash proceeds of $150 million, including normal closing adjustments. See Note D for information about impairment charges on the Barnett Shale assets.

Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer's Alaska subsidiary ("Pioneer Alaska"). In April 2014, the Company completed the sale of Pioneer Alaska to an unaffiliated third party pursuant to an amended purchase and sale agreement for cash proceeds of $267 million, before normal closing and other adjustments.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

The following table represents the components of the Company's discontinued operations for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Revenues and other income:
Oil and gas	$	49		$	89		$	198		$	246
Interest and other (a)	1			13			31			39
Gain on disposition of assets, net	—			—			5			9
	50			102			234			294
Costs and expenses:
Oil and gas production	16			32			59			90
Production and ad valorem taxes	3			5			12			15
Depletion, depreciation and amortization	2			34			11			87
Impairment of oil and gas properties	80			—			305			—
Exploration and abandonments	1			2			3			18
General and administrative	—			2			3			4
Accretion of discount on asset retirement obligations	—			—			1			1
Other	6			(2		)	14			(2		)
	108			73			408			213
Income (loss) from discontinued operations before income taxes	(58		)	29			(174		)	81
Current tax provision	—			—			(1		)	(4		)
Deferred tax (provision) benefit	21			(10		)	62			(25		)
Income (loss) from discontinued operations	$	(37	)	$	19		$	(113	)	$	52

____________________


(a)	Primarily comprised of cash received associated with Alaskan Petroleum Production Tax credits on qualifying capital expenditures.

As of December 31, 2013, the carrying values of the Company's ownership in Pioneer Alaska, the Barnett Shale field and Sendero were included in assets and liabilities held for sale in the accompanying consolidated balance sheet and were comprised of the following (the Company had no assets held for sale at September 30, 2014):



	December 31, 2013
	(in millions)
Composition of assets included in assets held for sale:
Current assets	$	58
Property, plant and equipment	526
Total assets	$	584

Composition of liabilities included in liabilities held for sale:
Current liabilities	$	29
Other liabilities	10
Total liabilities	$	39

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

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.

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, 2014 for each of the fair value hierarchy levels:



	Fair Value Measurement at the End of the Reporting Period 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, 2014
	(in millions)
Recurring fair value measurements
Assets:
Commodity derivatives	$	—	$	185	$	—	$	185
Deferred compensation plan assets	70		—		—		70
Total assets	70		185		—		255
Liabilities:
Commodity derivatives	—		1		—		1
Total liabilities	—		1		—		1
Total recurring fair value measurements	$	70	$	184	$	—	$	254

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

The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar 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, 2014, the significant inputs to these asset values represented Level 1 independent active exchange market price inputs.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

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. During the three and nine months ended September 30, 2014, the Company recorded charges in other expense in the Company's accompanying consolidated statements of operations of $3 million and $6 million, respectively, to reduce the carrying value of inventory to fair value.

Assets associated with divestitures. Long-lived assets that are classified as held for sale are recorded at the lower of the asset's net carrying amount or estimated fair value less costs to sell. The Hugoton field assets, the Barnett Shale field assets and Pioneer Alaska were classified as held for sale and carried as such until their divestitures in September 2014, September 2014 and April 2014, respectively. Associated therewith, the Company recognized impairment charges during 2014 to reduce the carrying values of the Hugoton field assets, the Barnett Shale field assets and Pioneer Alaska to their sales prices, less costs to sell.

The following table presents the fair value adjustments made by the Company during 2014 related to assets associated with divestitures:



			Fair Value Adjustment
	Sales Value Less Costs to Sell		Three Months Ended September 30, 2014			Nine Months Ended September 30, 2014
	(in millions)
Hugoton field	$	328	$	(34	)	$	(34	)
Barnett Shale field	$	149	$	(46	)	$	(174	)
Pioneer Alaska	$	253	$	—		$	(97	)

See Note C for additional information regarding the Company's divestitures of the Hugoton field assets, the Barnett Shale field assets and Pioneer Alaska.

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets as of September 30, 2014 and December 31, 2013 are as follows:



	September 30, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Long-term debt	$	2,662	$	3,025	$	2,653	$	3,019

Long-term debt includes the Company's credit facility and the Company's senior notes. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

Credit facility. 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.

Senior notes. The Company's senior notes represent debt securities that are traded on major exchanges but are not actively traded. 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 cash equivalents, 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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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

NOTE E. Derivative Financial Instruments

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

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

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of September 30, 2014 and the weighted average oil prices for those contracts:



	Three Months Ending December 31,		Year Ending December 31,
	2014		2015		2016
Collar contracts with short puts:
Volume (BBL) (a)(b)	69,000		95,767		59,000
Price per BBL:
Ceiling	$	114.05	$	99.36	$	98.55
Floor	$	93.70	$	87.98	$	86.14
Short put	$	77.61	$	73.54	$	74.75
Swap contracts:
Volume (BBL)	15,000		—		—
Price per BBL	$	96.31	$	—	$	—
Rollfactor swap contracts:
Volume (BBL) (c)	6,630		5,000		—
NYMEX roll price (d)	$	1.10	$	0.60	$	—

____________________

(a)

Counterparties have the option to extend for an additional year 5,000 BBLs per day of 2015 collar contracts with short puts with a ceiling price of $100.08 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL. The option to extend is exercisable on December 31, 2015. These contracts give the counterparties the option to extend the contracts under the same terms for an additional year if the option to extend is exercised by the counterparties on December 31, 2015.


(b)	During the period from October 1, 2014 through October 30, 2014, the Company entered into an additional 11,000 BBL per day of 2016 collar contracts with short puts with a ceiling price of $87.76 per BBL, a floor price of $82.82 per BBL and a short put price of $72.82 per BBL.


(c)	During the period from October 1, 2014 through October 30, 2014, the Company entered into an additional 12,000 BBL per day of 2015 rollfactor swap contracts with a NYMEX roll price of $0.15 per BBL.


(d)	Represents swaps that fix the difference between (i) each day's price per BBL of WTI for the first nearby month less (ii) the price per BBL of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per BBL of WTI for the first nearby month less (iv) the price per BBL of WTI for the third nearby NYMEX month, multiplied by .3333.

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL component product prices.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of September 30, 2014 and the weighted average NGL prices for those contracts:



	Three Months Ending December 31,		Year Ending December 31,
	2014		2015		2016
Natural gasoline collar contracts with short puts (a):
Volume (BBL)	3,500		—		—
Price per BBL:
Ceiling	$	97.93	$	—	$	—
Floor	$	90.14	$	—	$	—
Short put	$	81.36	$	—	$	—
Ethane collar contracts (a):
Volume (BBL)	3,000		—		—
Price per BBL:
Ceiling	$	13.72	$	—	$	—
Floor	$	10.78	$	—	$	—
Ethane swap contracts (a)(b):
Volume (BBL)	—		—		3,000
Average price per BBL	$	—	$	—	$	12.39
Propane swap contracts (a):
Volume (BBL)	1,674		—		—
Average price per BBL	$	47.95	$	—	$	—

____________________


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

(b) During the period from October 1, 2014 through October 30, 2014, the Company entered into an additional 1,000 BBL per day of 2016 swap contracts for ethane with a fixed price of $11.97 per BBL.

Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("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.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of September 30, 2014 and the weighted average gas prices for those contracts:



	Three Months Ending December 31,			Year Ending December 31,
	2014			2015			2016
Collar contracts with short puts:
Volume (MMBTU)	115,000			285,000			20,000
Price per MMBTU:
Ceiling	$	4.70		$	5.07		$	5.36
Floor	$	4.00		$	4.00		$	4.00
Short put	$	3.00		$	3.00		$	3.00
Swap contracts:
Volume (MMBTU)	195,000			20,000			70,000
Price per MMBTU	$	4.04		$	4.31		$	4.06
Basis swap contracts:
Mid-Continent index swap volume (a)	120,000			95,000			—
Price differential ($/MMBTU)	$	(0.22	)	$	(0.24	)	$	—
Permian Basin index swap volume (a)	10,000			10,000			—
Price differential ($/MMBTU)	$	(0.15	)	$	(0.13	)	$	—
Permian Basin index swap volume (b)	16,630			—			—
Price differential ($/MMBTU)	$	0.34		$	—		$	—

____________________


(a)	Represent swaps that fix the basis differentials between the index prices at which the Company sells its Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts.


(b)	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 differential 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, 2014, the Company had (i) marketing gas index swap contracts for 40,000 MMBTU per day for the remainder of 2014 with a price differential of $0.31 per MMBTU between Permian Basin index prices and southern California index prices and (ii) marketing oil index swap contracts for 10,000 BBL per day for the remainder of 2014 with a price differential of $2.81 per BBL between Cushing WTI and Louisiana Light Sweet oil ("LLS") and 10,000 BBL per day for 2015 with a price differential of $2.99 per BBL between Cushing WTI and LLS.

Interest rate derivative activities. During the three months ended June 30, 2014, the Company terminated its interest rate derivative contracts for cash proceeds of $14 million. Prior to termination, the Company received a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month London Interbank Offered Rate ("LIBOR") plus an average rate of 1.11 percent on a notional amount of $400 million.

During the period from October 1, 2014 through October 30, 2014, the Company entered into interest rate derivative contracts that expire on June 30, 2015 for a notional amount of $200 million. The Company will pay an average fixed rate of 2.43 percent in exchange for receiving the 10-year Treasury rate as of the expiration date.

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.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

The aggregate fair value of the Company's derivative instruments reported in the 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, 2014
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	$	132	$	(4	)	$	128
Commodity price derivatives	Derivatives - noncurrent	$	62	$	(5	)	57
							$	185
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	5	$	(4	)	$	1
Commodity price derivatives	Derivatives - noncurrent	$	5	$	(5	)	—
							$	1



Fair Value of Derivative Instruments as of December 31, 2013
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	$	73	$	(7	)	$	66
Interest rate derivatives	Derivatives - current	$	10	$	—		10
Commodity price derivatives	Derivatives - noncurrent	$	95	$	(4	)	91
Interest rate derivatives	Derivatives - noncurrent	$	15	$	(15	)	—
							$	167
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	19	$	(7	)	$	12
Commodity price derivatives	Derivatives - noncurrent	$	4	$	(4	)	—
Interest rate derivatives	Derivatives - noncurrent	$	25	$	(15	)	10
							$	22

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(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 Hedging	Location of Gain / (Loss) Recognized in	Three Months Ended September 30,					Nine Months Ended September 30,
Instruments	Earnings on Derivatives	2014		2013			2014		2013
		(in millions)
Commodity price derivatives	Derivative gains (losses), net	$	341	$	(108	)	$	1	$	(17	)
Interest rate derivatives	Derivative gains (losses), net	—		6			18		17
Total		$	341	$	(102	)	$	19	$	—

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, 2014:



	Three Months Ended September 30, 2014			Nine Months Ended September 30, 2014
	(in millions)
Beginning capitalized exploratory costs	$	322		$	159
Additions to exploratory costs pending the determination of proved reserves	586			1,275
Reclassification due to determination of proved reserves	(466		)	(941		)
Disposition of assets	(16		)	(52		)
Impairment of properties	(1		)	(12		)
Exploratory well costs charged to exploration expense	(1		)	(5		)
Ending capitalized exploratory costs	$	424		$	424

The following table provides an aging, as of September 30, 2014 and December 31, 2013, of capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized for a period greater than one year based on the date drilling was completed:



	September 30, 2014		December 31, 2013
	(in millions, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	416	$	116
More than one year	8		43
	$	424	$	159

Number of projects with exploratory costs that have been suspended for a period greater than one year	3		1

At September 30, 2014, the $8 million of suspended well costs that have been suspended for a period greater than one year are comprised of two wells in eastern Colorado and one well in the Eagle Ford Shale play that were drilled as stratigraphic test wells. The costs are capitalized pending the results of further drilling operations in the area.

The $43 million of suspended well costs suspended for a period greater than one year at December 31, 2013 related to Pioneer Alaska, which was sold in April 2014. See Note C for additional information on the sale of Pioneer Alaska.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

NOTE G. Long-term Debt

The Company's long-term debt consists of senior notes and a revolving corporate credit facility (the "Credit Facility"), including the effects of net deferred fair value hedge losses and issuance discounts. The Credit Facility is maintained with a syndicate of financial institutions and has aggregate loan commitments of $1.5 billion that expire in December 2017. As of September 30, 2014, the Company had no outstanding borrowings under the Credit Facility and was in compliance with all of its debt covenants.

NOTE H. Incentive Plans

Stock-based compensation

For the three and nine months ended September 30, 2014, the Company recorded $27 million and $89 million, respectively, of stock-based compensation expense for all plans, as compared to $33 million and $85 million for the same respective periods of 2013. As of September 30, 2014, there was $160 million of unrecognized compensation expense related to unvested share-based compensation plan awards, including $42 million attributable to stock-based awards that are expected to be settled on their vesting date in cash, rather than in equity shares ("Liability Awards"). The unrecognized compensation expense will be recognized 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, 2014 and December 31, 2013, accounts payable – due to affiliates includes $22 million and $33 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the nine months ended September 30, 2014, 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, 2013	1,371,207		422,382		134,476		289,927
Awards granted	406,617		140,093		67,182		—
Awards vested	(451,372	)	(200,408	)	(898	)	—
Options exercised	—		—		—		(90,869	)
Awards forfeited	(52,542	)	(25,534	)	(1,078	)	—
Outstanding as of September 30, 2014	1,273,910		336,533		199,682		199,058

Postretirement Benefit Obligations

As of September 30, 2014 and December 31, 2013, the Company had $6 million and $8 million, respectively, of unfunded accumulated postretirement benefit obligations. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years. Other than the Company's retirement plan, the participants of these plans are not current employees of the Company. The plans had no assets as of September 30, 2014 or December 31, 2013.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Company's asset retirement obligation activity during the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Beginning asset retirement obligations	$	193		$	191		$	194		$	198
New wells placed on production	1			1			3			3
Changes in estimates	2			—			3			(6		)
Dispositions	(5		)	—			(7		)	(4		)
Liabilities settled	(6		)	(4		)	(14		)	(10		)
Accretion of discount	3			3			9			9
Accretion of discount on discontinued operations	—			—			—			1
Ending asset retirement obligations	$	188		$	191		$	188		$	191

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 September 30, 2014, the current portion of the Company's asset retirement obligations was $27 million, as compared to $19 million at December 31, 2013.

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 consolidated 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 typically retains certain liabilities and provides the purchaser certain indemnifications, subject to defined limitations, which may apply to pre-closing matters such as 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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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

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, 2014 and 2013:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
	(in millions)
Equity interest in income of EFS Midstream (a)	$	3		$	4	$	10		$	10
Other income	1			2		5			6
Deferred compensation plan income	—			—		3			2
Income (loss) from vertical integration services (b)	(2		)	2		(9		)	(15		)
Total interest and other income	$	2		$	8	$	9		$	3

____________________


(a)	The Company accounts for its investment in EFS Midstream LLC ("EFS Midstream") using the equity method. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term.

