Edgar Filing: PIONEER NATURAL RESOURCES CO

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Accelerated filer

Non-accelerated filer

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Smaller reporting company

PXD-2012.09.30

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, 2012



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

For the transition period from ________ to ________

Commission File Number: 1-13245

______________________________

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

______________________________



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

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

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

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

______________________________

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No ý

Number of shares of Common Stock outstanding as of October 31, 2012 123,232,483

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, 2012 and December 31, 2011	5

	Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011	7

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

	Consolidated Statement of Equity for the nine months ended September 30, 2012	9

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011	10

	Notes to Consolidated Financial Statements	11

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44

Item 4.	Controls and Procedures	48

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

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, 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 (including joint venture agreements) with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's operating activities, access to and availability of transportation, processing and refining facilities, Pioneer's ability to replace reserves, implement its business plans (including its plan to complete certain asset divestments) 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 an industrial sand mining business 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 (the "SEC"). 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, 2011 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.


•	"MMBTUPD" means MMBTU per day.


•	"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, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	333,886		$	537,484
Accounts receivable:
Trade, net of allowance for doubtful accounts of $832 and $806 as of September 30, 2012 and December 31, 2011, respectively	298,320			275,991
Due from affiliates	2,250			7,822
Income taxes receivable	10,126			3
Inventories	277,419			241,609
Prepaid expenses	21,657			14,263
Discontinued operations held for sale	400,392			73,349
Other current assets:
Derivatives	225,900			238,835
Other	9,934			12,936
Total current assets	1,579,884			1,402,292
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	13,250,249			12,013,805
Unproved properties	203,285			235,527
Accumulated depletion, depreciation and amortization	(4,107,432		)	(3,648,465		)
Total property, plant and equipment	9,346,102			8,600,867
Goodwill	293,449			298,142
Other property and equipment, net	1,186,131			573,075
Other assets:
Investment in unconsolidated affiliate	194,003			169,532
Derivatives	101,023			243,240
Other, net of allowance for doubtful accounts of $644 and $340 as of September 30, 2012 and December 31, 2011, respectively	113,409			160,008
	$	12,814,001		$	11,447,156

The financial information included as of September 30, 2012 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, 2012			December 31, 2011
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	736,381		$	647,455
Due to affiliates	68,255			68,756
Interest payable	40,960			57,240
Income taxes payable	222			9,788
Deferred income taxes	63,927			57,713
Discontinued operations held for sale	5,919			75,901
Other current liabilities:
Derivatives	14,815			74,415
Deferred revenue	10,575			42,069
Other	50,794			36,174
Total current liabilities	991,848			1,069,511
Long-term debt	3,562,070			2,528,905
Derivatives	27,938			33,561
Deferred income taxes	2,209,472			1,942,446
Other liabilities	222,564			221,595
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 134,782,883 and 133,121,092 shares issued at September 30, 2012 and December 31, 2011, respectively	1,348			1,331
Additional paid-in capital	3,641,248			3,613,808
Treasury stock at cost: 11,551,195 and 11,264,936 at September 30, 2012 and December 31, 2011, respectively	(504,140		)	(458,281		)
Retained earnings	2,485,935			2,335,066
Accumulated other comprehensive loss - net deferred hedge losses, net of tax	—			(3,130		)
Total equity attributable to common stockholders	5,624,391			5,488,794
Noncontrolling interests in consolidating subsidiaries	175,718			162,344
Total equity	5,800,109			5,651,138
Commitments and contingencies
	$	12,814,001		$	11,447,156

