Edgar Filing: PIONEER NATURAL RESOURCES CO

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PXD-2013.09.30

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, 2013



¨	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 November 4, 2013 138,667,689

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, 2013 and December 31, 2012	5

	Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012	7

	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2013 and 2012	8

	Consolidated Statement of Equity for the nine months ended September 30, 2013	9

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	10

	Notes to Consolidated Financial Statements	11

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

Item 4.	Controls and Procedures	47

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	48

Item 1A.	Risk Factors	48

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 4.	Mine Safety Disclosures	49

Item 6.	Exhibits	50

Signatures		51

Exhibit Index		52

Table of Contents

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, satisfaction of the conditions to the closing of the Company's agreement to sell its Alaska subsidiary, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's 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, the risks associated with the proposed merger transaction with Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest"), which is described in more detail in this Report, pursuant to which Pioneer Southwest would become a wholly-owned subsidiary of the Company, including the risks that the merger transaction will not be consummated and the anticipated benefits from the merger transaction cannot be fully realized, 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, 2012 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.

Table of Contents

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.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)



	September 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	744,120		$	229,396
Accounts receivable:
Trade, net	408,240			316,854
Due from affiliates	5,212			3,299
Income taxes receivable	10,168			7,447
Inventories	226,438			197,056
Prepaid expenses	19,984			13,438
Other current assets:
Derivatives	114,166			279,119
Other	4,933			3,746
Total current assets	1,533,261			1,050,355
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	15,924,526			14,259,708
Unproved properties	149,782			231,555
Accumulated depletion, depreciation and amortization	(5,086,258		)	(4,412,913		)
Total property, plant and equipment	10,988,050			10,078,350
Goodwill	279,687			298,142
Other property and equipment, net	1,258,627			1,217,694
Other assets:
Investment in unconsolidated affiliate	235,631			204,129
Derivatives	86,574			55,257
Other, net	163,114			165,103
	$	14,544,944		$	13,069,030

The financial information included as of September 30, 2013 has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in thousands, except share data)



	September 30, 2013			December 31, 2012
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	954,311		$	729,942
Due to affiliates	106,073			96,935
Interest payable	36,509			68,083
Income taxes payable	129			208
Deferred income taxes	60,340			86,481
Other current liabilities:
Derivatives	6,436			13,416
Other	51,013			39,725
Total current liabilities	1,214,811			1,034,790
Long-term debt	2,851,212			3,721,193
Derivatives	7,719			12,307
Deferred income taxes	2,415,663			2,140,416
Other liabilities	292,788			293,016
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 145,828,410 and 134,966,740 shares issued at September 30, 2013 and December 31, 2012, respectively	1,458			1,350
Additional paid-in capital	4,870,566			3,683,934
Treasury stock at cost: 7,161,364 and 11,611,093 at September 30, 2013 and December 31, 2012, respectively	(323,348		)	(510,570		)
Retained earnings	3,032,531			2,514,640
Total equity attributable to common stockholders	7,581,207			5,689,354
Noncontrolling interests in consolidating subsidiaries	181,544			177,954
Total equity	7,762,751			5,867,308
Commitments and contingencies
	$	14,544,944		$	13,069,030

The financial information included as of September 30, 2013 has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues and other income:
Oil and gas	$	908,757		$	716,327		$	2,541,748		$	2,077,020
Interest and other	21,087			10,256			41,561			31,450
Derivative gains (losses), net	(102,535		)	(123,994		)	(333		)	243,568
Gain (loss) on disposition of assets, net	(487		)	12,848			214,917			57,584
	826,822			615,437			2,797,893			2,409,622
Costs and expenses:
Oil and gas production	181,340			179,687			529,968			461,549
Production and ad valorem taxes	53,946			49,779			162,080			140,070
Depletion, depreciation and amortization	256,260			207,398			736,613			589,737
Impairment of oil and gas properties	—			—			—			444,880
Exploration and abandonments	31,509			27,039			83,109			117,504
General and administrative	73,722			62,567			204,127			180,591
Accretion of discount on asset retirement obligations	3,180			2,497			9,499			7,371
Interest	45,138			54,441			138,678			150,307
Other	24,947			32,011			65,007			86,269
	670,042			615,419			1,929,081			2,178,278
Income from continuing operations before income taxes	156,780			18			868,812			231,344
Income tax provision	(58,233		)	(10,614		)	(309,591		)	(83,231		)
Income (loss) from continuing operations	98,547			(10,596		)	559,221			148,113
Income (loss) from discontinued operations, net of tax	—			32,295			(465		)	55,007
Net income	98,547			21,699			558,756			203,120
Net income attributable to noncontrolling interests	(7,422		)	(2,475		)	(29,705		)	(39,669		)
Net income attributable to common stockholders	$	91,125		$	19,224		$	529,051		$	163,451

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	0.65		$	(0.11	)	$	3.87		$	0.87
Income (loss) from discontinued operations attributable to common stockholders	—			0.26			—			0.44
Net income attributable to common stockholders	$	0.65		$	0.15		$	3.87		$	1.31
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	0.65		$	(0.11	)	$	3.82		$	0.85
Income (loss) from discontinued operations attributable to common stockholders	—			0.26			—			0.43
Net income attributable to common stockholders	$	0.65		$	0.15		$	3.82		$	1.28
Weighted average shares outstanding:
Basic	138,586			123,111			135,057			122,874
Diluted	138,946			123,111			136,835			126,111
Dividends declared per share	$	0.04		$	0.04		$	0.08		$	0.08

Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	91,125		$	(13,071	)	$	529,516		$	108,444
Income (loss) from discontinued operations, net of tax	—			32,295			(465		)	55,007
Net income	$	91,125		$	19,224		$	529,051		$	163,451

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.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Net income	$	98,547		$	21,699		$	558,756		$	203,120
Other comprehensive activity:
Net hedge losses included in continuing operations	—			—			—			4,855
Income tax benefit	—			—			—			(1,725		)
Other comprehensive activity	—			—			—			3,130
Comprehensive income	98,547			21,699			558,756			206,250
Comprehensive income attributable to the noncontrolling interests	(7,422		)	(2,475		)	(29,705		)	(39,669		)
Comprehensive income attributable to common stockholders	$	91,125		$	19,224		$	529,051		$	166,581

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(in thousands, 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, 2012	123,356		$	1,350	$	3,683,934		$	(510,570	)	$	2,514,640		$	177,954		$	5,867,308
Issuance of common stock	10,350		103		1,280,813			—			—			—			1,280,916
Dividends declared ($0.08 per share)	—		—		—			—			(11,160		)	—			(11,160		)
Exercise of long-term incentive plan stock options and employee stock purchases	222		—		11			10,043			—			—			10,054
Treasury stock purchases	(154	)	—		—			(20,053		)	—			—			(20,053		)
Conversion of 2.875% senior convertible notes	4,381		—		(197,240		)	197,232			—			—			(8		)
Tax benefit related to conversion of 2.875% senior convertible notes	—		—		38,415			—			—			—			38,415
Tax benefit related to stock-based compensation	—		—		12,612			—			—			—			12,612
Compensation costs:
Vested compensation awards, net	512		5		(5		)	—			—			—			—
Compensation costs included in net income	—		—		52,026			—			—			838			52,864
Cash distributions to noncontrolling interests	—		—		—			—			—			(26,953		)	(26,953		)
Net income	—		—		—			—			529,051			29,705			558,756
Balance as of September 30, 2013	138,667		$	1,458	$	4,870,566		$	(323,348	)	$	3,032,531		$	181,544		$	7,762,751

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.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)



	Nine Months Ended September 30,
	2013			2012
Cash flows from operating activities:
Net income	$	558,756		$	203,120
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	736,613			589,737
Impairment of oil and gas properties	—			444,880
Exploration expenses, including dry holes	20,238			52,574
Deferred income taxes	300,312			76,180
Gain on disposition of assets, net	(214,917		)	(57,584		)
Accretion of discount on asset retirement obligations	9,499			7,371
Discontinued operations	(158		)	(19,245		)
Interest expense	13,039			26,812
Derivative related activity	122,068			93,088
Amortization of stock-based compensation	52,789			46,899
Amortization of deferred revenue	—			(31,494		)
Other noncash items	559			(20,998		)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(88,993		)	(7,946		)
Income taxes receivable	(2,721		)	(8,632		)
Inventories	(28,015		)	(6,347		)
Prepaid expenses	(7,289		)	(6,772		)
Other current assets	1,778			7,898
Accounts payable	184,345			23,554
Interest payable	(31,574		)	(16,302		)
Income taxes payable	(98		)	(9,566		)
Other current liabilities	(21,963		)	(29,757		)
Net cash provided by operating activities	1,604,268			1,357,470
Cash flows from investing activities:
Proceeds from disposition of assets	685,188			92,473
Payments for acquisition, net of cash acquired	—			(296,959		)
Additions to oil and gas properties	(1,987,200		)	(2,072,800		)
Additions to other assets and other property and equipment, net	(159,896		)	(238,803		)
Net cash used in investing activities	(1,461,908		)	(2,516,089		)
Cash flows from financing activities:
Borrowings under long-term debt	443,864			1,608,618
Principal payments on long-term debt	(1,322,771		)	(596,000		)
Proceeds from issuance of common stock, net of issuance costs	1,280,916			—
Distributions to noncontrolling interests	(26,953		)	(26,970		)
Borrowings (payments) of other liabilities	237			(894		)
Exercise of long-term incentive plan stock options and employee stock purchases	10,054			7,072
Purchases of treasury stock	(20,053		)	(56,677		)
Excess tax benefits from share-based payment arrangements	12,612			31,330
Payments of financing fees	(8		)	(6,430		)
Dividends paid	(5,534		)	(5,028		)
Net cash provided by financing activities	372,364			955,021
Net increase (decrease) in cash and cash equivalents	514,724			(203,598		)
Cash and cash equivalents, beginning of period	229,396			537,484
Cash and cash equivalents, end of period	$	744,120		$	333,886

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.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(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 field operations in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Barnett Shale Combo play in North Texas, the Raton field in southeastern Colorado, the Hugoton field in southwest Kansas, the West Panhandle field in the Texas Panhandle and Alaska.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2013 and for the three and nine months ended September 30, 2013 and 2012 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, 2012.

Certain reclassifications have been made to the 2012 financial statement and footnote amounts in order to conform to the 2013 presentation, including classifying the results of the Company's Barnett Shale operations, previously recorded as discontinued operations for the three and nine months ended September 30, 2012, as income from continuing operations.

Issuance of common stock. In February 2013, the Company issued 10.35 million shares of its common stock and realized $1.3 billion of cash proceeds, net of associated underwriting and offering expenses.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest"). The Company owns and controls Pioneer Natural Resources GP LLC (the "General Partner"), which manages Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations and cash flows of Pioneer Southwest are consolidated with those of the Company. Noncontrolling interests in consolidated subsidiaries includes $167.9 million attributable to outstanding Pioneer Southwest common units held by unitholders other than Pioneer or its subsidiaries as of September 30, 2013. See Note C for discussion of a pending merger between the Company and Pioneer Southwest.

New accounting pronouncements. In July 2013, the Financial Accounting Standards Boards issued Accounting Standards Update ("ASU") 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists," which provides guidance on the presentation of unrecognized tax benefits. ASU 2013-11 was adopted by the Company during the third quarter of 2013.

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of the Company acquired an industrial sand mining business that is now named Premier Silica LLC ("Premier Silica"). Premier Silica's primary mine operations are in Brady, Texas. The Brady mine facilities primarily produce, process and provide sand to the Company for use as proppant in its fracture stimulation of oil and gas wells in Texas. Premier Silica's sand production that is in excess of the Company's sand needs for fracture stimulation and sand production that is not usable for fracture stimulation is primarily sold to third parties for industrial and recreational purposes. The aggregate purchase price of Premier Silica was $297.1 million, including closing adjustments.

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(Unaudited)

Divestitures Recorded in Continuing Operations

Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem"), a U.S. subsidiary of the Sinochem Group, 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 in West Texas for total consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $621.2 million, including normal closing adjustments, resulting in a pretax gain of $179.7 million. The Company reduced the carrying value of goodwill and the gain recognized associated with the sale by $18.5 million, reflecting the portion of the Company's goodwill that related to the horizontal Wolfcamp Shale assets that were sold. 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 horizontal Wolfcamp Shale play.

Sales of unproved oil and gas properties. For the nine months ended September 30, 2013, the Company's pretax gain on disposition of assets from continuing operations of $214.9 million was primarily associated with the Southern Wolfcamp transaction described above. Additionally, the Company sold (i) its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38.1 million, which resulted in a pretax gain of $22.4 million, and (ii) its interest in certain unproved oil and gas properties in the Barnett Shale for net cash proceeds of $11.6 million, which resulted in a pretax gain of $8.7 million.