(b)

Income (loss) from vertical integration services primarily represents net margins that result from Company-provided fracture stimulation and related 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, 2014, these net margins included $125 million and $321 million of gross vertical integration revenues, respectively, and $127 million and $330 million of total vertical integration costs and expenses, respectively. For the same periods in 2013, these net margins included $103 million and $206 million of gross vertical integration revenues, respectively, and $101 million and $221 million of total vertical integration costs and expenses, respectively.

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, 2014 and 2013:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)
Transportation commitment charge (a)	$	11	$	10	$	34	$	29
Other	4		5		11		14
Impairment of inventory (b)	3		3		6		5
Contingency and environmental accrual adjustments	—		5		2		7
Above market and idle drilling and well services equipment charges (c)	2		1		2		10
Total other expense	$	20	$	24	$	55	$	65

____________________


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


(b)	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.


(c)	Primarily represents expenses attributable to the portion of the Company's contracted rig rates that were above market rates and idle rig fees, neither of which were chargeable to joint operations.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

NOTE M. Income Taxes

The Company's income tax provisions attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014		2013
	(in millions)
Current tax provision (benefit)	$	(14	)	$	(9	)	$	4	$	5
Deferred tax provision	250			57			315		276
Income tax provision	$	236		$	48		$	319	$	281

For the three and nine months ended September 30, 2014, the Company's effective tax rates, excluding income attributable to the noncontrolling interest, were 36 percent and 34 percent, respectively, as compared to effective rates of 40 percent and 37 percent for each of the same respective periods in 2013. The Company's 2014 effective tax rates differed from the U.S. statutory rate of 35 percent primarily due to state income tax apportionments, nondeductible expenses and, for the nine months ended September 30, 2014, the recognition of a $21 million tax benefit resulting from the resolution during the first quarter of 2014 of the tax uncertainty related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica. There are no unrecognized tax benefits as of September 30, 2014.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2012 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2009. As of September 30, 2014, 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 Per Share

The following table reconciles the Company's net income from continuing operations attributable to common stockholders to basic and diluted net income from continuing operations attributable to common stockholders for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)
Net income from continuing operations attributable to common stockholders	$	411		$	72		$	612		$	477
Participating basic earnings	(4		)	(1		)	(5		)	(6		)
Basic and diluted income from continuing operations attributable to common stockholders	$	407		$	71		$	607		$	471

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2014

(Unaudited)

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
	(in millions)
Weighted average common shares outstanding:
Basic	143	139	143	135
Dilution attributable to convertible senior notes	—	—	—	2
Diluted (a)	143	139	143	137

____________________

(a)

The Company excluded 33,591 shares and 11,197 shares attributable to unvested performance units from the diluted income per share calculations for the three and nine months ended September 30, 2014, respectively, because they would have been anti-dilutive to the calculation. Options to purchase 34,842 shares of the Company's common stock were excluded from the diluted income per share calculations for the nine months ended September 30, 2013 because they would have been anti-dilutive to the calculation.

NOTE O. Subsequent Events

During November 2014, the Company announced that it is pursuing the divestment of its 50.1 percent share of EFS Midstream. The Company accounts for EFS Midstream under the equity method of accounting for investments in unconsolidated affiliates. The Company is in the early stages of marketing its equity investment in EFS Midstream and no assurance can be given that the sale will be completed in accordance with the Company's plans or on terms and at a price acceptable to the Company.

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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 2014 included the following highlights:

•

Net income attributable to common stockholders for the third quarter of 2014 was $374 million ($2.58 per diluted share), as compared to net income of $91 million ($0.65 per diluted share) for the third quarter of 2013. The increase in net income attributable to common stockholders is comprised of a $339 million increase in net income from continuing operations attributable to common stockholders and a $56 million decrease in income from discontinued operations, net of tax.

The primary components of the increase in net income from continuing operations include:


•	a $443 million increase in net derivative gains, primarily as a result of decreases in forward commodity prices and changes in the Company's portfolio of derivatives; and


•	a $147 million increase in oil and gas revenues as a result of a 22 percent increase in sales volumes, partially offset by a 3 percent decrease in the average commodity prices received per BOE; partially offset by


•	a $52 million increase in DD&A expense, primarily attributable to the 22 percent increase in sales volumes;


•	a $27 million increase in total oil and gas production costs and production and ad valorem taxes, primarily associated with the 22 percent increase in sales volumes;


•	a $9 million increase in general and administrative expense, primarily due to increased personnel, occupancy and information technology costs resulting from the growth in employee headcount in support of the Company's capital expansion initiatives; and


•	a $188 million increase in the Company's income tax provision as a result of the Company's increase in income from continuing operations before taxes.

The primary components of the decrease in income from discontinued operations, net of tax, include:


•	an $80 million impairment charge to reduce the carrying value of the Company's Barnett Shale and Hugoton field assets to their sales values less costs to sell;


•	a $52 million decrease in revenues and other income, primarily due to the sale of Pioneer Alaska in April 2014; partially offset by


•	a $32 million decrease in depletion, depreciation and amortization, primarily due to the Hugoton field, the Barnett Shale field and Pioneer Alaska assets being classified as held for sale;


•	a $16 million decrease in oil and gas production costs due to the sale of Pioneer Alaska in April 2014; and


•	a $31 million change in the Company's income taxes attributable to discontinued operations as a result of the change in pretax income from discontinued operations.

•

During the third quarter of 2014, average daily sales volumes from continuing operations increased by 22 percent to 186,077 BOEPD, as compared to 152,671 BOEPD during the third quarter of 2013. The increase in third quarter 2014 average daily sales volumes, as compared to the third quarter of 2013, is primarily due to the Company's successful Spraberry/Wolfcamp and Eagle Ford Shale drilling programs.


•	Average oil and NGL prices decreased during the third quarter of 2014 to $90.82 per BBL and $28.44 per BBL, respectively, as compared to $101.70 per BBL and $30.87 per BBL, respectively, in the third quarter of 2013. Gas prices increased during the third quarter of 2014 to $3.79 per MCF, as compared to $3.30 per MCF in the third quarter of 2013.

•

Net cash provided by operating activities decreased to $616 million for the three months ended September 30, 2014, as compared to $668 million for the three months ended September 30, 2013. The $52 million decrease in net cash provided by operating activities is primarily due to working capital changes and a decrease in (i) oil and NGL prices and (ii) net cash flows from derivative settlements, partially offset by an increase in revenues due to an increase in oil and gas sales volumes.


•	As of September 30, 2014, the Company's net debt to book capitalization was 23 percent, as compared to 25 percent at December 31, 2013.

PIONEER NATURAL RESOURCES COMPANY

Recent Developments

Commodity prices. Oil prices have declined recently as a result of the combination of increased worldwide production and declining worldwide demand. The increase in the supply of oil has been largely due to the production growth of U.S. shale oil and higher Libyan and Iraqi oil exports in recent months. Demand has been negatively impacted by the decline in the Chinese growth rate and the lingering recession in Europe. Oil storage levels in the U.S. are also increasing, which could cause an increase in the differential between WTI, the index on which the Company's oil sales prices are determined, and Brent, the index price used to price oil internationally.

WTI prices have declined from over $100 per barrel in July 2014 to around $80 per barrel recently. Although the Company has entered into oil derivative contracts to manage its price risk through 2016, a sustained lower oil price environment could result in lower realized prices and a reduction in the Company's expected cash flow. The duration and magnitude of the recent decline in oil prices cannot be predicted, but a sustained decline could result in the Company reducing its capital spending plans, which would reduce the Company's production growth rate. The Company plans to continue to monitor the oil price environment and adjust its capital spending plans and production growth targets as needed in order to maintain adequate liquidity and financial flexibility.