The financial information included as of September 30, 2012 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,
	2012			2011			2012			2011
Revenues and other income:
Oil and gas	$	695,422		$	574,114		$	2,014,920		$	1,595,563
Interest and other	18,733			7,311			53,224			49,378
Derivative gains (losses), net	(123,994		)	401,072			243,568			386,118
Gain (loss) on disposition of assets, net	13,237			1,048			57,973			(1,439		)
	603,398			983,545			2,369,685			2,029,620
Costs and expenses:
Oil and gas production	176,711			112,661			449,861			305,098
Production and ad valorem taxes	49,036			37,713			137,797			105,982
Depletion, depreciation and amortization	204,264			138,413			557,064			387,320
Exploration and abandonments	26,652			14,021			108,914			42,809
General and administrative	62,567			49,618			180,591			137,868
Accretion of discount on asset retirement obligations	2,369			1,993			6,994			5,930
Interest	54,441			45,560			150,307			135,782
Hurricane activity, net	—			(1,487		)	—			(1,418		)
Other	31,923			17,057			86,028			46,971
	607,963			415,549			1,677,556			1,166,342
Income (loss) from continuing operations before income taxes	(4,565		)	567,996			692,129			863,278
Income tax provision	(8,386		)	(182,728		)	(248,535		)	(278,732		)
Income (loss) from continuing operations	(12,951		)	385,268			443,594			584,546
Income (loss) from discontinued operations, net of tax	34,650			330			(240,474		)	410,556
Net income	21,699			385,598			203,120			995,102
Net income attributable to noncontrolling interests	(2,475		)	(34,134		)	(39,669		)	(49,467		)
Net income attributable to common stockholders	$	19,224		$	351,464		$	163,451		$	945,635

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.13	)	$	2.96		$	3.27		$	4.53
Income (loss) from discontinued operations attributable to common stockholders	0.28			—			(1.96		)	3.47
Net income attributable to common stockholders	$	0.15		$	2.96		$	1.31		$	8.00
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.13	)	$	2.95		$	3.19		$	4.44
Income (loss) from discontinued operations attributable to common stockholders	0.28			—			(1.91		)	3.41
Net income attributable to common stockholders	$	0.15		$	2.95		$	1.28		$	7.85
Weighted average shares outstanding:
Basic	123,111			116,281			122,874			116,122
Diluted	123,111			117,075			126,111			118,350
Dividends declared per share	$	0.04		$	0.04		$	0.08		$	0.08

Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	(15,426	)	$	351,134		$	403,925		$	535,079
Income (loss) from discontinued operations, net of tax	34,650			330			(240,474		)	410,556
Net income	$	19,224		$	351,464		$	163,451		$	945,635

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,
	2012			2011			2012			2011
Net income	$	21,699		$	385,598		$	203,120		$	995,102
Other comprehensive activity:
Net hedge (gains) losses included in continuing operations	—			(8,224		)	4,855			(24,418		)
Income tax (benefit) provision	—			1,838			(1,725		)	6,724
Other comprehensive activity	—			(6,386		)	3,130			(17,694		)
Comprehensive income	21,699			379,212			206,250			977,408
Comprehensive income attributable to the noncontrolling interests	(2,475		)	(30,670		)	(39,669		)	(39,192		)
Comprehensive income attributable to common stockholders	$	19,224		$	348,542		$	166,581		$	938,216

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			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Equity
Balance as of December 31, 2011	121,856		$	1,331	$	3,613,808		$	(458,281	)	$	2,335,066		$	(3,130	)	$	162,344		$	5,651,138
Dividends declared ($0.08 per share)	—		—		—			—			(9,999		)	—			—			(9,999		)
Exercise of long-term incentive plan stock options and employee stock purchases	190		—		(969		)	10,624			(2,583		)	—			—			7,072
Treasury stock purchases	(477	)	—		—			(56,488		)	—			—			(189		)	(56,677		)
Conversion of 2.875% senior convertible notes	—		—		(5		)	5			—			—			—			—
Tax benefit related to stock-based compensation	—		—		31,330			—			—			—			—			31,330
Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering	—		—		(49,072		)	—			—			—			—			(49,072		)
Compensation costs:
Vested compensation awards, net	1,663		17		(17		)	—			—			—			—			—
Compensation costs included in net income	—		—		46,173			—			—			—			864			47,037
Cash distributions to noncontrolling interests	—		—		—			—			—			—			(26,970		)	(26,970		)
Net income	—		—		—			—			163,451			—			39,669			203,120
Other comprehensive activity:
Deferred hedging activity, net of tax:
Net hedge losses included in continuing operations	—		—		—			—			—			3,130			—			3,130
Balance as of September 30, 2012	123,232		$	1,348	$	3,641,248		$	(504,140	)	$	2,485,935		$	—		$	175,718		$	5,800,109