For the three months ended September 30, 2012, the Company's pretax gain on disposition of assets was $12.8 million, primarily associated with the sale of the Company's interest in the Cosmopolitan Unit in the Cook Inlet of Alaska to unaffiliated third parties for cash proceeds of $10.1 million, which together with certain Company obligations assumed by the purchasers, resulted in a pretax gain of $12.6 million. Additionally, the Company's pretax gain on the disposition of assets for the nine months ended September 30, 2012 of $57.6 million includes a first quarter 2012 sale of a portion of its interest in an unproved oil and gas properties in the Eagle Ford Shale field for net cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million.

Divestitures Recorded as Discontinued Operations

South Africa. During the first quarter of 2012, the Company agreed to sell its assets in South Africa ("Pioneer South Africa"), effective January 1, 2012, for $60.0 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities associated with the assets. In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a third quarter 2012 pretax gain of $28.6 million. The Company classified Pioneer South Africa's results of operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

For the three and nine months ended September 30, 2012, the Company recognized revenues and other income of $38.1 million and $77.9 million, respectively, and pretax earnings of $37.2 million and $71.2 million, respectively, associated with discontinued operations, principally related to the results of operations and gain from the sale of Pioneer South Africa prior to its divestiture in August 2012.

Pending Merger

On August 9, 2013, the Company entered into an Agreement and Plan of Merger with Pioneer Natural Resources USA, Inc., a wholly-owned subsidiary of the Company ("Pioneer USA"), PNR Acquisition Company, LLC, a wholly-owned subsidiary of the Company ("MergerCo"), Pioneer Southwest and the General Partner, which was amended on October 25, 2013 (as amended, the "Merger Agreement").

Pursuant to the Merger Agreement, MergerCo will merge with and into Pioneer Southwest with Pioneer Southwest surviving the merger (the "Merger"), such that following the Merger, the General Partner will remain a wholly-owned subsidiary of the Company and the sole general partner of Pioneer Southwest, and Pioneer USA will be the sole limited partner of Pioneer Southwest. Except for the common units owned by the Company, all of the common units outstanding as of the closing of the Merger will be cancelled and, except for the dissenting units (as defined in the next paragraph), converted into the right to receive 0.2325 of a share of common stock of the Company per common unit.

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Pursuant to the terms and conditions of the Merger Agreement, common units that are owned by a unitholder (a) other than Pioneer Southwest or its subsidiaries or the Company or its subsidiaries, (b) who does not vote at the special meeting of Pioneer Southwest in favor of the proposal to approve the Merger Agreement and the transactions contemplated thereby, including the Merger, and (c) who is entitled to demand and properly demands appraisal of such common units (the "dissenting units") pursuant to, and who complies in all respects with, the provisions of the Merger Agreement regarding appraisal rights (the "dissenting unitholders") will not be converted into the right to receive the merger consideration, but instead will be entitled to payment of the fair value of such dissenting units pursuant to and in accordance with the provisions of the Merger Agreement, unless and until such dissenting unitholder shall have failed to perfect or shall have effectively withdrawn or lost the appraisal rights. If a dissenting unitholder fails to perfect or effectively withdraws or loses the appraisal rights, then, as of the occurrence of such event or the closing of the Merger, whichever occurs later, each of such dissenting unitholder's dissenting units will be converted into the right to receive 0.2325 of a share of common stock of the Company per common unit.

The Merger Agreement provides that regular quarterly distributions on the Pioneer Southwest's common units, not to exceed $0.52 per common unit per quarter (which $0.52 per common unit is equivalent to the most recent distribution declared for the quarter ended September 30, 2013), are to continue until the closing of the Merger. Regular distributions for a quarter are declared late in the first month following such quarter, and no distribution will be paid for a quarter if the Merger closes prior to the normal record date for such distribution. No fractional shares of the Company's common stock will be issued in the Merger. In lieu of receiving any fractional share of common stock to which any holder of the Pioneer Southwest's common units would otherwise have been entitled, after aggregating all fractions of shares to which such holder would be entitled, any fractional share will be rounded up to a whole share of common stock of the Company. The closing of the Merger is subject to certain closing conditions, including the approval of the Merger Agreement and the transactions contemplated thereby by the affirmative vote of holders of a majority of the outstanding common units entitled to vote at a special meeting of the unitholders of Pioneer Southwest. Pursuant to a voting agreement, the Company has agreed to cause the common units owned by it and its subsidiaries to be voted in favor of the Merger, which units represent 52.4 percent of Pioneer Southwest's outstanding common units and therefore constitute a sufficient number of common units to approve the Merger at the special meeting of the unitholders of Pioneer Southwest. The parties anticipate that the Merger will close in the fourth quarter of 2013, pending the satisfaction of certain conditions thereto. See Note J for a description of the litigation contingencies associated with the Merger.

NOTE D. Fair Value Measurements

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

Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:


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


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


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

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(Unaudited)

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

The following table presents the Company's assets and liabilities that are measured at fair value as of September 30, 2013:



	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, 2013
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	149	$	147	$	—	$	296
Commodity derivatives	—		191,226		—		191,226
Interest rate derivatives	—		9,514		—		9,514
Deferred compensation plan assets	59,939		—		—		59,939
Total assets	60,088		200,887		—		260,975
Liabilities:
Commodity derivatives	—		11,028		—		11,028
Interest rate derivatives	—		3,127		—		3,127
Total liabilities	—		14,155		—		14,155
Total recurring fair value measurements	$	60,088	$	186,732	$	—	$	246,820

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities that are both actively traded and not actively traded on major exchanges. 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, 2013, substantially all of the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain trading securities that are not actively traded on major exchanges were classified as Level 2 inputs.

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.

Interest rate derivatives. The Company's interest rate derivative assets as of September 30, 2013 represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of September 30, 2013 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate ("LIBOR") yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset measurements represent Level 2 inputs in the hierarchy.

Assets and liabilities measured at fair value on a nonrecurring basis. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate their carrying values may not be fully recoverable. During the six months ended June 30, 2012, reductions in management's longer-term commodity price outlooks ("Management's Price Outlooks") provided indications of possible impairment of the Company's dry gas properties in the Barnett

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(Unaudited)

Shale field in North Texas. As a result of management's assessments, during the second quarter of 2012, the Company recognized a pretax noncash impairment charge of $444.9 million to reduce the carrying value of the Barnett Shale field to its estimated fair value. The Company calculated the estimated fair value of the Barnett Shale field as of June 30, 2012 using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of Barnett Shale field's discounted future cash flows as of June 30, 2012 included Management's Price Outlooks for (i) oil and gas prices of $87.09 per barrel ("BBL") for oil and $4.64 per million British thermal units ("MMBTU") for gas, (ii) production costs, (iii) capital expenditures, (iv) production and (v) estimated proved reserves and risk-adjusted probable reserves. Management's commodity price outlooks represent longer-term outlooks that are developed based on third-party futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

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 sheet as of September 30, 2013 and December 31, 2012 are as follows:



	September 30, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	2,851,212	$	3,247,459	$	3,721,193	$	4,555,770

Long-term debt includes the Company's credit facility, the Pioneer Southwest 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 facilities. The fair values of the Company's and Pioneer Southwest's credit facilities are 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 (in the case of the Company's credit facility) or LIBOR (in the case of the Pioneer Southwest credit facility) and (iii) the applicable credit-adjustments.

Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.

The Company has other financial instruments consisting primarily of 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 certain assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.

NOTE E. Derivative Financial Instruments

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

The following table sets forth the volumes per day in BBLs associated with the Company's outstanding oil derivative contracts as of September 30, 2013 and the weighted average oil prices per BBL for those contracts:



	Three Months Ending December 31,		Year Ending December 31,
	2013		2014		2015		2016
Collar contracts with short puts:
Volume (BBL)	69,000		69,000		85,000		25,000
Price per BBL:
Ceiling	$	120.55	$	114.05	$	98.98	$	93.30
Floor	$	91.39	$	93.70	$	88.06	$	85.00
Short put	$	74.22	$	77.61	$	73.06	$	70.00
Swap contracts:
Volume (BBL)	9,750		10,000		—		—
Price per BBL	$	95.57	$	93.87	$	—	$	—
Rollfactor swap contracts:
Volume (BBL)	11,000		19,000		—		—
NYMEX roll price (a)	$	0.85	$	0.45	$	—	$	—
Basis swap contracts:
Cushing to LLS index swap volume (BBL)	3,000		—		—		—
Price per BBL (b)	$	8.53	$	—	$	—	$	—

____________________


(a)	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.


(b)	Basis differential price between Cushing WTI and Louisiana Light Sweet crude ("LLS").

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

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 product component prices.

The following table sets forth the volumes per day in BBLs associated with the Company's outstanding NGL derivative contracts as of September 30, 2013 and the weighted average NGL prices per BBL for those contracts:



	Three Months Ending December 31,		Year Ending December 31,
	2013		2014
Collar contracts with short puts (a):
Volume (BBL)	1,064		1,000
Price per BBL:
Ceiling	$	105.28	$	109.50
Floor	$	89.30	$	95.00
Short put	$	75.20	$	80.00
Collar contracts (b):
Volume (BBL)	2,500		3,000
Price per BBL:
Ceiling	$	12.68	$	13.72
Floor	$	10.50	$	10.78

____________________


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


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

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 actual index prices at which the gas is sold.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

The following table sets forth the volumes per day in MMBTUs associated with the Company's outstanding gas derivative contracts as of September 30, 2013 and the weighted average gas prices per MMBTU for those contracts:



	Three Months Ending December 31,			Year Ending December 31,
	2013			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
Collar contracts:
Volume (MMBTU)	152,500			—			—			—
Price per MMBTU:
Ceiling	$	6.22		$	—		$	—		$	—
Floor	$	4.98		$	—		$	—		$	—
Swap contracts:
Volume (MMBTU)	165,870			175,000			20,000			—
Price per MMBTU	$	5.10		$	4.02		$	4.31		$	—
Basis swap contracts:
Volume (MMBTU) (a)	162,500			75,082			30,000			—
Price per MMBTU	$	(0.22	)	$	(0.19	)	$	(0.18	)	$	—

____________________


(a)	Subsequent to September 30, 2013, the Company entered into additional basis swap contracts for 10,000 MMBTU per day of the Company's 2014 production with a negative price differential of $0.26 per MMBTU between the relevant index price and the NYMEX price.

Interest rate derivative activities. During the second quarter of 2013, the Company terminated its interest rate derivative contracts that locked in a fixed forward annual interest rate of 3.21 percent, for a 10-year period ending in December 2025, on a notional amount of $250 million and received cash proceeds of $482 thousand.

As of September 30, 2013, the Company was a party to interest rate derivative contracts whereby the Company will receive a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.11 percent on a notional amount of $400 million through July 15, 2022.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of September 30, 2013 and December 31, 2012 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(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, 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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	117,191	$	(12,368	)	$	104,823
Interest rate derivatives	Derivatives - current	$	9,342	$	—		$	9,342
Commodity price derivatives	Derivatives - noncurrent	$	96,371	$	(9,968	)	86,403
Interest rate derivatives	Derivatives - noncurrent	$	15,767	$	(15,595	)	$	172
							$	200,740
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	18,804	$	(12,368	)	$	6,436
Commodity price derivatives	Derivatives - noncurrent	$	14,560	$	(9,968	)	4,592
Interest rate derivatives	Derivatives - noncurrent	$	18,722	$	(15,595	)	$	3,127
							$	14,155



Fair Value of Derivative Instruments as of December 31, 2012
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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	286,805	$	(7,686	)	$	279,119
Commodity price derivatives	Derivatives - noncurrent	$	61,618	$	(6,361	)	55,257
							$	334,376
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	21,102	$	(7,686	)	$	13,416
Commodity price derivatives	Derivatives - noncurrent	$	8,944	$	(6,361	)	2,583
Interest rate derivatives	Derivatives - noncurrent	$	9,724	$	—		9,724
							$	25,723

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(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	2013			2012			2013			2012
		(in thousands)
Commodity price derivatives	Derivative gains (losses), net	$	(108,922	)	$	(118,795	)	$	(16,926	)	$	267,806
Interest rate derivatives	Derivative gains (losses), net	6,387			(5,199		)	16,593			(24,238		)
Total		$	(102,535	)	$	(123,994	)	$	(333	)	$	243,568

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. After an exploratory well has been completed and found oil and gas reserves, a determination may be pending as to whether the oil and gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The 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, 2013:



	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
	(in thousands)
Beginning capitalized exploratory costs	$	255,001		$	212,670
Additions to exploratory costs pending the determination of proved reserves	252,884			945,001
Reclassification due to determination of proved reserves	(168,299		)	(720,338		)
Disposition of assets	(5,251		)	(92,955		)
Exploratory well costs charged to exploration expense	433			(9,610		)
Ending capitalized exploratory costs	$	334,768		$	334,768

The following table provides an aging, as of September 30, 2013 and December 31, 2012, 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, 2013		December 31, 2012
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	188,511	$	190,678
More than one year	146,257		21,992
	$	334,768	$	212,670

Number of projects with exploratory costs that have been suspended for a period greater than one year	2		1

Alaska - Oooguruk. As of September 30, 2013 and December 31, 2012, the Company had $30.8 million and $22.0 million, respectively, of suspended well costs recorded for the K-13 well in the Alaska Oooguruk field. Drilling on the K-13 well was completed during September 2011. During well completion operations, subsurface damages were sustained. The Company

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

performed repairs and recompleted the well during the third quarter of 2013. The well is currently undergoing production tests and may require additional stimulation work that, if required, is expected to be completed during the first quarter of 2014.