EFS Midstream. During November 2014, the Company announced that it is pursuing the divestment of its 50.1 percent share of EFS Midstream. The Company accounts for EFS Midstream under the equity method of accounting for investments in unconsolidated affiliates. The Company is in the early stages of marketing its equity investment in EFS Midstream and no assurance can be given that the sale will be completed in accordance with the Company's plans or on terms and at a price acceptable to the Company.

Fourth Quarter 2014 Outlook

Based on current estimates, the Company expects the following operating and financial results from continuing operations for the quarter ending December 31, 2014:

Production is forecasted to average 200,000 to 205,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $13.25 to $15.25 per BOE based on current NYMEX strip commodity prices. DD&A expense is expected to average $15.00 to $17.00 per BOE.

Total exploration and abandonment expense is expected to be $25 million to $35 million. General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $46 million to $51 million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 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. Cash income taxes are expected to range from $1 million to $5 million and are primarily attributable to state taxes.

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PIONEER NATURAL RESOURCES COMPANY

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, 2014:



	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	60,960	19,777	81,938	94,393
South Texas - Eagle Ford Shale	17,501	13,341	87,894	45,490
Raton Basin	—	—	125,320	20,887
West Panhandle	2,832	4,160	13,701	9,275
South Texas - Other	1,189	39	27,824	5,866
Other	3	2	72	18
Total continuing operations	82,485	37,319	336,749	175,929
Barnett Shale	2,145	3,812	28,597	10,724
Hugoton	—	2,238	21,915	5,889
Alaska	1,338	—	—	1,338
Total including discontinued operations	85,968	43,369	387,261	193,880

During 2014 and 2013, the Company has focused its capital budgets and expenditures on oil and liquids-rich gas drilling activities due to relatively lower gas prices. As a result of these capital activities, the Company's total liquids production from continuing operations increased to 68 percent of total production, on a BOE basis, for the nine months ended September 30, 2014, as compared to 64 percent for the same period last year. The Company's liquids revenue as a percent of total commodity sales was 86 percent for the nine months ended September 30, 2014, as compared to 87 percent for the same period last year, due to a 26 percent increase in the average gas price while there was no substantial change in oil and NGL prices.

The following table summarizes by geographic area the Company's finding and development costs incurred during the nine months ended September 30, 2014:



	Acquisition Costs				Exploration			Development		Asset Retirement
	Proved		Unproved		Costs			Costs		Obligations		Total
	(in millions)
Permian Basin	$	2	$	9	$	922		$	930	$	1	$	1,864
South Texas - Eagle Ford Shale	—		—		266			174		1		441
Raton Basin	—		—		5			20		—		25
West Panhandle	—		—		2			6		—		8
South Texas - Other	—		—		17			11		—		28
Other	—		2		10			—		—		12
Total continuing operations	2		11		1,222			1,141		2		2,378
Barnett Shale	4		5		120			30		—		159
Hugoton	—		—		1			1		—		2
Alaska	—		—		(1		)	48		4		51
Total including discontinued operations	$	6	$	16	$	1,342		$	1,220	$	6	$	2,590

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The following table summarizes the Company's development and exploration/extension drilling activities for the nine months ended September 30, 2014:



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Wells Sold	Ending Wells in Progress
Permian Basin	59	202	214	4	43
South Texas - Eagle Ford Shale	16	26	30	—	12
Total continuing operations	75	228	244	4	55
Barnett Shale	1	—	1	—	—
Alaska	4	1	—	5	—
Total including discontinued operations	80	229	245	9	55



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Wells Sold	Ending Wells in Progress
Permian Basin	31	175	118	—	1	87
South Texas - Eagle Ford Shale	24	76	62	—	—	38
South Texas - Other	—	8	8	—	—	—
Other	3	2	—	1	—	4
Total continuing operations	58	261	188	1	1	129
Barnett Shale	17	42	52	—	7	—
Alaska	2	—	—	—	2	—
Total including discontinued operations	77	303	240	1	10	129

Permian Basin area. The Company successfully completed 332 wells in the Permian Basin area during the first nine months of 2014. During 2014, the Company expects to place on production over 200 vertical wells and approximately 200 horizontal wells, with the horizontal wells being drilled in the Spraberry/Wolfcamp Shale horizons.

The Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Spraberry and Wolfcamp A, B, C and D intervals and its drilling results to-date. During 2014, the Company expects to place on production approximately 100 horizontal wells in each of the northern portion of the play and the southern portion of the play, where the Company has its joint venture with Sinochem. Three-well pads are being utilized to drill most of the wells in the 2014 program. In the northern portion of the play, the Company expects that approximately 80 percent of the wells placed on production during 2014 will be Wolfcamp A, B and D interval wells. The remaining 20 percent will be Spraberry Shale wells (Lower Spraberry Shale, Jo Mill Shale and Middle Spraberry Shale). In the southern portion of the play, approximately two-thirds of the wells that are expected to be completed will be Wolfcamp B interval wells, with the remainder being a mix of Wolfcamp A, C and D interval wells. The Company has recently initiated completion optimization testing in Midland and Martin counties, which includes increasing proppant concentration per lateral foot, increasing clusters per stage and reducing fluid volume. The Company expects results from this testing to be available later next year. With the addition of drilling rigs during the first half of 2014, combined with the effects of pad drilling, the Company significantly increased production in the third quarter and expects another production increase during the fourth quarter of 2014.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval, including the Strawn and Atoka intervals. The Company reduced its vertical drilling activity from 11 rigs to seven rigs during the third quarter of 2014, with further reductions expected in 2015. The Company expects to place on production over 200 vertical wells that are predominately targeting deeper intervals during 2014. These wells are being drilled to meet continuous drilling obligations.

The Company is continuing to successfully appraise the Jo Mill Shale and Middle Spraberry Shale intervals. Early production from a Jo Mill Shale well drilled in Upton County and a Middle Spraberry Shale well drilled in Upton County during the third quarter are tracking the performance of the Company's best Jo Mill Shale interval and Middle Spraberry Shale interval wells placed on production earlier this year in Martin and Midland counties, respectively. The Company plans to continue to appraise both of these intervals.

The Company continues to benefit from 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. The Company is currently utilizing six Company-owned fracture stimulation fleets totaling approximately 250,000 horsepower in the Spraberry field. To support its

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PIONEER NATURAL RESOURCES COMPANY

operations, the Company also owns other field service equipment, 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 brown sand for proppant, which is being used by the Company to fracture stimulate vertical and horizontal wells 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 identifying the future requirements for water, field infrastructure, gas processing, sand, pipeline takeaway, oilfield services, tubulars, electricity, systems, buildings and roads. The Company plans to continue construction of front-end loaded infrastructure, which is expected to provide significant future cost savings and support the Company's long-term growth plan in the Spraberry/Wolfcamp area. This infrastructure includes a field-wide water distribution network, additional gas processing facilities, continued build-out of horizontal tank batteries and expansion of Premier Silica's Brady sand mine.