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,
	2012			2011
Cash flows from operating activities:
Net income	$	203,120		$	995,102
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	557,064			387,320
Exploration expenses, including dry holes	52,574			5,228
Deferred income taxes	241,608			270,657
(Gain) loss on disposition of assets, net	(57,973		)	1,439
Accretion of discount on asset retirement obligations	6,994			5,930
Discontinued operations	293,646			(371,767		)
Interest expense	26,812			23,412
Derivative related activity	93,088			(269,746		)
Amortization of stock-based compensation	46,899			31,525
Amortization of deferred revenue	(31,494		)	(33,620		)
Other noncash items	(20,998		)	3,480
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(7,946		)	(35,252		)
Income taxes receivable	(8,632		)	28,588
Inventories	(6,347		)	(115,961		)
Prepaid expenses	(6,772		)	(7,558		)
Other current assets	7,898			8,520
Accounts payable	23,554			83,632
Interest payable	(16,302		)	(25,053		)
Income taxes payable	(9,566		)	(1,807		)
Other current liabilities	(29,757		)	45,969
Net cash provided by operating activities	1,357,470			1,030,038
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	92,473			819,638
Payments for acquisition, net of cash acquired	(296,959		)	—
Investment in unconsolidated subsidiary	—			(89,620		)
Additions to oil and gas properties	(2,072,800		)	(1,319,131		)
Additions to other assets and other property and equipment, net	(238,803		)	(265,740		)
Net cash used in investing activities	(2,516,089		)	(854,853		)
Cash flows from financing activities:
Borrowings under long-term debt	1,608,618			102,616
Principal payments on long-term debt	(596,000		)	(135,883		)
Distributions to noncontrolling interests	(26,970		)	(19,944		)
Payments of other liabilities	(894		)	(503		)
Exercise of long-term incentive plan stock options and employee stock purchases	7,072			3,690
Purchases of treasury stock	(56,677		)	(40,326		)
Excess tax benefits from share-based payment arrangements	31,330			28,123
Payment of financing fees	(6,430		)	(8,741		)
Dividends paid	(5,028		)	(4,812		)
Net cash provided by (used in) financing activities	955,021			(75,780		)
Net increase (decrease) in cash and cash equivalents	(203,598		)	99,405
Cash and cash equivalents, beginning of period	537,484			111,160
Cash and cash equivalents, end of period	$	333,886		$	210,565

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, 2012

(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 with operations in the United States.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2012 and for the three and nine months ended September 30, 2012 and 2011 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 or omitted in 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, 2011.

Certain reclassifications have been made to the 2011 financial statement and footnote amounts in order to conform to the 2012 presentation.

On May 6, 2008, the Company recognized a noncash gain on the sale of common units of Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest," a majority-owned and consolidated subsidiary) as a component of additional paid-in capital in stockholders' equity. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (“ASC”) Topic 740 Income Taxes, deferred income taxes of $49.1 million should be recognized for the future tax effects arising from the noncash gain on the sale of the Pioneer Southwest common units, with a corresponding decrease to additional paid-in capital. The Company recorded the deferred income taxes associated with this transaction in June 2012. The effect of this adjustment is immaterial to the accompanying financial statements.

Revision for deferred income taxes. The accompanying consolidated balance sheet as of December 31, 2011 has been revised for a change in the classification of deferred income taxes associated with the Company's unrealized current derivative net gains as of December 31, 2011. The noncash revisions resulted in a $77.0 million decrease in current deferred tax assets, a $57.7 million increase in current deferred tax liabilities and a $134.7 million decrease in noncurrent deferred tax liabilities from the amounts previously reported at December 31, 2011. These revisions were made to appropriately reflect the impact on deferred income taxes based on the expected settlement periods related to derivatives, which remained subject to market risk as of December 31, 2011. See "- Derivatives and hedging," below and Notes E and H for more information about derivative fair values and market risk.

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at their estimated fair values. See Note E for information about the fair value of the Company's derivatives. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing derivative hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income or loss ("AOCI - Hedging"), in the equity section of the Company's consolidated balance sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. During the six months ended June 30, 2012, the remaining hedge gains or losses that were previously deferred in AOCI - Hedging were transferred to earnings. Since discontinuing hedge accounting, the Company has recognized all changes in the fair values of its derivative contracts 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 executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and its counterparties are generally based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing Pioneer Southwest's borrowing rate.