Alaska - Nuna. The Company's Nuna project, which has $115.5 million of suspended project costs as of September 30, 2013, includes the Nuna-1 exploration well that was drilled during 2012 to test the Torok formation and a second appraisal well that was drilled and logged during the first quarter of 2013. The Company flow-tested the Nuna-1 well during the second quarter of 2012 and again in the first quarter of 2013. The second appraisal well encountered a mechanical problem and could not be flow-tested before the end of the winter drilling season. The results of the flow tests on the Nuna-1 well and the log data from the second Nuna well are both very encouraging. The Company is currently conducting a front-end engineering design ("FEED") study to evaluate the potential for onshore production facilities to support the project.

See Note O for information regarding the Company's October 2013 agreement to sell its Alaskan subsidiary.

NOTE G. Long-term Debt

The Company's long-term debt consists of senior notes and revolving credit facilities, including the effects of net deferred fair value hedge losses and issuance discounts. As of September 30, 2013, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Corporate credit facility. The Company maintains a corporate credit facility (the "Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $1.5 billion that expires in December 2017. As of September 30, 2013, the Company had no outstanding borrowings under the Credit Facility.

Pioneer Southwest credit facility. Pioneer Southwest maintains a Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $300 million that expires in March 2017. As of September 30, 2013, Pioneer Southwest had outstanding borrowings of $201.0 million under the Pioneer Southwest Credit Facility. Pioneer Southwest's borrowing capacity under the Pioneer Southwest Credit Facility is subject to a covenant requiring that Pioneer Southwest maintain a specified ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. The net present value covenant limits Pioneer Southwest's available borrowing capacity under the Pioneer Southwest Credit Facility to $68.6 million as of September 30, 2013.

Convertible senior notes. As of December 31, 2012, the Company had $479.9 million of 2.875% Convertible Senior Notes due 2038 ("Convertible Senior Notes") outstanding. During December 2012 and March 2013, the Company's stock price met the price threshold that caused the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. In addition, on April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479.1 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479.1 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock during the six months ended June 30, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $845 thousand in principal and interest to redeem all Convertible Senior Notes that remained outstanding.

NOTE H. Incentive Plans

Stock-based compensation

For the three and nine months ended September 30, 2013, the Company recorded $32.5 million and $85.3 million, respectively, of stock-based compensation expense for all plans, as compared to $22.8 million and $66.0 million, respectively, for the same periods of 2012. As of September 30, 2013, there was $178.1 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $56.6 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"). This compensation 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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

September 30, 2013 and December 31, 2012, accounts payable – due to affiliates includes $24.5 million and $18.8 million, respectively, of liabilities attributable to Liability Awards.

The following table summarizes the activity that occurred during the nine months ended September 30, 2013, for each type of share-based incentive award issued by Pioneer or Pioneer Southwest:



	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units		Stock Options		Pioneer Southwest LTIP Restricted Units		Pioneer Southwest LTIP Phantom Units
Outstanding as of December 31, 2012	1,512,762		405,916		91,370		467,486		7,496		102,644
Awards granted	433,311		250,641		94,917		—		—		32,242
Awards vested	(509,659	)	(197,769	)	—		—		(7,496	)	(35,118	)
Options exercised	—		—		—		(166,474	)	—		—
Awards forfeited	(65,950	)	(29,664	)	(10,842	)	(11,085	)	—		—
Outstanding as of September 30, 2013	1,370,464		429,124		175,445		289,927		—		99,768

Postretirement Benefit Obligations

As of September 30, 2013 and December 31, 2012, the Company had $8.3 million and $9.7 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years, and one funded plan for which the Company assumed sponsorship in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of September 30, 2013 or December 31, 2012. The Company's funding policy for the Premier Silica plan is to contribute amounts sufficient to meet legal funding requirements, plus any additional amounts that the Company may determine to be appropriate considering the funded status of the plan, tax deductibility, the cash flow generated by the Company and other factors. The Company continually reassesses the amount and timing of any discretionary contributions and may elect to make such contributions in future periods.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(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, 2013 and 2012:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Beginning asset retirement obligations	$	191,129		$	145,457		$	197,754		$	136,742
Liabilities assumed in acquisitions	—			—			—			8,515
New wells placed on production	1,234			1,251			3,682			3,662
Changes in estimates (a)	—			48			(5,597		)	1,651
Dispositions	—			(2,536		)	(4,310		)	(2,536		)
Liabilities settled	(4,721		)	(4,507		)	(10,218		)	(13,249		)
Accretion of discount	3,180			2,497			9,499			7,371
Accretion of discount from integrated services (b)	1			23			13			77
Ending asset retirement obligations	$	190,823		$	142,233		$	190,823		$	142,233

_____________________


(a)	The changes in estimates during the nine months ended September 30, 2013 are attributable to lengthening the economic lives of certain wells, which reduced the present values of the associated asset retirement obligations.


(b)	Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note K for more information about interest and other income.

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, 2013 and December 31, 2012, the current portions of the Company's asset retirement obligations were $13.4 million and $13.3 million, respectively.

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.

Lawsuits filed in state and federal courts in Texas relating to the Merger. On May 15, 2013, David Flecker, a purported unitholder of Pioneer Southwest, filed a class action petition on behalf of Pioneer Southwest's unitholders and a derivative suit on behalf of Pioneer Southwest against the Company, Pioneer USA, the General Partner and the directors of the General Partner, in the 134th Judicial District of Dallas County, Texas (the "Flecker Lawsuit"). A similar class action petition and derivative suit was filed against the same defendants on May 20, 2013, in the 160th Judicial District of Dallas County, Texas, by purported unitholder Vipul Patel (the "Patel Lawsuit"). On August 27, 2013, the plaintiff in the Flecker Lawsuit filed an amended petition. On September 3, 2013, the court consolidated the Patel Lawsuit into the Flecker Lawsuit (as consolidated, the "Texas State Court Lawsuit"), and the plaintiffs filed a consolidated derivative and class action petition on September 5, 2013.

The Texas State Court Lawsuit alleges, among other things, that the consideration offered by the Company in the Merger is unfair and inadequate and that, by pursuing a transaction that is the result of an allegedly conflicted and unfair process, the defendants have breached their duties under Pioneer Southwest's partnership agreement as well as the implied covenant of good faith and fair dealing, and are engaging in self-dealing. Specifically, the lawsuit alleges that the director defendants: (i) engaged in self-dealing, failed to act in good faith toward Pioneer Southwest, and breached their duties owed to Pioneer Southwest; (ii) failed to properly value Pioneer Southwest and its various assets and operations and ignored or failed to protect against the numerous conflicts of interest arising out of the proposed transaction; and (iii) breached the implied covenant of good faith and fair dealing by engaging

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

in a flawed merger process. The Texas State Court Lawsuit also alleges that the Company, Pioneer USA and the General Partner aided and abetted the director defendants in their purported breach of fiduciary duties.

Based on these allegations, the plaintiffs in the Texas State Court Lawsuit seek to enjoin the defendants from proceeding with or consummating the proposed transaction. To the extent that the Merger is implemented before relief is granted, the plaintiffs seek to have the Merger rescinded. The plaintiffs also seek money damages and attorneys' fees. The defendants have filed a motion to dismiss the Texas State Court Lawsuit based on improper forum.

On August 21, 2013, Allan H. Beverly, a purported unitholder, filed a class action complaint against Pioneer Southwest, the Company, Pioneer USA, MergerCo and the directors of the General Partner in the United States District Court for the Northern District of Texas (the "Beverly Lawsuit"). The Beverly Lawsuit alleges that the defendants breached their fiduciary duties by agreeing to the Merger by means of an unfair process and for an unfair price. Specifically, the lawsuit alleges that the director defendants: (i) failed to maximize the value of Pioneer Southwest to its public unitholders and took steps to avoid competitive bidding; (ii) failed to properly value Pioneer Southwest; and (iii) ignored or failed to protect against the numerous conflicts of interest arising out of the proposed transaction. The Beverly Lawsuit also alleges that the Company, Pioneer USA and MergerCo aided and abetted the director defendants in their purported breach of fiduciary duties.

On September 13, 2013, Douglas Shelton, another purported unitholder, filed a class action complaint against the same defendants in the Beverly Lawsuit (as well as the General Partner) in the same court as the Beverly Lawsuit (the "Shelton Lawsuit"). The Shelton Lawsuit makes similar allegations to the Beverly Lawsuit, and also alleges that Section 7.9 of Pioneer Southwest's partnership agreement fails to alter or eliminate the defendants' common law fiduciary duties owed to unitholders in the context of the Merger. Specifically, the lawsuit alleges: (i) that the Company, as controlling unitholder, failed to fulfill its fiduciary duties in connection with the Merger because it purportedly cannot establish that the proposed Merger is the result of a fair process that will return a fair price to the unaffiliated unitholders of Pioneer Southwest; (ii) that the director defendants breached their fiduciary duties by failing to exercise due care and diligence in connection with the proposed Merger because the proposed Merger is purportedly not the result of a fair process that will return a fair price to the unaffiliated unitholders; and (iii) that the non-director defendants aided and abetted the director defendants in their purported breach of fiduciary duties. The plaintiffs in the Beverly Lawsuit and the Shelton Lawsuit (together, the "Federal Lawsuits") seek the same remedies as the plaintiffs in the Texas State Court Lawsuit.

On September 26, 2013, representatives of the plaintiffs in the Texas State Court Lawsuit and the Federal Lawsuits and representatives of the defendants in such lawsuits entered into a memorandum of understanding ("the memorandum of understanding") to settle the claims and allegations made in such lawsuits. The memorandum of understanding provides the plaintiffs with a period of confirmatory discovery during which the plaintiffs can confirm the fairness and reasonableness of the settlement contemplated by the memorandum of understanding. The parties agreed to use their reasonable best efforts to agree upon, execute and present to the Dallas County, Texas District Court a stipulation of settlement, which will provide for, among other things, a certification, for settlement purposes only, of the applicable class of unitholders to which the settlement will apply. Furthermore, the stipulation of settlement will provide for a full and complete discharge, dismissal with prejudice, settlement and release of all claims, suits and causes of action by the plaintiffs (other than appraisal rights under the Merger Agreement) against the defendants and their representatives arising out of or relating to the allegations made in the Texas State Court Lawsuit and the Federal Lawsuits, the Merger or any deliberations, negotiations, disclosures, omissions, press releases, statements or misstatements in connection therewith, any fiduciary or other obligations in respect of the Merger or any alternative transaction or under Pioneer Southwest's partnership agreement, or any costs and expenses associated with settlement other than as provided in the stipulation. All proceedings relating to the allegations made in the Texas State Court Lawsuit other than with respect to the settlement have been stayed. As part of the consideration for the settlement, the Merger Agreement was amended to provide for contractual appraisal rights for the unitholders. The parties to the memorandum of understanding have agreed to use their reasonable best efforts to obtain the agreement of any plaintiffs filing similar lawsuits to the Texas State Court Lawsuit or the Federal Lawsuits (whether filed in any state or federal court) to become party to the memorandum of understanding and the related settlement, and it is a condition to the consummation of the final settlement that any such plaintiffs join the settlement or such similar lawsuits otherwise be dismissed with prejudice prior to the final approval of the settlement. On October 15, 2013, the plaintiffs in the Beverly Lawsuit voluntarily dismissed all claims in the lawsuit in accordance with the memorandum of understanding. On October 16, 2013, the plaintiffs in the Shelton Lawsuit likewise voluntarily dismissed all claims in the lawsuit in accordance with the memorandum of understanding. There can be no assurance that a final settlement will be consummated.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

Lawsuit filed in the Delaware Court of Chancery relating to the Merger. On September 23, 2013, Patrick Wilson, another purported unitholder, filed a class action petition on behalf of the unitholders against Pioneer USA, MergerCo, Pioneer Southwest, the General Partner and the directors of the General Partner in the Court of Chancery of the State of Delaware (the "Wilson Lawsuit"). The Wilson Lawsuit alleges that the director defendants breached their purported fiduciary obligations to the unitholders by engaging in a process that undervalued Pioneer Southwest and which allegedly constitutes gross negligence, recklessness, willful misconduct, bad faith or knowing violations of law. Additionally, the Wilson Lawsuit alleges that the non-director defendants aided and abetted the purported breaches of fiduciary duties of the director defendants. The Wilson Lawsuit seeks the same remedies as the plaintiffs in the Texas State Court Lawsuit and the Federal Lawsuits. As of the date of this Report, the plaintiffs in the Wilson Lawsuit have not joined the memorandum of understanding.