During April 2014, the Company extended its gas processing agreement with Atlas Pipeline Partners, L.P. ("Atlas") for an additional 10 years (through 2032) to provide for adequate gas processing capacity across the Spraberry/Wolfcamp area. Associated with the agreement, Atlas added 200 million cubic feet per day of new processing capacity during the third quarter of 2014 and expects to add another 200 million cubic feet per day of new processing capacity during the second half of 2015. The Company owns a 27 percent interest in the Atlas gas processing facilities and will fund its share of capital to build these new facilities. The Company also owns a 30 percent interest in West Texas Gas ("WTG") gas processing facilities in Martin county where WTG is the operator and majority owner of the facilities. WTG expects to complete the construction of a new 200 million cubic feet per day processing facility during the fourth quarter of 2014.

As part of its long-term development plan for the Spraberry/Wolfcamp, the Company plans to reduce its reliance on fresh water used in fracture stimulation operations and mitigate the need for the disposal of produced water through recycling, while also reducing its cost for water acquisition and transportation. Alternative sources of water supply include effluent water, brackish water wells drilled by the Company (e.g. Santa Rosa aquifer), brackish water acquired from third-party sources and recycled produced water. The Company has agreed to purchase approximately 120 thousand barrels per day of effluent water from City of Odessa beginning in the second half of 2015 and is finalizing an agreement with City of Midland to purchase approximately 240 thousand barrels per day of effluent water beginning in the second half of 2017.

The Company's current plans reflect the construction of a field-wide distribution system to transport water by pipeline directly from these alternative sources to frac ponds near planned drilling locations to improve efficiency and reduce costs associated with trucking water. This distribution system is expected to include (i) a 100-mile mainline (30-inch to 36-inch diameter pipeline) stretching across the field, (ii) feeder lines from the Odessa and Midland effluent water plants, (iii) up to 20 subsystems to deliver water to planned drilling locations, (iv) 125 to 150 frac ponds to store water near planned drilling locations and (v) fiber optic lines to improve communication and data management across the basin. Flexibility exists to defer the build-out of subsystems and frac ponds in a lower commodity price environment.

In addition to the new gas processing facilities and planned water distribution system, the Company continues to build new large-scale tank batteries and saltwater disposal facilities to handle the higher volumes that are produced from horizontal wells and expects to expand Premier Silica's Brady sand mine to meet the Company's future proppant requirements for fracture stimulation operation. The Company expects these front-end infrastructure construction activities to continue over the next few years. Total 2015 and 2016 construction infrastructure costs for a field-wide water distribution network, additional gas processing facilities, continued build-out of horizontal tank batteries and expansion of Premier Silica's Brady sand mine is expected to range from $1.4 billion to $1.6 billion.

Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2014 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2014 drilling program has been focused on liquids-rich drilling, with no wells planned to be drilled in dry gas acreage. The Company completed 92 horizontal Eagle Ford Shale wells during the first nine months of 2014, all of which were successful, with average lateral lengths of approximately 5,700 feet and, on average, 19-stage fracture stimulations. The Company has placed 35 Upper Eagle Ford interval wells on production and estimates that approximately 25 percent of the Company's acreage is prospective for this interval in the Eagle Ford Shale play. The Company is operating two Pioneer-owned fracture stimulation fleets in the play and supplements with third-party fleets as needed.

In 2013, the Company added approximately 300 drilling locations in the liquids-rich area of the play as a result of downspacing from 1,000 feet between wells (120-acre spacing) to 500 feet (60-acre spacing) between wells. Further downspacing and staggered testing to a range of 175 feet to 300 feet between staggered wells is underway in the liquids-rich areas where the 500-foot spacing was successful. Some areas will include testing of the Lower Eagle Ford Shale only, while others will include a combination of the Lower and Upper Eagle Ford interval tests. Results from the downspacing and staggered tests in the Eagle Ford Shale continue to be encouraging.

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The Company's drilling operations in the Eagle Ford Shale continue to focus on improving drilling efficiencies. During 2014, most Eagle Ford Shale wells have been drilled utilizing three-well and four-well pads. Pad drilling saves the Company a significant amount of capital costs per well, as compared to drilling single-well locations. The Company has also been using lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in all active development areas, including deeper areas of the field. Well performance continues to be similar to direct offset ceramic-stimulated wells. The Company is continuing to monitor the performance of these wells.

During the second quarter of 2014, the Company received confirmation from the U.S. Department of Commerce that condensate processed through distillation units such as those located at several of Pioneer's Eagle Ford Shale central gathering plants in South Texas is a petroleum product that may be exported without a license.

Divestitures Recorded as Discontinued Operations. During the fourth quarter of 2013, the Company committed to (i) a plan to divest of its net assets in the Barnett Shale field in North Texas and (ii) sell 100 percent of the capital stock in Pioneer Alaska. In September 2014, the Company completed the sale of the Barnett Shale field assets to an unaffiliated third party. In April 2014, the Company completed the sale of Pioneer Alaska to an unaffiliated third party pursuant to an amended purchase and sale agreement.

In July 2014, the Company committed to a plan to divest of its net assets in the Hugoton field in southwest Kansas. In September 2014, the Company completed the sale of its Hugoton net assets to an unaffiliated third party.

The Company has classified its Hugoton, Barnett Shale and Pioneer Alaska results of operations as income (loss) from discontinued operations, net of tax, in the accompanying consolidated statements of operations. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's divestitures of its Hugoton and Barnett Shale field assets and Pioneer Alaska.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $967 million and $2.8 billion for the three and nine months ended September 30, 2014, respectively, as compared to $820 million and $2.3 billion for the same respective periods in 2013.

The increase in oil and gas revenues during the three months ended September 30, 2014, as compared to the same period in 2013, reflected 31 percent, 26 percent and seven percent increases in daily oil, NGL and gas sales volumes, respectively, and a 15 percent increase in average gas prices. Partially offsetting the effects of these increases were 11 percent and eight percent declines in oil and NGL prices, respectively. The increase in oil and gas revenues during the nine months ended September 30, 2014, as compared to the same period in 2013, reflected 20 percent, 28 percent and one percent increases in daily oil, NGL and gas sales volumes, respectively, and a 26 percent increase in average gas prices, respectively.

The following table provides average daily sales volumes for the three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2014	2013	2014	2013
Oil (BBLs)	88,973	67,674	82,485	68,650
NGLs (BBLs)	39,819	31,507	37,319	29,268
Gas (MCF)	343,711	320,938	336,749	334,876
Total (BOEs)	186,077	152,671	175,929	153,730

Average daily BOE sales volumes increased by 22 percent and 14 percent for the three and nine months ended September 30, 2014, respectively, as compared to the same respective periods in 2013, principally due to the Company's successful Spraberry/Wolfcamp and Eagle Ford Shale drilling programs.

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PIONEER NATURAL RESOURCES COMPANY

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, 2014 and 2013:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Oil (per BBL)	$	90.82	$	101.70	$	92.94	$	93.24
NGL (per BBL)	$	28.44	$	30.87	$	30.36	$	29.92
Gas (per MCF)	$	3.79	$	3.30	$	4.28	$	3.39
Total (per BOE)	$	56.51	$	58.39	$	58.20	$	54.71

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company’s areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast oil price. 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. Deficiency 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 further information on transportation commitment charges.

Interest and other income. Interest and other income for the three and nine months ended September 30, 2014 was $2 million and $9 million, respectively, as compared to $8 million and $3 million for the same respective periods in 2013. The changes in interest and other income for the three and nine months ended September 30, 2014, as compared to the same respective periods in 2013, are primarily due to changes between periods in the earnings attributable to vertical integration services provided to third-party working interest owners in wells owned and operated by the Company. 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, 2014, the Company recorded $341 million and $19 million, respectively, of net derivative gains on commodity price and interest rate derivatives, of which $3 million represented net cash receipts during the three months ended September 30, 2014 and $20 million represented net cash payments during the nine months ended September 30, 2014. During the three and nine months ended September 30, 2013, the Company recorded $102 million and a nominal amount of net derivative losses, respectively, of which $34 million and $122 million, respectively, reflected cash receipts. Derivative gains and losses result from changes in the fair values of the Company's derivative contracts. 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 $11 million for the three and nine months ended September 30, 2014, respectively, as compared to a $1 million net loss and $206 million net gain for the same respective periods in 2013.