Goodwill. Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2012, the Company performed a qualitative assessment of goodwill in accordance with FASB Accounting Standards Update ("ASU") No. 2011-08, Intangibles - Goodwill and Other (Topic 350) ("ASU 2011-08"), which permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test, and determined that it was not likely that the Company's goodwill was impaired. During the third quarter of 2012, the Company classified its Barnett Shale field assets and liabilities as discontinued operations held for sale. Associated therewith, the Company reclassified $4.7 million of goodwill attributable to the Barnett Shale assets to discontinued operations held for sale on the accompanying consolidated balance sheet at September 30, 2012. See Note C for more information about the Company's plan to sell its Barnett Shale net assets.

Impairment of assets. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate that their carrying values may not be fully recoverable. If the carrying value of long-lived assets is determined to be impaired, it is reduced to its estimated fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. See Note O for additional information about the Company's recent impairments and its risk of future impairments.

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of Pioneer acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC (the "Sand Acquisition"). During April 2012, the Company changed the name of Oglebay Norton Industrial Sands, LLC to Premier Silica LLC ("Premier Silica"). Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. Premier Silica's business is supportive to the Company's vertical integration strategy of controlling major cost components of the Company's drilling and production activities in the areas where the Company has a significant inventory of drilling locations and a significant number of producing wells. The aggregate purchase price of Premier Silica was $297.0 million, including closing adjustments, and was funded from available cash and borrowings under the Company's credit facility.

The Sand Acquisition was accounted for as a business combination which, among other things, requires that assets acquired and liabilities assumed be measured at their acquisition date fair values. The Company's assessment of the fair values of Premier Silica's assets and liabilities is preliminary, and may be adjusted as a result of normal closing adjustments. The fair value of the tangible assets acquired totaled $472.7 million and were primarily comprised of proved sand reserves, probable sand reserves and mine processing facilities and equipment of $458.2 million. The fair value of liabilities assumed totaled $175.8 million and were primarily comprised of deferred income taxes of $151.0 million.

The Company recognized $246 thousand and $2.4 million of acquisition-related costs associated with the Sand Acquisition that were expensed in the three and nine months ended September 30, 2012, respectively. These costs are included in other expense in the accompanying consolidated statements of operations for the three and nine months ended September 30, 2012.

Divestitures Recorded as Discontinued Operations

Barnett Shale. During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. The plan is expected to result in the sale of the Barnett Shale net assets during the first quarter of 2013. The Company has classified its (i) Barnett Shale assets and liabilities as discontinued operations held for sale in the accompanying consolidated balance sheet as of September 30, 2012 and (ii) Barnett Shale results of operations as income from discontinued

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

operations, net of tax, in the accompanying consolidated statements of operations (representing a recasting of the Barnett Shale results of operations for the three and nine months ended September 30, 2011 and six months ended June 30, 2012, which were originally classified as continuing operations).

South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest its net assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell its net assets in Pioneer South Africa to an unaffiliated third party, 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 of the Company's South Africa subsidiaries. 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 pretax gain of $28.6 million. The Company classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2011 and (ii) Pioneer South Africa's results of operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations (representing a recasting of Pioneer South Africa results of operations for the three and nine months ended September 30, 2011, which were originally classified as continuing operations).

Tunisia. In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third party for cash proceeds of $802.5 million, including normal closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia, prior to its sale, as discontinued operations, net of tax, in the accompanying consolidated statement of operations for the three and nine months ended September 30, 2011.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