The Company cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this Report, nor can the Company predict the amount of time and expense that will be required to resolve these lawsuits. See Note C for a description of the Merger Agreement.

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, 2013 and 2012:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013			2012
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	12,864	$	3,979	$	38,633		$	15,825
Equity interest in income of unconsolidated affiliate (b)	3,941		1,151		10,024			2,696
Other income	1,554		1,373		5,119			3,608
Deferred compensation plan income	381		204		2,363			1,727
Interest income	81		84		256			1,400
Income (loss) from vertical integration services (c)	2,266		3,465		(14,834		)	6,194
Total interest and other income	$	21,087	$	10,256	$	41,561		$	31,450

____________________


(a)	The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.


(b)	The Company, along with its joint venture partner, formed EFS Midstream LLC ("EFS Midstream") in 2010 to operate gathering facilities in the Eagle Ford Shale area. The Company accounts for its investment in EFS Midstream using the equity method. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term.

(c)

Income (loss) from vertical integration services represent net margins that result from Company-provided fracture stimulation, drilling 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, 2013, these net margins include $103.1 million and $206.3 million of gross vertical integration revenues, respectively, and $100.8 million and $221.1 million of total vertical integration costs and expenses, respectively. For the same periods in 2012, these net margins include $61.9 million and $223.6 million of gross vertical integration revenues, respectively, and $58.4 million and $217.4 million of total vertical integration costs and expenses, respectively.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

NOTE L. Other Expense

The following table provides the components of the Company's other expense for the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in thousands)
Transportation commitment charge (a)	$	13,482	$	9,694	$	31,228	$	27,374
Other	2,825		2,586		11,138		12,709
Above market and idle drilling and well services equipment rates (b)	1,293		12,808		9,744		23,553
Contingency and environmental accrual adjustments	4,701		70		6,782		772
Inventory impairment (c)	2,646		46		5,096		6,093
Terminated drilling rig contract charges (d)	—		6,807		1,019		15,768
Total other expense	$	24,947	$	32,011	$	65,007	$	86,269

____________________


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


(b)	Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.


(c)	Represents valuation charges on excess or damaged materials and supplies inventories.


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

NOTE M. Income Taxes

The Company's income tax benefits or provisions attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Current	$	8,341		$	8,275		$	(9,279	)	$	(7,051	)
Deferred	(66,574		)	(18,889		)	(300,312		)	(76,180		)
Income tax provision	$	(58,233	)	$	(10,614	)	$	(309,591	)	$	(83,231	)

For the three and nine months ended September 30, 2013, the Company's effective tax rate, excluding income attributable to the noncontrolling interest, was 39 percent and 37 percent, respectively, as compared to effective rates of (432) percent and 43 percent for the same respective periods in 2012. The Company's effective tax rates differ from the U.S. statutory rate of 35 percent primarily due to state income tax apportionments and nondeductible expenses.

At September 30, 2013, the Company had unrecognized tax benefits of $21.2 million resulting from net operating loss carryovers and alternative minimum tax credits obtained from the acquisition of Premier Silica. The unrecognized tax benefit is recorded as a reduction of the associated deferred tax asset and, if recognized, would affect the annual effective tax rate. The Company expects to resolve uncertainties regarding the unrecognized tax benefit within twelve months of September 30, 2013. There were no unrecognized tax benefits as of December 31, 2012.

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 2011 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 2008. As of September 30, 2013, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(Unaudited)

NOTE N. Net Income Per Share

The Company uses the two-class method of calculating net income per share because certain of the Company's and its consolidated subsidiaries' unvested share-based awards qualify as participating securities. Participating securities participate in the Company's dividend or partnership distributions and are assumed to participate in the Company's undistributed income proportionate to their share of the weighted average outstanding common shares, but are not assumed to participate in the Company's net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company's calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net income attributable to common stockholders.

During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share from continuing operations; therefore, conversion into common stock is assumed not to occur.

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30, 2013								Nine Months Ended September 30, 2013
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	91,125		$	—	$	91,125		$	529,516		$	(465	)	$	529,051
Participating basic earnings	(1,239		)	—		(1,239		)	(6,729		)	—			(6,729		)
Basic net income (loss) attributable to common stockholders	89,886			—		89,886			522,787			(465		)	522,322
Reallocation of participating earnings	3			—		3			102			—			102
Diluted income (loss) attributable to common stockholders	$	89,889		$	—	$	89,889		$	522,889		$	(465	)	$	522,424



	Three Months Ended September 30, 2012									Nine Months Ended September 30, 2012
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	(13,071	)	$	32,295		$	19,224		$	108,444		$	55,007		$	163,451
Participating basic earnings	—			(357		)	(357		)	(1,658		)	(841		)	(2,499		)
Basic net income (loss) attributable to common stockholders	(13,071		)	31,938			18,867			106,786			54,166			160,952
Reallocation of participating earnings	—			—			—			89			45			134
Diluted income (loss) attributable to common stockholders	$	(13,071	)	$	31,938		$	18,867		$	106,875		$	54,211		$	161,086

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(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, 2013 and 2012:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
	(in thousands)
Weighted average common shares outstanding:
Basic	138,586	123,111	135,057	122,874
Dilutive common stock options (a)	128	—	141	196
Convertible Senior Notes dilution (a)	—	—	1,453	2,866
Contingently issuable performance unit shares (a)	232	—	184	175
Diluted	138,946	123,111	136,835	126,111

____________________

(a)

The following common share equivalents were excluded from the weighted average diluted shares for the three months ended September 30, 2012 because they would have been anti-dilutive to the loss recorded for the period: 179,449 outstanding options to purchase the Company's common stock, 184,545 common shares attributable to unvested performance units and 3,311,845 common shares issuable if holders of the Company's 2.875% Convertible Senior Notes had exercised their conversion rights (see Note G). Options to purchase 185,722 shares of the Company's common stock were excluded from the diluted income per share calculations for the nine months ended September 30, 2012 because they would have been anti-dilutive to the calculation. For the nine months ended September 30, 2013, options to purchase 34,842 shares of the Company's common stock were excluded from the diluted income per share calculation because they would have been anti-dilutive to the calculation.

NOTE O. Subsequent Events

Distribution declaration. In October 2013, Pioneer Southwest declared a cash distribution of $0.52 per common unit for the period from July 1 to September 30, 2013. The distribution is payable on November 12, 2013 to unitholders of record at the close of business on November 4, 2013. Associated therewith, Pioneer Southwest expects to pay $18.6 million of aggregate distributions.

Merger Agreement. On October 25, 2013, the Company entered into an amendment to the Agreement and Plan of Merger with Pioneer USA, MergerCo, Pioneer Southwest and the General Partner dated August 9, 2013. Pursuant to the Merger Agreement, MergerCo will merge with and into Pioneer Southwest, with Pioneer Southwest surviving the Merger, such that following the Merger, the General Partner will remain a wholly-owned subsidiary of Pioneer and the sole general partner of Pioneer Southwest, and Pioneer USA will be the sole limited partner of Pioneer Southwest. Except for the common units owned by the Company, all of the common units outstanding as of the closing of the Merger will be cancelled and, except for the dissenting units, converted into the right to receive 0.2325 of a share of common stock of the Company per common unit. The closing of the Merger is subject to the satisfaction of certain closing conditions. See Note C for a description of the Merger Agreement.

Divestiture. In October 2013, the Company announced that it entered into a purchase and sale agreement with an unaffiliated third party to sell 100 percent of the equity in Pioneer's Alaska subsidiary, representing all of the Company's net assets in Alaska ("Pioneer Alaska"), for cash proceeds of $550.0 million, before normal closing adjustments. Closing of the transaction is expected to occur during the fourth quarter of 2013 or the first quarter of 2014 and is subject to certain conditions, including governmental approvals, buyer's arrangement of financing and other customary closing conditions. Associated with the sale of Pioneer Alaska, the Company expects to record a pretax noncash loss of approximately $350 million during the three months ended December 31, 2013. The financial and operating results of Pioneer Alaska's activities are expected to be reflected as discontinued operations for the quarter ending December 31, 2013 and for all prior periods that will be presented in the Company's annual report on Form 10-K for the year ended December 31, 2013. No impairment of Pioneer Alaska's net assets was recorded as of September 30, 2013 due to (i) the probability-weighted undiscounted cash flows of Pioneer Alaska net assets exceeding their carrying value at September 30, 2013 and (ii) the uncertainty regarding the willingness of third parties to purchase Pioneer Alaska on terms and at a price acceptable to the Company, which precluded held for sale criteria as of September 30, 2013. No assurance can be given that the closing conditions will be satisfied or that the sale will occur in accordance with the terms described above.

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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 2013 included the following highlights:

•

Net income attributable to common stockholders for the third quarter of 2013 was $91.1 million ($0.65 per diluted share), as compared to net income of $19.2 million ($0.15 per diluted share) for the third quarter of 2012. The increase in net income attributable to common stockholders is comprised of a $109.1 million increase in income from continuing operations, partially offset by a $4.9 million increase in net income attributable to noncontrolling interests and a $32.3 million decline in income from discontinued operations, net of tax, as a result of completing the sale of Pioneer South Africa during the third quarter of 2012. The primary components of the increase in net income from continuing operations include:


▪	a $192.4 million increase in oil and gas revenues as a result of an eight percent increase in total sales volumes and an 18 percent increase in the average commodity prices received per BOE; and


▪	a $21.5 million decrease in net derivative losses, primarily as a result of changes in forward commodity prices and changes in the Company's portfolio of derivatives;


▪	a $9.3 million decrease in interest expense, primarily due to a decline in outstanding borrowings; partially offset by


▪	a $48.9 million increase in DD&A expense, primarily due to increased sales volumes and an increase in the carrying value of proved oil and gas properties;


▪	a $47.6 million increase in the Company's income tax provision as a result of the Company's increased profitability; and

▪

an $11.2 million increase in general and administrative expense, primarily due to growth in employee headcount in support of the Company's capital expansion initiatives, performance-related compensation expense and higher stock-based compensation expense associated with Liability Awards as a result of increases in the market value of the Company's common stock (see Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about the Company's Liability Awards).


•	During the third quarter of 2013, average daily sales volumes from continuing operations increased by eight percent to 172,611 BOEPD, as compared to 159,894 BOEPD during the third quarter of 2012. The increase in third quarter 2013 average daily sales volumes, as compared to the third quarter of 2012, was primarily due to the Company's successful drilling program.


•	Average oil and gas prices increased during the third quarter of 2013 to $101.83 per BBL and $3.32 per MCF, respectively, as compared to $89.88 per BBL and $2.62 per MCF, respectively, in the third quarter of 2012. Average NGL prices decreased during the third quarter of 2013 to $30.17 per BBL, as compared to $30.96 per BBL in the third quarter of 2012.

•

Average oil and gas production costs per BOE decreased to $11.41 for the third quarter of 2013, as compared to $12.23 for the third quarter of 2012, primarily due to a decline in lease operating expenses as a result of lower saltwater disposal, electricity and repairs and maintenance costs and lower net natural gas plant charges resulting from increased gathering and processing revenues from processing third-party gas in Company-owned facilities.


•	Net cash provided by operating activities increased to $668.4 million for the three months ended September 30, 2013, as compared to $432.1 million for the three months ended September 30, 2012. The $236.3 million increase in net cash provided by operating activities is primarily due to an increase in oil and gas sales, partially offset by a decrease in realized derivative gains.