The net gain for the nine months ended September 30, 2014 includes the Company's February 2014 sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million, which resulted in a gain of $2 million on the unproved properties. The Company also recognized a $1 million gain during the first quarter of 2014 associated with the sale of Sendero.

The net gain for the nine months ended September 30, 2013 is primarily associated with (i) the sale of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas for cash proceeds of $624 million, which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem and (ii) the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for cash proceeds of $38 million, which resulted in a gain of $22 million. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's gains and losses on the disposition of assets.

Oil and gas production costs. The Company recorded oil and gas production costs of $168 million and $493 million during the three and nine months ended September 30, 2014, respectively, as compared to $150 million and $440 million during the same

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respective periods in 2013. 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 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 each of the three and nine months ended September 30, 2014 decreased by eight percent and two percent, respectively, as compared to the same respective periods in 2013. The decrease in production costs per BOE during the three months ended September 30, 2014, as compared to the same period in 2013, is primarily reflective of decreases in lease operating expenses and third-party transportation charges. The decrease in production costs per BOE during the nine months ended September 30, 2014, as compared to the same period in 2013, is primarily reflective of an increase in net natural gas plant income resulting from increased gathering and processing revenues from processing third-party gas in Company-owned facilities and a decline in workover expenses, partially offset by increases in lease operating expenses.

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, 2014 and 2013:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Lease operating expenses	$	7.83		$	8.24		$	8.19		$	7.96
Third-party transportation charges	1.66			2.05			1.75			1.78
Net natural gas plant charges	(0.30		)	(0.37		)	(0.33		)	(0.15		)
Workover costs	0.63			0.72			0.66			0.89
Total production costs	$	9.82		$	10.64		$	10.27		$	10.48

Production and ad valorem taxes. The Company's production and ad valorem taxes were $58 million and $169 million during the three and nine months ended September 30, 2014, respectively, as compared to $49 million and $147 million for the same respective periods in 2013. 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, 2014 and 2013:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Production taxes	2.42		2.30		$	2.35	$	2.25
Ad valorem taxes	$	0.93	$	1.21	1.16		1.26
Total production and ad valorem taxes	$	3.35	$	3.51	$	3.51	$	3.51

Depletion, depreciation and amortization expense. The Company's DD&A expense was $274 million ($16.03 per BOE) and $734 million ($15.28 per BOE) for the three and nine months ended September 30, 2014, respectively, as compared to $222 million ($15.78 per BOE) and $650 million ($15.49 per BOE) during the same respective periods in 2013. The changes in per BOE DD&A expense during the three and nine months ended September 30, 2014, as compared to the same periods in 2013, are primarily due to the changes in depletion expense.

Depletion expense on oil and gas properties was $15.48 and $14.72 per BOE during the three and nine months ended September 30, 2014, respectively, as compared to $15.07 and $14.79 per BOE during the same respective periods in 2013. The changes in per BOE depletion expense during the three and nine months ended September 30, 2014, as compared to the same respective periods in 2013, are primarily due to (i) a decline in reserves due to negative revisions of previous estimates during the fourth quarter of 2013 to remove undeveloped vertical well locations that were no longer expected to be drilled as the Company shifted its planned capital expenditures to higher-rate-of-return horizontal drilling and (ii) a decline in proved reserves due to lower oil and NGL prices used in the Company's September 30, 2014 reserve estimates, offset by (iii) the impairment of proved properties in the Raton field during the fourth quarter of 2013, which reduced the Raton field's carrying value by $1.5 billion.

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. It is reasonably possible that the estimate of undiscounted future net cash flows attributable to its properties may

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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 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 longer-term commodity price outlooks ("Management's Price Outlooks") and (iv) increases or decreases in production and capital costs associated with these fields.

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense for the three and nine months ended September 30, 2014 and 2013 (in millions):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Geological and geophysical	$	21	$	21	$	69	$	56
Exploratory dry holes	1		—		5		—
Leasehold abandonments and other	—		9		6		9
	$	22	$	30	$	80	$	65

The Company's geological and geophysical costs increased by $13 million during the nine months ended September 30, 2014, as compared to the same period in 2013, primarily due to increased seismic and seismic interpretation expenditures supportive of drilling activities in the Spraberry/Wolfcamp field.

During the nine months ended September 30, 2014, the Company drilled and evaluated 241 exploration/extension wells, 240 of which were successfully completed as discoveries. During the same period in 2013, the Company drilled and evaluated 166 exploration/extension wells, 160 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and nine months ended September 30, 2014 was $81 million and $244 million, respectively, as compared to $72 million and $200 million for the same respective periods in 2013. The increases in general and administrative expense for the three and nine months ended September 30, 2014, as compared to the same respective periods in 2013, are primarily due to increases in expenses related to personnel, including contract labor, occupancy and information technology in support of the Company's capital expansion initiatives.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $3 million and $9 million for both the three and nine months ended September 30, 2014 and 2013, respectively. See Note I of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $46 million and $138 million for the three and nine months ended September 30, 2014, respectively, as compared to $45 million and $139 million during the same respective periods in 2013. The weighted average interest rate on the Company's indebtedness for the three and nine months ended September 30, 2014, including the effects of capitalized interest, were 6.6 percent and 6.3 percent, respectively, as compared to 6.7 percent and 6.2 percent for the same respective periods in 2013.

Other expense. Other expense was $20 million and $55 million for the three and nine months ended September 30, 2014, respectively, as compared to $24 million and $65 million during the same respective periods in 2013. The decrease in other expense for the nine months ended September 30, 2014, as compared to the same respective period in 2013, is primarily due to a decrease of $8 million in above market and idle drilling and well service equipment charges. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision. The Company recorded income tax provisions from continuing operations of $236 million and $319 million for the three and nine months ended September 30, 2014, respectively, as compared to $48 million and $281 million during the same respective periods in 2013. The Company's effective tax rates for the three and nine months ended September 30, 2014 were 36 percent and 34 percent, respectively, as compared to 40 percent and 37 percent for the same respective periods in 2013. The difference between the effective tax rate and the U.S. statutory tax rate of 35 percent during the nine months ended September 30, 2014 is primarily due to the recognition of a $21 million tax benefit related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.

Income/loss from discontinued operations, net of tax. The Company reported losses from discontinued operations, net of tax, of $37 million and $113 million for the three and nine months ended September 30, 2014, respectively, as compared to income from discontinued operations, net of tax, of $19 million and $52 million for the same respective periods in 2013. The decreases in earnings from discontinued operations for the three and nine months ended September 30, 2014, as compared to the same

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respective periods in 2013, are primarily due to (i) $80 million and $305 million of impairment charges for the three and nine months ended September 30, 2014, respectively, to reduce the carrying values of the Company's Barnett Shale field assets, Hugoton field assets and Pioneer Alaska to their estimated sales values less costs to sell. The impairment charges were partially offset by a reduction in DD&A for the three and nine months ended September 30, 2014 associated with those assets classified as held for sale. See Note C of the Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2014 was nominal, as compared to $7 million and $30 million for the same respective periods in 2013. The decreases in income attributable to noncontrolling interests for the three and nine months ended September 30, 2014, as compared to the same respective periods in 2013, are due to the Company's acquisition of all of the outstanding common units of Pioneer Southwest not owned by the Company in December 2013. The portion of income from noncontrolling interest for the three and nine months ended September 30, 2013 related to Pioneer Southwest was $7 million and $30 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, 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, proceeds from divestitures or external financing sources as discussed in "Capital resources" below.