The following table represents the components of the Company's discontinued operations for the three and nine months ended September 30, 2012 and 2011 (principally related to the divestitures of the Company's net assets in the Barnett Shale field and Pioneer South Africa and, for the nine months ended September 30, 2011, the divestiture of Pioneer Tunisia):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Revenues and other income:
Oil and gas	$	30,466		$	36,395		$	111,426		$	118,137
Interest and other	—			224			20			5,195
Gain (loss) on disposition of assets, net	28,179			(58		)	28,157			645,241
	58,645			36,561			139,603			768,573
Costs and expenses:
Oil and gas production	11,573			6,944			35,718			19,023
Production and ad valorem taxes	744			829			2,273			1,720
Depletion, depreciation and amortization (a)	3,134			18,043			32,673			54,717
Impairment of oil and gas properties (a) (b)	—			—			444,880			—
Exploration and abandonments	372			6,005			8,660			19,021
General and administrative	721			471			1,853			9,868
Accretion of discount on asset retirement obligations (a)	344			813			1,898			2,270
Interest	—			—			(75		)	773
Other	(26		)	245			1,313			4,457
	16,862			33,350			529,193			111,849
Income (loss) from discontinued operations before income taxes	41,783			3,211			(389,590		)	656,724
Current tax provision	(4,231		)	(9,338		)	(8,317		)	(35,872		)
Deferred tax (provision) benefit (a)	(2,902		)	6,457			157,433			(210,296		)
Income (loss) from discontinued operations	$	34,650		$	330		$	(240,474	)	$	410,556

____________________


(a)	Represents significant noncash components of discontinued operations.


(b)	Represents the pretax noncash impairment of Barnett Shale field oil and gas properties that was recorded during the three months ended June 30, 2012. See Note O for additional information about Barnett Shale field impairment.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

As of September 30, 2012 and December 31, 2011, the carrying values of Barnett Shale field and Pioneer South Africa assets and liabilities, respectively, were included in discontinued operations held for sale in the accompanying consolidated balance sheet and were comprised of the following:



	September 30, 2012		December 31, 2011
	(in thousands)
Composition of assets included in discontinued operations held for sale:
Current assets (excluding cash and cash equivalents)	$	13,127	$	10,465
Property, plant and equipment	351,736		53,025
Goodwill	4,693		—
Deferred tax assets	28,647		9,816
Other assets, net	2,189		43
Total assets	$	400,392	$	73,349

Composition of liabilities included in discontinued operations held for sale:
Current liabilities	$	160	$	11,689
Deferred revenue	—		34,320
Other liabilities	5,759		29,892
Total liabilities	$	5,919	$	75,901

Divestitures Recorded in Continuing Operations

The Company's net gain on disposition of assets of $13.2 million 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. Additionally, the Company's net gain on disposition of assets for the nine months ended September 30, 2012 of $58.0 million includes the first quarter sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million.

During the three and nine months ended September 30, 2011, the Company's net gains and losses on disposition of assets were primarily associated with the sales of excess materials and supplies inventories.

NOTE D. Exploratory Costs

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

The following table reflects the Company's capitalized exploratory well and project activity during the three and nine months ended September 30, 2012:



	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
	(in thousands)
Beginning capitalized exploratory costs	$	193,727		$	107,596
Additions to exploratory costs pending the determination of proved reserves	235,500			616,332
Reclassification due to determination of proved reserves	(224,784		)	(491,199		)
Exploratory well costs charged to exploration expense	(1,563		)	(29,849		)
Ending capitalized exploratory costs	$	202,880		$	202,880

The following table provides an aging, as of September 30, 2012 and December 31, 2011, 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, 2012		December 31, 2011
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	181,022	$	107,596
More than one year	21,858		—
	$	202,880	$	107,596

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

As of September 30, 2012, the Company had one project with exploratory costs that had been suspended for a period of one year or more, which is described below. As of December 31, 2011, the Company had no exploratory projects for which exploratory costs had been capitalized for a period greater than one year from the date drilling was completed.

Alaska - Oooguruk. As of September 30, 2012, the Company has $21.9 million 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, sub-surface damages were sustained. The Company currently expects to recomplete the well in mid-2013.

NOTE E. 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(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, 2012:



	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, 2012
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	162	$	157		$	—	$	319
Commodity derivatives	—		326,923			—		326,923
Deferred compensation plan assets	47,402		—			—		47,402
Total assets	47,564		327,080			—		374,644
Liabilities:
Commodity derivatives	—		(31,219		)	$	—	(31,219		)
Interest rate derivatives	—		(11,534		)	—		(11,534		)
Total liabilities	—		(42,753		)	—		(42,753		)
Total recurring fair value measurements	$	47,564	$	284,327		$	—	$	331,891

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, 2012, 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.