•

As of September 30, 2013, the Company's net debt to book capitalization declined to 21 percent, as compared to 37 percent as of December 31, 2012, principally reflective of an increase in cash and cash equivalents of $514.7 million, a decrease in long-term debt of $870.0 million and net income of $558.8 million for the nine months ended September 30, 2013. The changes in the Company's cash and cash equivalents and long-term debt primarily resulted from the application of net cash proceeds from the February 2013 sale of 10.35 million shares of common stock and the May 2013 completion of the Wolfcamp joint venture with Sinochem. See Notes B and C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about the Company's common stock issuance and joint venture with Sinochem.

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PIONEER NATURAL RESOURCES COMPANY

Recent Developments

Pending Merger

On August 9, 2013, the Company entered into the Merger Agreement with Pioneer USA, MergerCo, Pioneer Southwest and the General Partner, which was amended on October 25, 2013.

Pursuant to the Merger Agreement, MergerCo will merge with and into Pioneer Southwest with Pioneer Southwest surviving the Merger, such that following the Merger, the General Partner will remain a wholly-owned subsidiary of the Company and the sole general partner of Pioneer Southwest, and the Company will be the sole limited partner of Pioneer Southwest. Except for the common units owned by the Company, all of the common units outstanding as of the closing of the Merger will be cancelled and, except for the dissenting units, converted into the right to receive 0.2325 of a share of common stock of the Company per common unit.

Pursuant to the terms and conditions of the Merger Agreement, dissenting units that are owned by dissenting unitholders will not be converted into the right to receive the merger consideration, but instead will be entitled to payment of the fair value of such dissenting units ("appraisal rights") pursuant to and in accordance with the provisions of the Merger Agreement, unless and until such dissenting unitholder shall have failed to perfect or shall have effectively withdrawn or lost their appraisal rights. If a dissenting unitholder fails to perfect or effectively withdraws or loses the appraisal rights, then, as of the occurrence of such event or the closing of the Merger, whichever occurs later, each of such dissenting unitholder's dissenting units will be converted into the right to receive 0.2325 of a share of common stock of the Company per common unit.

The Merger Agreement provides that regular quarterly distributions on Pioneer Southwest's common units, not to exceed $0.52 per common unit per quarter (which $0.52 per common unit is equivalent to the most recent distribution declared for the quarter ended September 30, 2013), are to continue until the closing of the Merger. Regular distributions for a quarter are declared late in the first month following such quarter, and no distribution will be paid for a quarter if the Merger closes prior to the normal record date for such distribution. No fractional shares of the Company's common stock will be issued in the Merger. In lieu of receiving any fractional share of common stock to which any holder of the Pioneer Southwest's common units would otherwise have been entitled, after aggregating all fractions of shares to which such holder would be entitled, any fractional share will be rounded up to a whole share of common stock of the Company. The closing of the Merger is subject to certain closing conditions, including the approval of the Merger Agreement and the transactions contemplated thereby by the affirmative vote of holders of a majority of the outstanding common units entitled to vote at a special meeting of the unitholders of Pioneer Southwest. Pursuant to a voting agreement, the Company has agreed to cause the common units owned by it and its subsidiaries to be voted in favor of the Merger, which units represent 52.4 percent of Pioneer Southwest's outstanding common units and therefore constitute a sufficient number of common units to approve the Merger at the special meeting of the unitholders of Pioneer Southwest. The parties anticipate that the Merger will close in the fourth quarter of 2013, pending the satisfaction of certain conditions thereto.

The consolidation of the properties of the Company and Pioneer Southwest in the Midland Basin in West Texas through this proposed transaction would facilitate the Company's plans to fully and optimally develop the area utilizing horizontal drilling and would provide organizational, operational and administrative efficiencies. The Company owns 100 percent of the General Partner and owns approximately 52.4 percent of the 35,713,700 outstanding common units of Pioneer Southwest. See Notes B, C and J of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about Pioneer Southwest and for descriptions of litigation contingencies associated with the Merger Agreement and "Part II, Item 1A. Risk Factors" for additional information about potential risks associated with the Merger.

Divestiture

During October 2013, the Company announced that it has entered into a purchase and sale agreement with an unaffiliated third party to sell Pioneer Alaska for cash proceeds of $550.0 million, before normal closing adjustments. Closing of the transaction is expected to occur during the fourth quarter of 2013 or the first quarter of 2014 and is subject to certain conditions, including governmental approvals, buyer's arrangement of financing and other customary closing conditions. Associated with the sale of Pioneer Alaska, the Company expects to record a pretax noncash loss of approximately $350 million during the three months ended December 31, 2013. The financial and operating results of Pioneer Alaska's activities are expected to be reflected as discontinued operations for the quarter ending December 31, 2013 and for all prior periods that will be presented in the Company's annual report on Form 10-K for the year ended December 31, 2013. See Note O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about the sale of Pioneer Alaska. No assurance can be given that the closing conditions will be satisfied or that the sale will occur in accordance with the terms described above.

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Fourth Quarter 2013 Outlook

Based on current estimates (excluding Pioneer Alaska, which is expected to be reflected as discontinued operations), the Company expects the following operating and financial results for the quarter ending December 31, 2013:

Production is forecasted to average 179,000 to 184,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $14.00 to $16.00 per BOE based on current NYMEX strip commodity prices. DD&A expense is expected to average $15.50 to $17.50 per BOE.

Total exploration and abandonment expense is expected to be $25 million to $35 million. General and administrative expense is expected to be $70 million to $75 million. Interest expense is expected to be $44 million to $49 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.

Noncontrolling interest in consolidated subsidiaries' net income, excluding noncash mark-to-market adjustments, is expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company's effective income tax rate, excluding the effect of net income attributable to noncontrolling interest, 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 $10 million to $15 million and are primarily attributable to federal alternative minimum tax and state taxes.

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, 2013:



	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	52,456	14,728	71,435	79,090
South Texas - Eagle Ford Shale	13,001	10,141	81,136	36,665
Raton Basin	—	—	136,112	22,685
Mid-Continent	3,061	6,873	40,551	16,693
Barnett Shale	1,452	3,193	23,196	8,511
South Texas - Edwards and Austin Chalk	128	1	31,442	5,370
Alaska	4,217	—	—	4,217
Other	4	2	65	16
	74,319	34,938	383,937	173,247

During 2013 and 2012, the Company has focused its capital budgets and expenditures on oil and liquids-rich gas drilling activities due to low gas prices. As a result of these capital activities, the Company's total liquids production from continuing operations increased to 63 percent of total production, on a BOE basis, for the nine months ended September 30, 2013, as compared to 59 percent for the same period last year. Despite the increase in liquids production, the Company's liquids revenue, as a percent of total commodity sales, decreased to 86 percent for the nine months ended September 30, 2013, as compared to 88 percent for the same period last year, due to a 43 percent and one percent increase in the average gas and oil prices, respectively, and a decline of 15 percent in NGL prices, as compared to the nine months ended September 30, 2012.

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The following table summarizes by geographic area the Company's finding and development costs incurred during the nine months ended September 30, 2013:



	Acquisition Costs						Exploration		Development		Asset Retirement
	Proved			Unproved			Costs		Costs		Obligations			Total
	(in thousands)
Permian Basin	$	883		$	43,874		$	508,528	$	788,872	$	1,932		$	1,344,089
South Texas - Eagle Ford Shale	35			1,264			286,515		131,137		1,076			420,027
Raton Basin	—			—			4,372		2,898		—			7,270
Mid-Continent	—			188			2,008		12,100		49			14,345
Barnett Shale	6,170			5,946			100,970		37,882		446			151,414
South Texas - Edwards and Austin Chalk	(32		)	(16		)	3,134		3,224		—			6,310
Alaska	—			—			68,070		114,393		(5,463		)	177,000
Other	11			1,170			19,869		1		44			21,095
	$	7,067		$	52,426		$	993,466	$	1,090,507	$	(1,916	)	$	2,141,550

The following table summarizes the Company's development and exploration/extension drilling activities for the nine months ended September 30, 2013:



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	136	226	302	2	58
South Texas - Eagle Ford Shale	11	27	26	—	12
Mid-Continent	—	11	11	—	—
Barnett Shale	—	3	3	—	—
Alaska	4	2	3	—	3
	151	269	345	2	73



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	17	94	71	—	40
South Texas - Eagle Ford Shale	21	75	59	—	37
South Texas - Edwards and Austin Chalk	—	1	1	—	—
Barnett Shale	9	36	29	6	10
Alaska	2	1	—	—	3
Other	—	5	—	—	5
	49	212	160	6	95

Permian Basin area. The Company drilled 375 wells in the Permian Basin area during the first nine months of 2013, of which 373 were successful.

The Company currently has 28 rigs operating in the Spraberry field, of which 15 are drilling vertical wells and 13 are drilling horizontal wells. During 2013, the Company expects to spud approximately 300 vertical wells and 134 horizontal wells, with the horizontal wells being drilled in three Wolfcamp Shale intervals and three Spraberry Shale intervals. Excluding the southern joint venture area, the Company expects to spend $1.2 billion of drilling capital in the Spraberry field during 2013.

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 2013, the Company expects to spud 34 horizontal wells in the northern portion of the play and 100 horizontal wells in the southern portion of the play.

During the fourth quarter of 2012, the Company initiated horizontal Wolfcamp Shale drilling activities to delineate the northern portion of its Spraberry acreage position. Wells drilled in the northern portion of the play are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths. During the third quarter and

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October of 2013, the Company placed on production its first three Wolfcamp D interval wells and its third Wolfcamp B interval well in its northern acreage with encouraging results. The Company is utilizing five horizontal rigs in its northern acreage and drilling is currently focused in Midland, Martin and Andrews counties, with three rigs drilling Wolfcamp Shale wells and two rigs drilling Jo Mill and Spraberry Shale wells. These wells are primarily being drilled on two-well pads to gain efficiencies; therefore, the wells will not be completed until after the second well on each pad is drilled and accordingly production from these wells is not expected until both wells are ready to produce.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval, including the Strawn and Atoka intervals. The 2013 drilling program reflects 90 percent of the vertical wells being deepened below the Wolfcamp interval. Based on results to-date, the Company estimates that 85 percent of its Spraberry acreage position is prospective for the Strawn interval and that 40 percent to 50 percent of its acreage position is prospective for the Atoka interval.

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 consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $621.2 million, including normal closing adjustments, resulting in a 2013 pretax gain of $179.7 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 horizontal Wolfcamp Shale play. Associated with the closing of the joint venture transaction, the Company conveyed a 40 percent interest in the producing horizontal Wolfcamp Shale wells in the joint venture area.

The Company and Sinochem agreed to a plan to drill 100 horizontal Wolfcamp Shale wells during 2013, 120 wells in 2014 and 165 wells in 2015, subject to adjustment during each year's annual budgeting process. Associated therewith, the Company expects capital expenditures of $425 million during 2013. The Company is currently running eight horizontal rigs in the southern joint venture area and is testing downspacing from 720-foot spacing between wells (116-acre spacing) to 480-foot spacing between wells (77-acre spacing). The initial test includes 12 wells that have been drilled on three-well pads.

Sinochem also elected to participate in certain vertical wells that were drilled in the joint interest area after the December 1, 2012 effective date and received its share of production and costs from the Wolfcamp and deeper horizons based on the reserve contribution from the Wolfcamp and deeper intervals relative to reserves from all completed intervals. Pioneer's and Sinochem's participation in vertical wells is based on each party's interest without any drilling carry applied. Pioneer retained 100 percent of its vertical production in the joint interest area for wells drilled before the December 1, 2012 effective date. Pioneer also retained its current working interests in all horizons shallower than the Wolfcamp horizon and continues as operator of the properties in the joint interest area.

The Company continues to benefit from its integrated services to control drilling and operating costs and support the execution of its drilling and production activities in the Spraberry field. The Company owns 15 vertical drilling rigs and is presently utilizing four Company-owned vertical fracture stimulation fleets totaling approximately 80,000 horsepower and three Company-owned horizontal fracture stimulation fleets totaling approximately 90,000 horsepower in the Spraberry field. To support its growing 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 the majority of the Company's brown sand requirements for proppant that is being used to fracture stimulate vertical and horizontal wells in the Spraberry and Wolfcamp Shale intervals.

Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2013 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2013 drilling program has been focused on liquids-rich drilling, with less than 10 percent of the wells designated to hold strategic dry gas acreage.

The Company completed 85 horizontal Eagle Ford Shale wells during the first nine months of 2013, all of which were successful, with average lateral lengths of approximately 5,100 feet and, on average, 15-stage fracture stimulations. Additionally, the Company recently completed its first successful Upper Eagle Ford Shale well and estimates that approximately 25 percent of the Company's acreage is prospective for this interval in the Eagle Ford Shale play. The Company plans to spend $575 million of drilling capital and utilize 10 drilling rigs in 2013 to drill approximately 130 Eagle Ford Shale wells. The Company has been using two Pioneer-owned fracture stimulation fleets during 2013 in the Eagle Ford Shale area.