The Company's capital expenditures during the nine months ended September 30, 2014, were $2.5 billion, consisting of $2.3 billion for drilling operations (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs and capital expenditures associated with Pioneer Alaska and Barnett Shale field assets prior to their sale) and $197 million for buildings, vertical integration and other plant and equipment additions. Based on results for the nine months ended September 30, 2014 and Management's Price Outlook, the Company expects its cash flows from operating activities, cash and cash equivalents on hand, proceeds from divestitures and, if necessary, availability under its Credit Facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2014.

Investing activities. Investing activities used $1.6 billion of cash during the nine months ended September 30, 2014, as compared to $1.5 billion of cash used in investing activities during the nine months ended September 30, 2013. The increase in cash used in investing activities for the nine months ending September 30, 2014, as compared to the nine months ended September 30, 2013, is primarily due to a $272 million increase in additions to oil and gas properties and a $64 million increase in additions to other assets, partially offset by a $170 million increase in proceeds from the disposition of assets. During the nine months ended September 30, 2014, the Company's expenditures for investing activities were primarily funded by net cash provided by operating activities and proceeds from disposition of assets.

Dividends/distributions. During February and August of both 2014 and 2013, 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.

During January 2013, April 2013 and July 2013, the Pioneer Southwest board of directors declared a quarterly distribution of $0.52 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $27 million during the nine months ended September 30, 2013.

Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments (including commitments to pay day rates for drilling rigs), capital funding obligations, derivative obligations, firm transportation and fractionation commitments, minimum annual gathering, treating 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, 2014, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) operating lease agreements, (ii) drilling commitments, (iii) firm transportation and fractionation commitments, (iv) open purchase commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates and gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput, open delivery commitments and 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. Since December 31, 2013, the primary changes in the Company's contractual obligations are (i) a $39 million increase in the fair value of the Company's derivative

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contracts and (ii) a reduction of $267 million in future firm gathering, processing, fractionation and transportation commitments conveyed as part of the Barnett Shale and Hugoton field asset divestitures. See Note C of the Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's divestiture of its Barnett Shale and Hugoton field assets.

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, 2014, these contracts (only commodity derivative contracts) represented net assets of $184 million. The ultimate liquidation value of the Company's commodity derivatives will be dependent upon actual future commodity prices, which may differ materially from the inputs used to determine the derivatives' fair values as of September 30, 2014. 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, 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 and cash on hand 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 availability under its Credit Facility, issue debt or equity securities or obtain capital from other sources, such as through the sale of nonstrategic assets.

Operating activities. Net cash provided by operating activities during the nine months ended September 30, 2014 was $1.8 billion, as compared to $1.6 billion during the same period in 2013. The increase in net cash provided by operating activities for the nine months ended September 30, 2014, as compared to the nine months ended September 30, 2013, is primarily due to an increase in oil, NGL and gas sales volumes as a result of the Company's successful drilling program, partially offset by a decrease in net cash flows from derivative settlements.

Asset divestitures. During the nine months ended September 30, 2014, the Company completed the sale of (i) the Company's Barnett Shale field net assets for cash proceeds of $150 million, (ii) the Company's Hugoton field net assets for cash proceeds of $328 million, (iii) Pioneer Alaska for cash proceeds of $267 million, (iv) Sendero for cash proceeds of $31 million (Sendero had $14 million of cash on hand at the time of the sale) and (v) proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million.

In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for total consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for cash proceeds of $624 million. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play.

Financing activities. Net cash used in financing activities during the nine months ended September 30, 2014 was $13 million, as compared to net cash provided by financing activities of $372 million during the same period in 2013. The decrease in net cash provided by financing activities during the nine months ended September 30, 2014, as compared to the same period of 2013, is primarily the result of a decrease of $1.3 billion of realized net proceeds from the Company's completion of an offering of its common stock in February 2013, partially offset by (i) a decrease in net principal payments on long-term debt of $879 million and (ii) a decrease of $26 million in distributions to noncontrolling interests.

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 and unused borrowing capacity under its Credit Facility. As of September 30, 2014, 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, 2014. The Company also had cash on hand of $550 million as of September 30, 2014. If internal cash flows and cash on hand 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 capital expenditures using borrowings under its Credit Facility, issuances of debt or equity securities or other sources, such as the sale 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 internal operating cash flows, cash

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on hand, proceeds from divestitures and, if necessary, available capacity under the Company's Credit Facility will be adequate to fund 2014 capital expenditures, dividend payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

Debt ratings. The Company is rated as 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: production growth opportunities, liquidity, debt levels, asset composition and 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, 2014 was $9.3 billion, consisting of $550 million of cash and cash equivalents, debt of $2.7 billion and equity of $7.2 billion. The Company's net debt to net book capitalization decreased to 23 percent at September 30, 2014 from 25 percent at December 31, 2013, primarily due to an increase in cash and cash equivalents of $157 million. The Company's ratio of current assets to current liabilities decreased to 1.04 to 1.00 at September 30, 2014, as compared to 1.38 to 1.00 at December 31, 2013, primarily due to a decrease in net assets due to the sale of the Company's Hugoton and Barnett Shale net assets in September 2014 and Pioneer Alaska in April 2014.

New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in "Item1. Financial Statements".

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2013. 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, 2013.

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, 2014:



	Derivative Contract Net Assets
	Commodities		Interest Rates			Total
	(in millions)
Fair value of contracts outstanding as of December 31, 2013	$	145	$	—		$	145
Changes in contract fair value	1		18			19
Contract maturity payments (receipts)	36		(4		)	32
Contract terminations payments (receipts)	2		(14		)	(12		)
Fair value of contracts outstanding as of September 30, 2014	$	184	$	—		$	184

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

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The following table provides information about financial instruments to which the Company was a party as of September 30, 2014 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, 2014. The Company had no outstanding variable rate debt as of September 30, 2014, but presents for the reader's information the average variable contractual rates for its credit facility projected forward proportionate to the forward yield curve for LIBOR on October 30, 2014.



	Three Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at September 30,
	2014			2015 (b)			2016			2017			2018			Thereafter			Total		2014
	(dollars in millions)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	455		$	485		$	450		$	1,300		$	2,690	$	3,025
Weighted average fixed interest rate	6.15		%	6.15		%	6.17		%	6.11		%	5.91		%	5.81		%
Variable rate principal maturities:
Weighted average variable interest rate	1.74		%	2.01		%	2.92		%	3.76		%	—			—

____________________


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

(b)