Interest rate derivatives. The Company's interest rate derivative liabilities as of September 30, 2012 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, 2012 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represent Level 2 inputs in the hierarchy priority.

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 Company's oil, NGL and gas swap, collar and collar contracts with short puts asset and liability measurements represent Level 2 inputs in the hierarchy priority. 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 which 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.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

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, 2012 and December 31, 2011 are as follows:



	September 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,562,070	$	4,449,088	$	2,528,905	$	3,105,585

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 rate (in the case of the Company's credit facility) or LIBOR (in the case of the Pioneer Southwest credit facility) yield curves 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, short-term receivables, prepaids, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and 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 F. Income Taxes

The Company's income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and nine months ended September 30, 2012 and 2011:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Current	$	13,052		$	(3,035	)	$	(6,927	)	$	(8,075	)
Deferred	(21,438		)	(179,693		)	(241,608		)	(270,657		)
Income tax provision	$	(8,386	)	$	(182,728	)	$	(248,535	)	$	(278,732	)

At the end of each interim reporting period, the Company updates its estimate of the annual effective tax rate. Tax items included in the annual effective tax rate are pro-rated for the full year and tax items discrete to a specific quarter are included in the effective tax rate for that quarter. The estimate used in providing for income taxes on a year-to-date basis may change in subsequent interim periods as new facts or circumstances become known. The annual effective tax rate represents the income tax benefit or provision divided by the income or loss from continuing operations before income taxes excluding the effect of net income attributable to noncontrolling interests. For the three months ended September 30, 2012 and 2011, the Company's effective tax rates are (119) percent and 34 percent, respectively, and for the nine months ended September 30, 2012 and 2011, the effective tax rates are 38 percent and 34 percent, respectively. The Company's effective tax rate for the three months ended September 30, 2012, as compared to the same period of the prior year, is primarily due to the impact of non-deductible items and state taxes on a pretax loss, excluding net income attributable to noncontrolling interests, of $7.0 million for the three months ended September 30, 2012, as compared to the impact of similar components on pretax income, excluding net income attributable to noncontrolling interests, of $533.9 million for the three months ended September 30, 2011.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2006. The Internal Revenue Service has closed examinations of the 2010 and prior tax years. As of September 30, 2012, no adjustments had

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

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, 2012, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Credit facility. During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that matures in March 2016, unless extended in accordance with the terms of the Credit Facility. As of September 30, 2012, the Company had $360.0 million of outstanding borrowings under the Credit Facility and $2.2 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $887.8 million of unused borrowing capacity under the Credit Facility.

Pioneer Southwest credit facility. During March 2012, Pioneer Southwest entered into an Amended and Restated 5-Year Revolving Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility provides for aggregate loan commitments of $300 million. As of September 30, 2012, Pioneer Southwest had $88.0 million of outstanding borrowings and $212.0 million of unused borrowing capacity under the Pioneer Southwest Credit Facility.

The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end maximum leverage ratio of not more than 3.5 to 1.00 and (ii) the maintenance of a ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas properties to total debt of at least 1.75 to 1.0.

Senior notes. During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds to reduce outstanding borrowings under the Credit Facility.

Convertible senior notes. As of September 30, 2012 and December 31, 2011, the Company had $479.9 million of 2.875% Convertible Senior Notes outstanding. The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, 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 2.875% Convertible Senior Notes were issued.

The Company's stock prices during each of March 2012 and March 2011 met the average price threshold that caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the three month periods ended June 30, 2012 and 2011. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $15 thousand and $70 thousand principal amounts of the notes for conversion during the three months ended June 30, 2012 and 2011, respectively. In accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement, the Company paid the tendering holders $15 thousand cash and issued to the tendering holders 55 shares of the Company's common stock during 2012 and paid the tendering holders a total of $71 thousand cash and issued to the tendering holders 340 shares of the Company's common stock during 2011.

The Company's stock prices during September 2012 also met the price threshold that causes the 2.875% Convertible Senior Notes to be convertible at the option of the holders for the three months ended December 31, 2012, and may become convertible in future quarters depending on the Company's stock price or other conditions.