The Company's drilling operations in the Eagle Ford Shale continue to focus on improving drilling efficiencies. The Company has 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 testing of downspacing to 300 feet between wells is underway in areas where the 500-foot spacing was successful. The number of wells drilled from pads, as opposed to single-well locations, is expected to increase from about 45 percent of the Eagle Ford Shale wells during 2012 to about 80 percent

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in 2013, reflecting that most of the Company's acreage is now held by production. Pad drilling saves the Company a significant amount of capital costs per well, as compared to single-well location drilling. Pad sizes generally range from two wells to six wells. None of the wells are completed until all of the wells on a pad are drilled. Therefore, the timing between when the first well on a pad is spud and when the pad is placed on production is dependent on how many wells are drilled from the pad.

The Company has been using lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. The Company is expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company fracture stimulated 66 wells with white sand proppant during the first three quarters of 2013, with significant capital savings per well. The Company is continuing to monitor the performance of these wells and expects that greater than 75 percent of its 2013 drilling program will use lower-cost white sand proppant.

Barnett Shale. The Company completed 38 Barnett Shale Combo wells during the first nine months of 2013, of which 32 were successful. The Company increased from one drilling rig to two drilling rigs late in the first quarter. During 2013, the Company expects to drill 55 wells, with capital expenditures of $185 million.

Alaska. The Company owns a 70 percent working interest in, and is the operator of, the Oooguruk development project. Since inception, the Company has drilled 20 production wells and ten injection wells to develop this project. During the first quarter of 2012, the Company drilled the Nuna-1 exploration well from an onshore location to evaluate the productivity of the Torok formation and the feasibility of future development expansion. The Company flow-tested the well during April 2012 until production could no longer be transported along the ice road being utilized. During the first quarter of 2013, the Company re-entered and performed a second flow test of the well at a facility-limited average rate of approximately 2,800 BOEPD. In addition, the Company drilled and logged a second appraisal well in the Torok formation to further evaluate its resource potential. The second appraisal well encountered a mechanical problem and could not be flow-tested before the end of the winter drilling season. The results of the flow tests on the Nuna-1 well and the log data from the second Nuna well are both encouraging. The Company is currently conducting a front-end engineering design ("FEED") study to evaluate the potential for onshore production facilities to support the project.

The Company completed three Oooguruk development wells during the nine months ended September 30, 2013, all of which were successful. The Company also successfully completed mechanically-diverted fracture stimulations of four wells from the Oooguruk island facilities during 2013. The remaining well is in the Torok interval. It encountered a mechanical problem requiring additional remediation. The well was repaired and recompleted during the third quarter of 2013 and is undergoing production testing. Based on the results of the production tests, the well may be fracture stimulated during the first quarter of 2014. The Company expects capital expenditures of $190 million in Alaska during 2013.

During October 2013, the Company announced that it has entered into a purchase and sale agreement with an unaffiliated third party to sell Pioneer Alaska for cash proceeds of $550.0 million, before normal closing adjustments. Closing of the transaction is expected to occur during the fourth quarter of 2013 or the first quarter of 2014 and is subject to certain conditions, including governmental approvals, buyer's arrangement of financing and other customary closing conditions. Associated with the sale of Pioneer Alaska, the Company expects to record a pretax noncash loss of approximately $350 million during the three months ended December 31, 2013. The financial and operating results of Pioneer Alaska's activities are expected to be reflected as discontinued operations for the quarter ending December 31, 2013 and for all prior periods that will be presented in the Company's annual report on Form 10-K for the year ended December 31, 2013. No assurance can be given that the closing conditions will be satisfied or that the sale will occur in accordance with the terms described above.

See Note F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's exploration projects in Alaska.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $908.8 million and $2.5 billion for the three and nine months ended September 30, 2013, respectively, as compared to $716.3 million and $2.1 billion for the same respective periods in 2012.

The increase in oil and gas revenues during the three months ended September 30, 2013, as compared to the same period in 2012, is reflective of 15 percent and 14 percent increases in daily oil and NGL sales volumes, respectively, and 13 percent and 27 percent increases in average oil and gas prices, respectively. Partially offsetting the effects of these increases was a decline of two percent in gas sales volumes and a three percent decrease in average NGL prices. The increase in oil and gas revenues during the nine months ended September 30, 2013, as compared to the same period in 2012, is reflective of 22 percent, 20 percent and three percent increases in daily oil, NGL and gas sales volumes, respectively, and one percent and 43 percent increases in average oil and gas prices, respectively. Partially offsetting the effects of these increases was a decline of 15 percent in average NGL prices.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides average daily sales volumes for the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2013	2012	2013	2012
Oil (BBLs)	73,944	64,342	74,319	61,159
NGLs (BBLs)	37,363	32,824	34,938	29,103
Gas (MCF)	367,823	376,364	383,937	372,846
Total (BOE)	172,611	159,894	173,247	152,403

Average daily BOE sales volumes increased by eight percent and 14 percent for the three and nine months ended September 30, 2013, as compared to the same respective periods in 2012, principally due to the Company's successful drilling programs.

Production for the nine months ended September 30, 2013 was negatively impacted by gas processing capacity limitations in the Spraberry field as a result of wet gas production for the Company and other industry participants growing faster than anticipated. New Spraberry field gas processing facilities were completed and began processing gas in mid-April 2013, which eliminated the Spraberry gas processing capacity limitations. Sales volumes for the three and nine months ended September 30, 2013 were also negatively impacted by ethane rejection as a result of low ethane prices, which made it economically preferable to leave the ethane in gas sales. The gas processing capacity limitations and ethane rejection resulted in reduced recoveries of ethane, negatively impacting sales volumes by approximately 1,000 BOEPD and 1,700 BOEPD for the three and nine months ended September 30, 2013, respectively.

The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities. The following table provides the Company's average prices for the three and nine months ended September 30, 2013 and 2012:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012 (a)		2013		2012 (a)
Oil (per BBL)	$	101.83	$	89.88	$	93.77	$	92.84
NGL (per BBL)	$	30.17	$	30.96	$	29.58	$	34.88
Gas (per MCF)	$	3.32	$	2.62	$	3.41	$	2.38
Total (per BOE)	$	57.23	$	48.70	$	53.74	$	49.74

____________________

(a)

For the three and nine months ended September 30, 2012, the Company's average realized oil prices per BBL were $88.09 and $91.15, respectively, and the average realized total prices per BOE for the three and nine months ended September 30, 2012 were $47.98 and $49.06, respectively. The average realized prices do not include the impact of transfers of the Company's deferred hedge losses, net from Accumulated Other Comprehensive Income from hedging activities ("AOCI-Hedging") and the amortization of deferred volumetric production payment ("VPP") revenue. During the six months ended June 30, 2012, the Company transferred $3.2 million of deferred oil hedge gains from AOCI-Hedging to oil revenue, representing all remaining AOCI-Hedging transfers to earnings. Amortization of deferred VPP revenue increased oil revenues by $10.6 million and $31.5 million during the three and nine months ended September 30, 2012. As of December 31, 2012, all VPP production volumes had been delivered and there were no further obligations under VPP contracts.

Interest and other income. Interest and other income for the three and nine months ended September 30, 2013 was $21.1 million and $41.6 million, as compared to $10.3 million and $31.5 million for the same respective periods in 2012. The $10.8 million increase in interest and other income during the three months ended September 30, 2013, as compared to the same period in 2012, was primarily due to an $8.9 million increase in Alaskan PPT credit recoveries and a $2.8 million increase in equity in earnings of EFS Midstream. The $10.1 million increase in interest and other income during the nine months ended September 30, 2013, as compared to the same period in 2012, was primarily due to a $22.8 million increase in Alaskan PPT credit recoveries and a $7.3 million increase in equity in earnings of EFS Midstream, partially offset by a $21.0 million decrease in earnings from third-party vertical integration services, primarily due to under-utilized services capacity. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding interest and other income.

Derivative gains (losses), net. The primary purposes for which the Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts are to (i) reduce the effect of price volatility on the commodities the Company produces, sells and consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three months ended September 30, 2013, the Company recorded $102.5 million of net derivative losses on commodity price and interest rate derivatives, of which $136.6 million

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represented unrealized net losses. During the nine months ended September 30, 2013, the Company recorded $333 thousand of net derivative losses on commodity price and interest rate derivatives, of which $122.1 million represented unrealized net losses. During the three and nine months ended September 30, 2012, the Company recorded $124.0 million of net derivative losses and $243.6 million of net derivative gains, respectively. 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 losses on the disposition of assets of $487 thousand for the three months ended September 30, 2013, as compared to net gains on the disposition of assets of $12.8 million for the same period in 2012. For the nine months ended September 30, 2013, the Company recorded net gains on the disposition of assets of $214.9 million, as compared to $57.6 million, for the same period in 2012. The net gains for the nine months ended September 30, 2013 included (i) the May 2013 completion of the Company's 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 to Sinochem for net cash proceeds of $621.2 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of sale, resulting in a pretax gain of $179.7 million, (ii) the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38.1 million, which resulted in a pretax gain of $22.4 million, and (iii) the sale of the Company's interest in certain unproved oil and gas properties in the Barnett Shale for net cash proceeds of $11.6 million, which resulted in a pretax gain of $8.7 million.

The net gain for the three months ended September 30, 2012 is primarily associated with the sale of the Company's interest in the Cosmopolitan Unit in the Cook Inlet of Alaska to unaffiliated third parties for cash proceeds of $10.1 million, which, together with certain Company obligations assumed by the purchasers, resulted in a pretax gain of $12.6 million. The net gain for the nine months ended September 30, 2012 also includes the first quarter 2012 sale of a portion of the Company's interest in an unproved oil and gas property in the Eagle Ford Shale field for net cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 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 $181.3 million and $530.0 million, respectively, during the three and nine months ended September 30, 2013 as compared to $179.7 million and $461.5 million, respectively, during the same respective periods in 2012. Lease operating expenses and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from the gathering and processing of third-party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the three and nine months ended September 30, 2013 decreased by seven percent and increased by two percent, respectively, as compared to the same respective periods in 2012. The decrease in production costs per BOE during the three months ended September 30, 2013, as compared to the same period in 2012, is primarily reflective of (i) a $1.02 per BOE decrease in lease operating expenses primarily due to lower per BOE saltwater disposal, electricity and repair and maintenance costs and (ii) a $0.74 per BOE decrease in net natural gas plant charges resulting from increased gathering and processing revenues from processing third-party gas in Company-owned facilities. Partially offsetting the aforementioned declines in per BOE production costs was (i) a $0.70 per BOE increase in third-party transportation costs, primarily associated with increasing Eagle Ford Shale sales volumes and (ii) a $0.24 per BOE increase in workover costs, primarily associated with the Company's Oooguruk project in Alaska. The increase in production costs per BOE during the nine months ended September 30, 2013, as compared to the same period in 2012, is primarily reflective of (i) a $0.47 per BOE increase in third-party transportation charges due to a higher proportion of the Company' production coming from the Eagle Ford Shale area that is subject to transportation charges, (ii) a $0.45 per BOE decrease in net natural gas plant charges resulting from increased gathering and processing revenues from processing third-party gas in Company-owned facilities and (iii) a $0.25 per BOE increase in workover expenses, primarily related to workover activities in Alaska.

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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, 2013 and 2012:



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013		2012
Lease operating expenses	$	8.59		$	9.61	$	8.38	$	8.48
Third-party transportation charges	1.98			1.28		1.74		1.27
Net natural gas plant charges	(0.15		)	0.59		0.04		0.49
Workover costs	0.99			0.75		1.05		0.80
Total production costs	$	11.41		$	12.23	$	11.21	$	11.04

Production and ad valorem taxes. The Company's production and ad valorem taxes were $53.9 million and $162.1 million during the three and nine months ended September 30, 2013, respectively, as compared to $49.8 million and $140.1 million, respectively, for the same respective periods in 2012. 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, 2013 and 2012:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Production taxes	2.09		2.03		$	2.07	$	2.05
Ad valorem taxes	$	1.31	$	1.35	1.36		1.30
Total production and ad valorem taxes	$	3.40	$	3.38	$	3.43	$	3.35

Depletion, depreciation and amortization expense. The Company's DD&A expense was $256.3 million ($16.14 per BOE) and $736.6 million ($15.57 per BOE) for the three and nine months ended September 30, 2013, respectively, as compared to $207.4 million ($14.10 per BOE) and $589.7 million ($14.12 per BOE), respectively, during the same respective periods in 2012. The increase in per BOE DD&A expense during the three and nine months ended September 30, 2013, as compared to the same respective periods in 2012, is primarily due to increases in depletion expense on oil and gas properties.