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, 2014. 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 relative to 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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	Three Months Ending December 31,			Year Ending December 31,					Asset (Liability) Fair Value at September 30,
	2014			2015			2016		2014 (a)
									(in millions)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (b)(c)	69,000			95,767			59,000		$	150
Weighted average ceiling price per BBL	$	114.05		$	99.36		$	98.55
Weighted average floor price per BBL	$	93.70		$	87.98		$	86.14
Weighted average short put price per BBL	$	77.61		$	73.54		$	74.75
Swap contracts	15,000			—			—		$	8
Weighted average fixed price per BBL	$	96.31		$	—		$	—
Average forward NYMEX oil prices (d)	$	81.12		$	80.51		$	80.34
Rollfactor swap contracts (e)(f)	6,630			5,000			—		$	1
Weighted average fixed price per BBL	$	1.10		$	0.60		$	—
Average forward rollfactor prices (d)	$	0.27		$	0.06		$	—
NGL Derivatives:
Average daily notional BBL volumes:
Natural gasoline collar contracts with short puts (g)	3,500			—			—		$	1
Weighted average ceiling price per BBL	$	97.93		$	—		$	—
Weighted average floor price per BBL	$	90.14		$	—		$	—
Weighted average short put price per BBL	$	81.36		$	—		$	—
Average forward NGL prices (h)	$	71.51		$	—		$	—
Ethane collar contracts (g)	3,000			—			—		$	—
Weighted average ceiling price per BBL	$	13.72		$	—		$	—
Weighted average floor price per BBL	$	10.78		$	—		$	—
Average forward NGL prices (h)	$	9.37		$	—		$	—
Ethane swap contracts (g)(i)	—			—			3,000		$	—
Weighted average fixed price per BBL	$	—		$	—		$	12.39
Average forward NGL prices (h)	$	—		$	—		$	11.29
Propane swap contracts (g)	1,674			—			—		$	1
Weighted average fixed price per BBL	$	47.95		$	—		$	—
Average forward NGL prices (h)	$	37.96		$	—		$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts	115,000			285,000			20,000		$	23
Weighted average ceiling price per MMBTU	$	4.70		$	5.07		$	5.36
Weighted average floor price per MMBTU	$	4.00		$	4.00		$	4.00
Weighted average short put price per MMBTU	$	3.00		$	3.00		$	3.00
Swap contracts	195,000			20,000			70,000		$	1
Weighted average fixed price per MMBTU	$	4.04		$	4.31		$	4.06
Average forward NYMEX gas prices (c)	$	3.83		$	3.76		$	3.94
Mid-Continent basis swap contracts (j)	120,000			95,000			—		$	(1	)
Weighted average fixed price per MMBTU	$	(0.22	)	$	(0.24	)	$	—
Permian Basin basis swap contracts (j)	10,000			10,000			—
Weighted average fixed price per MMBTU	$	(0.15	)	$	(0.13	)	$	—
Average forward basis differential prices (k)	$	(0.06	)	$	(0.22	)	$	—
Permian Basin basis swap contracts (l)	16,630			—			—
Weighted average fixed price per MMBTU	$	0.34		$	—		$	—
Average forward basis differential prices (m)	$	0.28		$	—		$	—

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(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)

Counterparties have the option to extend 5,000 BBLs per day of 2015 collar contracts with short puts for an additional year with a ceiling price of $100.08 per BBL, a floor price of $90.00 per BBL and a short put price of $80.00 per BBL. The option to extend is exercisable on December 31, 2015. These contracts give the counterparties the option to extend the contracts under the same terms for an additional year if the option to extend is exercised by the counterparties on December 31, 2015.


(c)	During the period from October 1, 2014 through October 30, 2014, the Company entered into an additional 11,000 BBL per day of 2016 collar contracts with short puts with a ceiling price of $87.76 per BBL, a floor price of $82.82 per BBL and a short put price of $72.82 per BBL.


(d)	The average forward NYMEX oil and gas prices are based on October 30, 2014 market quotes.


(e)	Represents swaps that fix the difference between (i) each day's price per BBL of WTI for the first nearby month less (ii) the price per BBL of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per BBL of WTI for the first nearby month less (iv) the price per BBL of WTI for the third nearby NYMEX month, multiplied by .3333.


(f)	During the period from October 1, 2014 through October 30, 2014, the Company entered into an additional 12,000 BBL per day of 2015 rollfactor swap contracts with a NYMEX roll price of $0.15 per BBL.


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


(h)	Forward component NGL prices are derived from respective active-market NGL component price quotes as of October 30, 2014.


(i)	During the period from October 1, 2014 through October 30, 2014, the Company entered into an additional 1,000 BBL per day of 2016 swap contracts for ethane with a fixed price of $11.97 per BBL.


(j)	Represent swaps that fix the basis differentials between the index prices at which the Company sells its Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts.


(k)	The average forward basis differential prices are based on October 30, 2014 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.


(l)	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.


(m)	The average forward basis differential prices are based on October 30, 2014 market quotes for basis differentials between Permian Basin index prices and southern California index prices.

Marketing and basis differential derivatives. 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, 2014, the Company had (i) marketing gas index swap contracts for 40,000 MMBTU per day for the remainder of 2014 with a price differential of 0.31 per MMBTU between Inside FERC-EPNG (Permian Basin) index prices and NGI-SoCal Border Monthly index prices and (ii) marketing oil index swap contracts for 10,000 BBL per day for the remainder of 2014 with a price differential of $2.81 per BBL between Cushing WTI and Louisiana Light Sweet oil ("LLS")and 10,000 BBL per day for 2015 with a price differential of $2.99 per BBL between Cushing WTI and LLS. As of September 30, 2014, these positions had asset fair values of $28 thousand and $19 thousand, respectively. Based on October 30, 2014 market quotes, the respective average forward basis differential price was $0.28 per MMBTU for basis differentials between the relevant quoted forward gas index prices and $3.00 per BBL and $2.85 per BBL for respective basis differentials between the relevant quoted forward oil index prices.

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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, 2014 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 such 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, you should carefully consider the risks discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2013, 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," which risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

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

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of treasury stock under plans or programs during the three months ended September 30, 2014:



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 2014	948	$	229.81	—
August 2014	1,904	$	203.48	—
September 2014	—	$	—	—
Total	2,852	$	212.23	—	$	—

____________________


(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. 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 Quarterly Report filed on Form 10-Q.

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PIONEER NATURAL RESOURCES COMPANY

Item 6. Exhibits

Exhibits



Exhibit Number		Description

10.1	(a) —	Severance Agreement, dated effective January 14, 2010, between the Company and J. D. Hall.

10.2	(a) —	Change in Control Agreement, dated March 4, 2013, between the Company and J. D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement.

10.3	(a) —	Indemnification Agreement, dated March 4, 2013, between the Company and J.D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement.

10.4	(a) —	Severance Agreement, dated effective August 10, 2005, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Severance Agreement.

10.5	(a) —	Amendment to Severance Agreement, dated December 8, 2008, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Amendment to Severance Agreement.

10.6	—	Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).

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

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

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

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

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

95.1	(a) —	Mine Safety Disclosures.

101.INS	(a) —	XBRL Instance Document.

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

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

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

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

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

_____________


(a)	Filed herewith.


(b)	Furnished herewith.

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PIONEER NATURAL RESOURCES COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereto duly authorized.



	PIONEER NATURAL RESOURCES COMPANY

Date: November 4, 2014	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy,
		Executive Vice President and Chief Financial Officer

Date: November 4, 2014	By:	/s/ MARGARET M. MONTEMAYOR
		Margaret M. Montemayor,
		Vice President and Chief Accounting Officer

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PIONEER NATURAL RESOURCES COMPANY

Exhibit Index



Exhibit Number		Description
10.1	(a) —	Severance Agreement, dated effective January 14, 2010, between the Company and J. D. Hall.

10.2	(a) —	Change in Control Agreement, dated March 4, 2013, between the Company and J. D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement.

10.3	(a) —	Indemnification Agreement, dated March 4, 2013, between the Company and J.D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement.

10.4	(a) —	Severance Agreement, dated effective August 10, 2005, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Severance Agreement.

10.5	(a) —	Amendment to Severance Agreement, dated December 8, 2008, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Amendment to Severance Agreement.

10.6	—	Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).

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.