On January 15, 2013, the 2.875% Convertible Senior Notes become redeemable at the option of the Company and on January 15, 2013, January 15, 2018, January 15, 2023, January 15, 2028 and January 15, 2033 the holders may require the Company to repurchase the notes for cash. The Company has the intent and ability to fund cash payments that may be required upon the conversion, redemption or repurchase of the 2.875% Convertible Senior Notes with borrowing capacity under the Credit Facility. Accordingly, the 2.875% Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets. If all of the 2.875% Convertible Senior Notes had been converted on September 30, 2012, the note holders would have received $479.9

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

million of cash and approximately 3.3 million shares of the Company's common stock, which was valued at $345.8 million on September 30, 2012.

NOTE H. 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 following table sets forth the volumes per day in barrels ("BBLs") outstanding as of September 30, 2012 under the Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:



	Three Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013		2014		2015
Collar contracts with short puts:
Volume (BBL) (a)	53,110			54,029		60,000		26,000
Average price per BBL:
Ceiling	$	118.85		$	119.60	$	117.06	$	104.45
Floor	$	85.09		$	89.71	$	92.67	$	95.00
Short put	$	69.44		$	73.74	$	76.58	$	80.00
Collar contracts:
Volume (BBL)	2,000			—		—		—
Average price per BBL:
Ceiling	$	127.00		$	—	$	—	$	—
Floor	$	90.00		$	—	$	—	$	—
Swap contracts:
Volume (BBL) (a)	11,000			20,000		—		—
Average price per BBL	$	89.34		$	97.27	$	—	$	—
Rollfactor swap contracts:
Volume (BBL)	—			6,000		—		—
NYMEX roll price (b)	$	—		$	0.43	$	—	$	—
Basis swap contracts:
Index swap volume (BBL)	20,000			—		—		—
Average price per BBL (c)	$	(1.15	)	$	—	$	—	$	—

____________________


(a)	Subsequent to September 30, 2012, the Company converted NYMEX swap contracts for 17,000 BBLs per day of 2013 production with a price of $100.14 per BBL into collar contracts with short puts for 17,000 BBLs per day of 2013 production with a ceiling price of $120.29 per BBL, a floor price of $100.41 per BBL and a short put price of $75.99 per BBL.


(b)	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.


(c)	Basis differential price between Midland WTI and Cushing WTI.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(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 outstanding as of September 30, 2012 under the Company's NGL derivative contracts and the weighted average NGL prices per BBL for those contracts:



	Three Months Ending December 31,		Twelve Months Ending December 31,
	2012		2013		2014
Collar contracts with short puts:
Volume (BBL)	3,000		1,000		1,000
Average price per BBL:
Ceiling	$	79.99	$	112.00	$	109.50
Floor	$	67.70	$	95.00	$	95.00
Short put	$	55.76	$	80.00	$	80.00
Swap contracts:
Volume (BBL)	2,750		—		—
Average price per BBL	$	67.85	$	—	$	—

____________________


(a)	Subsequent to September 30, 2012, the Company converted the 2013 collar contracts with short puts for 1,000 BBLs per day into collar contracts with short puts for 1,064 BBLs per day of 2013 natural gasoline production with a ceiling price of $105.28 per BBL, a floor price of $89.30 per BBL and a short put price of $75.20 per BBL.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

The following table sets forth the volumes per day in millions of British thermal units ("MMBTU") outstanding as of September 30, 2012 under the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:



	Three Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013			2014		2015
Collar contracts with short puts:
Volume (MMBTU) (a)	—			—			—		155,000
Price per MMBTU:
Ceiling	$	—		$	—		$	—	$	4.97
Floor	$	—		$	—		$	—	$	4.00
Short put	$	—		$	—		$	—	$	3.00
Collar contracts:
Volume (MMBTU)	65,000			150,000			—		—
Price per MMBTU:
Ceiling	$	6.60		$	6.25		$	—	$	—
Floor	$	5.00		$	5.00		$	—	$	—
Swap contracts:
Volume (MMBTU) (a)	275,000			112,500			105,000		—
Price per MMBTU	$	4.97		$	5.62		$	4.03	$	—
Basis swap contracts:
Volume (MMBTU)	136,000			142,500			—		—
Price per MMBTU	$	(0.34	)	$	(0.22	)	$	—	$	—

____________________


(a)	Subsequent to September 30, 2012, the Company entered into additional (i) 2013 swap contracts for 50,000 MMBTU per day priced at $4.01 per MMBTU and (ii) 2015 collar contracts with short puts for 70,000 MMBTU per day with a ceiling price of $5.35 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU.