Depletion expense on oil and gas properties was $15.44 and $14.89 per BOE during the three and nine months ended September 30, 2013, respectively, as compared to $13.48 and $13.51 per BOE during the same respective periods in 2012. The 15 percent and 10 percent increases in per BOE depletion expense during the three and nine months ended September 30, 2013, respectively, as compared to the same respective periods in 2012, are primarily due to capital expenditures to develop proved undeveloped locations, primarily in the Spraberry and Eagle Ford Shale fields, partially offset by the impairment effects of reducing the carrying value of proved properties in the Barnett Shale field during 2012.

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.

Management's Price Outlooks represent longer-term outlooks that are developed based on observable third-party futures price outlooks as of a measurement date. During the second quarter of 2012, declines in Management's Price Outlooks provided indications of possible impairment of the Company's dry gas properties in the Barnett Shale field in North Texas. As a result of management's assessments during the second quarter of 2012, the Company recognized a pretax noncash impairment charge of $444.9 million to reduce the carrying value of the Barnett Shale field.

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

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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, 2013 and 2012 (in thousands):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013		2012
Geological and geophysical	$	23,517		$	14,128	$	62,671	$	64,554
Exploratory dry holes	(433		)	1,564		9,610		29,851
Leasehold abandonments and other	8,425			11,347		10,828		23,099
	$	31,509		$	27,039	$	83,109	$	117,504

The Company's geological and geophysical costs increased by $9.4 million during the three months ended September 30, 2013, as compared to the same period in 2012, primarily due to increased seismic and seismic interpretation expenditures supportive of drilling activities in the Spraberry field. During the nine months ended September 30, 2013, the Company's exploratory dry holes decreased by $20.2 million as compared to the same period in 2012, primarily due to a dry hole provision of $20.2 million related to an unsuccessful exploration well in Alaska that was drilled during the first quarter of 2012. The Company's unproved acreage abandonments for the three and nine months ended September 30, 2013 decreased by $2.9 million and $12.3 million, respectively, as compared to the same respective periods in 2012, due to decreased acreage abandonments associated with the Raton area, the South Texas Austin Chalk field and the Spraberry field.

During the nine months ended September 30, 2013, the Company drilled and evaluated 166 exploration/extension wells, 160 of which were successfully completed as discoveries. During the same period in 2012, the Company drilled and evaluated 163 exploration/extension wells, 157 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and nine months ended September 30, 2013 was $73.7 million and $204.1 million, respectively, as compared to $62.6 million and $180.6 million, respectively, for the same respective periods in 2012. The increase in general and administrative expense for the three and nine months ended September 30, 2013, as compared to the respective periods in 2012, is primarily due to increases of $5.0 million and $20.5 million, respectively, in compensation and occupancy expenses related to staffing increases in support of the Company's capital expansion initiatives and increases of $5.5 million and $10.2 million, respectively, in stock-based compensation expense, primarily attributable to mark-to-market adjustments on the Company's restricted stock Liability Awards, which are valued based on the period-end closing stock price of the Company.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $3.2 million and $9.5 million for the three and nine months ended September 30, 2013, respectively, as compared to $2.5 million and $7.4 million during the same respective periods in 2012. 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 $45.1 million and $138.7 million for the three and nine months ended September 30, 2013, respectively, as compared to $54.4 million and $150.3 million, respectively, during the same respective periods in 2012. The weighted average interest rates on the Company's indebtedness for the three and nine months ended September 30, 2013, including the effects of capitalized interest, were 6.7 percent and 6.2 percent, respectively, as compared to 6.3 percent and 6.6 percent, respectively, for the same respective periods in 2012. The $9.3 million decrease in interest expense during the three months ended September 30, 2013, as compared to the same period of 2012, was primarily due to a decrease in debt, related to repayment of amounts outstanding under the Credit Facility and conversions of Convertible Senior Notes and a decrease of $4.5 million in noncash amortization of financing fees and debt issuance discounts. The $11.6 million decrease in interest expense during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012, was primarily due to a decrease in debt as a result of the repayment of amounts outstanding under the Credit Facility and conversions of Convertible Senior Notes, and a decrease of $13.8 million in noncash amortization of financing fees, debt issuance discounts and deferred hedge losses, partially offset by an increase in cash interest expense paid on senior notes of $2.2 million. See Note G of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding conversions of the Company's Convertible Senior Notes during 2013.

Other expense. Other expense for the three and nine months ended September 30, 2013 was $24.9 million and $65.0 million, respectively, as compared to $32.0 million and $86.3 million, respectively, for the same respective periods in 2012. The decrease in other expense for the three months ended September 30, 2013, as compared to the same period in 2012, is primarily attributable to an $11.5 million decrease in above market and idle rig and fracture stimulation equipment charges, which are not chargeable to joint operations, and a $6.8 million decrease due to rig contract termination fees in 2012, partially offset by increases in

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transportation commitment expenses, inventory valuation allowances and legal and environmental contingencies of $3.8 million, $2.6 million and $4.6 million, respectively.

The decrease in other expense for the nine months ended September 30, 2013, as compared to the same period in 2012, is primarily attributable to a $14.7 million decrease in rig contract termination fees and a $13.8 million decrease in above market and idle rig and fracture stimulation equipment charges, which are not chargeable to joint operations, partially offset by increases in legal and environmental contingencies and transportation commitment expenses of $6.0 million and $3.9 million, respectively. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision. The Company recorded an income tax provision from continuing operations of $58.2 million and $309.6 million for the three and nine months ended September 30, 2013, respectively, as compared to income tax provisions of $10.6 million and $83.2 million, respectively, for the same respective periods in 2012. The Company's effective tax rates, excluding net income attributable to noncontrolling interests, for the three and nine months ended September 30, 2013 were 39 percent and 37 percent, respectively. 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 nil and a loss of $465 thousand from discontinued operations, net of tax, for the three and nine months ended September 30, 2013, respectively, as compared to income from discontinued operations, net of tax, of $32.3 million and $55.0 million, respectively, for the same respective periods in 2012. The decrease in earnings from discontinued operations is primarily the result of completing the sale of Pioneer South Africa during the third quarter of 2012. 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 the noncontrolling interests for the three and nine months ended September 30, 2013 was $7.4 million and $29.7 million, respectively, as compared to $2.5 million and $39.7 million, respectively, for the same respective periods in 2012. The $4.9 million increase in income attributable to noncontrolling interests for the three months ended September 30, 2013, as compared to the same respective period in 2012, is primarily due to increases in Pioneer Southwest's revenues, partially offset by higher production costs and higher depletion expense. The $10.0 million decrease in income attributable to noncontrolling interests for the nine months ended September 30, 2013, as compared to the same respective period in 2012, is primarily due to decreases in Pioneer Southwest's mark-to-market derivative gains, higher production costs and higher depletion expense, partially offset by increased revenues.

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/distributions 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 the sale of joint interests and nonstrategic assets or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2013 is focused on oil and liquids-rich gas drilling activities with total planned expenditures of $3.0 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), consisting of $2.75 billion for drilling operations, including budgeted land capital for existing assets, and $240 million for buildings and vertical integration additions. Based on results for the nine months ended September 30, 2013 and Management's Price Outlook, the Company expects its cash flows from operating activities, cash and cash equivalents on hand, proceeds from asset sales and/or joint ventures and availability under its Credit Facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2013.

Investing activities. Investing activities used $1.5 billion of cash during the nine months ended September 30, 2013, as compared to $2.5 billion of cash used in investing activities during the nine months ended September 30, 2012. The $1.0 billion decrease in cash used in investing activities for the nine months ending September 30, 2013, as compared to the nine months ended September 30, 2012, is primarily due to (i) a $592.7 million increase in proceeds from the disposition of assets, including $621.2 million of net cash proceeds from the May 2013 sale to Sinochem of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas, (ii) a $297.0 million decrease in payments for acquisitions due to the acquisition of Premier Silica during 2012, (iii) an $85.6 million decrease in additions to oil and gas properties, partially due to the drilling carry being paid by Sinochem in the southern portion of the horizontal Wolfcamp Shale play and (iv) a $78.9 million decrease in additions to other assets and other property and equipment. During the nine months ended September 30, 2013, the Company's expenditures for investing activities were funded by net cash provided by operating activities and a portion of the proceeds from the February issuance of 10.35 million shares of the Company's common stock.

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Dividends/distributions. During February and August of both 2013 and 2012, 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 (the "Pioneer Southwest Board") declared quarterly distributions of $0.52 per limited partner unit, compared to the quarterly distribution of $0.51, $0.52 and $0.52 per limited partner unit declared in January 2012, April 2012 and July 2012, respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $26.5 million and $26.3 million during the nine months ended September 30, 2013 and 2012, respectively. During October 2013, the Pioneer Southwest Board declared a quarterly distribution of $0.52 per limited partner unit for unitholders of record on November 4, 2013, payable November 12, 2013.

Pursuant to the Merger Agreement, regular quarterly distributions on the Pioneer Southwest's common units, not to exceed $0.52 per common unit per quarter, are to continue until the closing of the Merger. Regular distributions for a quarter are declared late in the first month following such quarter, and no distribution will be paid for a quarter if the Merger closes prior to the normal record date for such distribution. The parties anticipate that the Merger will close in the fourth quarter of 2013, pending the satisfaction of certain conditions thereto. See "Recent Developments" for additional information regarding the Merger.

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, 2013, 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. 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, 2012, the material changes in the Company's contractual obligations include a $878.9 million decrease in the principal balances of outstanding long-term debt and a $122.1 million decrease in the Company's derivative net 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, 2013, these contracts represented net assets of $186.6 million. The ultimate liquidation value of the Company's commodity and interest rate derivatives will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives' fair values as of September 30, 2013. 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 sales of joint interests and nonstrategic assets 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 joint interests or nonstrategic assets.

Operating activities. Net cash provided by operating activities during the nine months ended September 30, 2013 was $1.6 billion, as compared to $1.4 billion during the same period in 2012. The increase in net cash provided by operating activities for the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012, is primarily due to an increase in oil and gas sales, partially offset by a decrease in realized derivative gains.

Asset divestitures. 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 net cash proceeds of $621.2 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale. 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 horizontal Wolfcamp Shale play.

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During the nine months ended September 30, 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 $38.1 million of net cash proceeds, which resulted in a pretax gain of $22.4 million, and a sale of its interest in certain unproved oil and gas properties in the Barnett Shale for net cash proceeds of $11.6 million, which resulted in a pretax gain of $8.7 million.

During October 2013, the Company announced that it has entered into a purchase and sale agreement with an unaffiliated third party to sell Pioneer Alaska for cash proceeds of $550.0 million, before normal closing adjustments. Closing of the transaction is expected to occur during the fourth quarter of 2013 or the first quarter of 2014 and is subject to certain conditions, including governmental approvals, buyer's arrangement of financing and other customary conditions. Associated with the sale of Pioneer Alaska, the Company expects to record a pretax noncash loss of approximately $350 million during the three months ended December 31, 2013. The financial and operating results of Pioneer Alaska's activities are expected to be reflected as discontinued operations for the quarter ending December 31, 2013 and for all prior periods that will be presented in the Company's annual report on Form 10-K for the year ended December 31, 2013. No assurance can be given that the closing conditions will be satisfied or that the sale will occur in accordance with the terms described above.

Financing activities. Net cash provided by financing activities during the nine months ended September 30, 2013 was $372.4 million, as compared to net cash provided by financing activities of $955.0 million during the nine months ended 2012. The decrease in net cash provided from financing activities during the nine months ended September 30, 2013, as compared to the same period of 2012, was primarily the result of (i) an increase in net principal payments on long-term debt of $1.9 billion, partially offset by (ii) the Company's completion of an offering of 10.35 million shares of its common stock in February 2013 at a per-share price, after underwriting and offering expenses, of $123.76 for a total of $1.3 billion of realized net proceeds.

During December 2012 and March 2013, respectively, the Company's stock price met the price threshold that caused the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Holders of $479.1 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479.1 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $845 thousand in principal and interest to redeem all Convertible Senior Notes that remained outstanding.

As the Company pursues its strategy, it may utilize various financing sources, including, to the extent available, fixed and floating rate debt, convertible securities, preferred stock or common stock. 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, 2013, the Company had no outstanding borrowings under its Credit Facility and was in compliance with all of its debt covenants. The Company had cash on hand of $744.1 million and had $1.5 billion of unused borrowing capacity as of September 30, 2013. 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 joint interests or 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 on hand, proceeds from sales of joint interests or nonstrategic assets and available capacity under the Company's Credit Facility will be adequate to fund 2013 capital expenditures and dividend/distribution 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 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. The Company is rated as investment grade by three credit rating agencies.

Book capitalization and current ratio. The Company's net book capitalization at September 30, 2013 was $9.9 billion, consisting of $744.1 million of cash and cash equivalents, debt of $2.9 billion and equity of $7.8 billion. The Company's net debt

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to net book capitalization was 21 percent and 37 percent at September 30, 2013 and December 31, 2012, respectively. The change was primarily a result of the increase in cash and cash equivalents of $514.7 million, a decrease in long-term debt of $870.0 million and net income of $558.8 million for the first nine months of 2013. The Company's ratio of current assets to current liabilities increased to 1.26 to 1.00 at September 30, 2013, as compared to 1.02 to 1.00 at December 31, 2012, primarily due to the above noted increase in cash and cash equivalents. Increases in the Company's liquidity resulted from the February 2013 sale of 10.35 million shares of common stock and the May 2013 completion of the Wolfcamp joint venture with Sinochem.

New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data."

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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, 2012. 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, 2012.

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, 2013:



	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2012	$	318,377		$	(9,724	)	$	308,653
Changes in contract fair value	(16,926		)	16,593			(333		)
Contract maturities	(121,253		)	—			(121,253		)
Contract terminations	—			(482		)	(482		)
Fair value of contracts outstanding as of September 30, 2013	$	180,198		$	6,387		$	186,585

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 debt transactions.

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The following table provides information about financial instruments to which the Company was a party as of September 30, 2013 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, 2013. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on November 4, 2013.



	Three Months Ending December 31,			Year Ending December 31,																	Asset (Liability) Fair Value at September 30,
	2013			2014			2015			2016			2017			Thereafter			Total		2013
	(dollars in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	—		$	455,385		$	485,100		$	1,749,500		$	2,689,985	$	(3,054,104	)
Weighted average interest rate	6.15		%	6.15		%	6.15		%	6.17		%	6.11		%	6.28		%
Variable rate principal maturities:
Pioneer Southwest Credit Facility	$	—		$	—		$	—		$	—		$	201,000		$	—		$	201,000	$	(193,355	)
Weighted average interest rate	1.88		%	1.97		%	2.38		%	3.28		%	4.29		%
Interest Rate Swaps:
Notional debt amount	$	400,000		$	400,000		$	400,000		$	400,000		$	400,000		$	363,333				$	6,387
Fixed rate receivable (%)	3.95		%	3.95		%	3.95		%	3.95		%	3.95		%	3.95		%
Variable rate payable (%)	1.36		%	1.46		%	1.87		%	2.77		%	3.78		%	5.36		%

____________________


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

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, 2013. 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,
	2013			2014			2015			2016		2013 (a)
												(in thousands)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts	69,000			69,000			85,000			25,000		$	103,845
Weighted average ceiling price per BBL	$	120.55		$	114.05		$	98.98		$	93.30
Weighted average floor price per BBL	$	91.39		$	93.70		$	88.06		$	85.00
Weighted average short put price per BBL	$	74.22		$	77.61		$	73.06		$	70.00
Swap contracts	9,750			10,000			—			—		$	(10,694	)
Weighted average fixed price per BBL	$	95.57		$	93.87		$	—		$	—
Average forward NYMEX oil prices (b)	$	94.62		$	93.38		$	88.02		$	84.45
Rollfactor swap contracts (c)	11,000			19,000			—			—		$	(4,046	)
Weighted average fixed price per BBL	$	0.85		$	0.45		$	—		$	—
Average forward rollfactor prices (b)	$	(0.41	)	$	0.54		$	—		$	—
Cushing to LLS index swap contracts	3,000			—			—			—		$	1,542
Weighted average fixed price per BBL	$	8.53		$	—		$	—		$	—
Average forward basis differential prices (d)	$	3.04		$	—		$	—		$	—
NGL Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (e)	1,064			1,000			—			—		$	2,173
Weighted average ceiling price per BBL	$	105.28		$	109.50		$	—		$	—
Weighted average floor price per BBL	$	89.30		$	95.00		$	—		$	—
Weighted average short put price per BBL	$	75.20		$	80.00		$	—		$	—
Average forward NGL prices (f)	$	87.41		$	82.39		$	—		$	—
Collar contracts (g)	2,500			3,000			—			—		$	841
Weighted average ceiling price per BBL	$	12.68		$	13.72		$	—		$	—
Weighted average floor price per BBL	$	10.50		$	10.78		$	—		$	—
Average forward NGL prices (f)	$	9.99		$	10.21		$	—		$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts	—			115,000			285,000			20,000		$	30,301
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
Collar contracts	152,500			—			—			—		$	19,455
Weighted average ceiling price per MMBTU	$	6.22		$	—		$	—		$	—
Weighted average floor price per MMBTU	$	4.98		$	—		$	—		$	—
Swap contracts	165,870			175,000			20,000			—		$	34,952
Weighted average fixed price per MMBTU	$	5.10		$	4.02		$	4.31		$	—
Average forward NYMEX gas prices (b)	$	3.45		$	3.61		$	3.84		$	3.98
Basis swap contracts (h)	162,500			75,082			30,000			—		$	1,829
Weighted average fixed price per MMBTU	$	(0.22	)	$	(0.19	)	$	(0.18	)	$	—
Average forward basis differential prices (i)	$	(0.06	)	$	(0.23	)	$	(0.29	)	$	—

___________________

(a)

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

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PIONEER NATURAL RESOURCES COMPANY


(b)	The average forward NYMEX oil and gas prices are based on November 4, 2013 market quotes.


(c)	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.


(d)	The average forward basis differential prices are based on November 4, 2013 market quotes for basis differentials between Cushing WTI and Louisiana Light Sweet crude ("LLS").


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


(f)	Forward component NGL prices are derived from respective active-market NGL component price quotes as of November 4, 2013.


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


(h)	Subsequent to September 30, 2013, the Company entered into additional basis swap contracts for 10,000 MMBTU per day of the Company's 2014 production with a negative price differential of $0.26 per MMBTU between the relevant index price and the NYMEX price.


(i)	The average forward basis differential prices are based on November 4, 2013 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward 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, 2013 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 the legal proceedings that are described in Note J of the Notes to Consolidated Financial Statements included in "Item 1. Financial Statements." The Company is also party to other 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 other 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, 2012, 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," as updated by the discussions in Part II of the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, under the heading "Item 1A. Risk Factors," which risks could materially affect the Company's business, financial condition or future results. Except as set forth below and as set forth in the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, there has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

The Merger may not be consummated even if Pioneer Southwest's unitholders approve the Merger.

The Merger Agreement contains conditions, some of which are beyond the parties' control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Merger not occurring, even though Pioneer Southwest's unitholders may have voted to approve the Merger. The Company and Pioneer Southwest cannot predict with certainty whether and when any of the conditions to the completion of the Merger will be satisfied. Any delay in completing the Merger could cause the Company not to realize, or delay the realization of, some or all of the benefits that it expects to achieve from the Merger. In addition, the Company and the Pioneer Southwest can agree not to consummate the Merger even if Pioneer Southwest's unitholders approve the Merger and the conditions to the closing of the Merger are otherwise satisfied.

The exchange ratio in the Merger Agreement is fixed and will not be adjusted in the event of any change in either the price of the Company's common stock or the price of Pioneer Southwest's common units.

If the Merger is completed, each common unit of Pioneer Southwest outstanding as of the closing of the Merger (other than dissenting units and common units owned by the Company and its subsidiaries) will be converted into the right to receive 0.2325 of a share of the Company's common stock. This exchange ratio was fixed in the Merger Agreement and will not be adjusted for changes in the market price of either shares of the Company's common stock or Pioneer Southwest's common units. Changes in the price of shares of the Company's common stock prior to the closing date of the Merger will affect the market value of the Merger consideration that Pioneer Southwest unitholders will receive in the Merger.

The market price of shares of the Company's common stock has historically varied greatly, and is likely to continue to be volatile because of numerous factors, which may include:


•	changes in the Company's drilling results and reserve growth outlook;


•	domestic and worldwide supply of and demand for oil, NGL and gas;


•	developments in the Middle East, which could affect the global supply of oil and significantly affect oil prices;


•	quarterly fluctuations in the Company's operating results and those of its competitors;


•	changes in stock market analysts' estimates of the Company's future performance and the future performance of its competitors;


•	purchases and sales of a high volume of shares of the Company's common stock;


•	events affecting other companies that the market deems comparable to the Company;


•	general conditions in the oil and gas industry in which the Company operates;


•	general economic conditions in the United States and other countries;


•	federal, state and local legislation, governmental regulation and legal developments in the industry in which the Company operates; and


•	changes in market assessments of the likelihood that the Merger will be completed.

The price of a share of the Company's common stock as of the closing date of the Merger may vary from its price on the date the Merger Agreement was executed or on the date of the special meeting of Pioneer Southwest's unitholders. As a result, the market value represented by the exchange ratio will also vary.

PIONEER NATURAL RESOURCES COMPANY

If the Merger does not occur, the Company and Pioneer Southwest will not benefit from the expenses they have incurred in the pursuit of the Merger.

The Merger may not be completed. If the Merger is not completed, the Company and Pioneer Southwest will have incurred substantial expenses for which no ultimate benefit will have been received by either company. The parties have incurred and expect to continue to incur Merger-related expenses, including investment banking, engineering, legal and accounting fees, and financial printing and other related charges, much of which may be incurred even if the Merger is not completed. In addition, if the Merger Agreement is terminated under specified circumstances, either the Company or Pioneer Southwest will be required to pay certain expenses of the other party.

Lawsuits have been filed against the Company, Pioneer Southwest, the General Partner, and the directors and certain officers of the General Partner challenging the Merger, and any injunctive relief or adverse judgment for monetary damages could prevent the Merger from occurring or could have a material adverse effect on Pioneer following the Merger.

The Company, Pioneer Southwest, the General Partner and the directors and certain officers of the General Partner have been named as defendants in purported class action petitions and derivative suits brought by purported unitholders, generally alleging claims of breach of duties under Pioneer Southwest's partnership agreement, breach of the implied covenant of good faith and fair dealing in connection with the Merger, self-dealing and aiding and abetting arising out of the defendants' pursuit of the Merger by way of an allegedly conflicted and unfair process. The plaintiffs seek to enjoin the defendants from proceeding with or consummating the Merger and, to the extent that the Merger is implemented before relief is granted, plaintiffs seek to have the Merger rescinded. The plaintiffs also seek money damages and attorneys' fees. While a memorandum of understanding has been entered into with respect to the settlement of certain of these lawsuits, there can be no guarantee that a settlement will be successfully consummated. Furthermore, not all of these lawsuits are subject to the memorandum of understanding, and additional lawsuits similar to these lawsuits may be filed in the future. The favorable resolution of any such lawsuits cannot be assured.

One of the conditions to the completion of the Merger is that no order, decree or injunction of any court or agency of competent jurisdiction shall be in effect, and no law shall have been enacted or adopted, that enjoins, prohibits or makes illegal consummation of any of the transactions contemplated by the Merger Agreement. A preliminary injunction could delay or jeopardize the completion of the Merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the Merger. An adverse judgment for rescission or for monetary damages could have a material adverse effect on Pioneer following the Merger.

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, 2013:



Period	Total Number of Shares (or Units) Purchased (a)	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased As Part of Publicly Announced Plans or Programs	Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs
July 2013	689	$	153.04	—
August 2013	1,953	$	170.11	—
September 2013	—	$	—	—
Total	2,642	$	165.66	—	$	—

____________________


(a)	Consists of shares purchased from each employee 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
2.1	—	Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 12, 2013).

2.2	—	Amendment No. 1, entered into as of October 25, 2013, to the Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 31, 2013).

10.1	—	Indemnification Agreement, dated effective July 23, 2013, between the Company and Stacy P. Methvin, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors 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 29, 2013).

10.2	—	Voting Agreement dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (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 August 12, 2013).

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 6, 2013	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy,
		Executive Vice President and Chief Financial Officer

Date: November 6, 2013	By:	/s/ FRANK W. HALL
		Frank W. Hall,
		Vice President and Chief Accounting Officer

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PIONEER NATURAL RESOURCES COMPANY

Exhibit Index



Exhibit Number		Description
2.1	—	Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 12, 2013).

2.2	—	Amendment No. 1, entered into as of October 25, 2013, to the Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 31, 2013).

10.1	—	Indemnification Agreement, dated effective July 23, 2013, between the Company and Stacy P. Methvin, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors 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 29, 2013).

10.2	—	Voting Agreement dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (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 August 12, 2013).

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.