Marketing and basis transfer derivative activities. Periodically, the Company enters into gas buy and sell marketing arrangements to utilize unused firm pipeline transportation commitments. Associated with these gas marketing arrangements, the Company may enter into gas index swaps to mitigate the related price risk. From time to time, the Company also enters into long and short gas swap contracts that transfer gas basis risk from one sales index to another sales index.

The following table sets forth the contract volumes outstanding as of September 30, 2012 under the Company's marketing and basis transfer derivative contracts and the weighted average gas prices per MMBTU for those contracts:



	Three Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013
Average Daily Gas Production Associated with Marketing Derivatives:
Basis swap contracts:
Index swap volume (MMBTU)	43,370			9,863
Price differential ($/MMBTU)	$	0.24		$	0.25
Average Daily Gas Production Associated with Basis Transfer Derivatives:
Basis swap contracts:
Short index swap volume (MMBTU)	1,685			—
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12		$	—
Long index swap volume (MMBTU)	(1,685		)	—
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)	$	—

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

Interest rates. As of September 30, 2012, the Company was a party to interest rate derivative contracts that lock 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. These derivative contracts mature and settle by their terms during December 2015.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of September 30, 2012 and December 31, 2011. The following tables provide disclosure of the Company's derivative instruments:

Fair Value of Derivative Instruments as of September 30, 2012

Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet

Location

Fair

Value

Balance Sheet

Location

Fair

Value

(in thousands)

Derivatives not designated as hedging instruments

Commodity price derivatives

Derivatives - current

234,231

Derivatives - current

23,145

Commodity price derivatives

Derivatives - noncurrent

108,819

Derivatives - noncurrent

24,201

Interest rate derivatives

Derivatives - noncurrent

—

Derivatives - noncurrent

11,534

343,050

58,880

Fair Value of Derivative Instruments as of December 31, 2011

Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet

Location

Fair

Value

Balance Sheet

Location

Fair

Value

(in thousands)

Derivatives not designated as hedging instruments

Commodity price derivatives

Derivatives - current

248,809

Derivatives - current

68,735

Interest rate derivatives

Derivatives - current

—

Derivatives - current

15,654

Commodity price derivatives

Derivatives - noncurrent

257,368

Derivatives - noncurrent

47,689

506,177

132,078

___________________


(a)	Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.



Derivatives in Cash Flow Hedging	Location of Gain/(Loss) Reclassified from	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
Derivatives in Cash Flow Hedging	Location of Gain/(Loss) Reclassified from	Three Months Ended September 30,					Nine Months Ended September 30,
Relationships	AOCI into Earnings	2012		2011			2012			2011
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	—	$	8,295		$	(3,156	)	$	24,627
Interest rate derivatives	Interest expense	—		(71		)	(1,699		)	(209		)
Total		$	—	$	8,224		$	(4,855	)	$	24,418

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)



		Amount of Gain (Loss) Recognized in Earnings on Derivatives
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	2012			2011			2012			2011
		(in thousands)
Commodity price derivatives	Derivative gains (losses), net	$	(118,795	)	$	407,407		$	267,806		$	380,030
Interest rate derivatives	Derivative gains (losses), net	(5,199		)	(6,335		)	(24,238		)	6,088
Total		$	(123,994	)	$	401,072		$	243,568		$	386,118

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

The following table provides the Company's net derivative assets or liabilities by counterparty as of September 30, 2012:



	Net Assets (Liabilities)
	(in thousands)

Citibank, N.A.	$	66,329
JP Morgan Chase	57,419
Barclays Capital	32,920
J. Aron & Company	20,846
BNP Paribas	20,061
BMO Financial Group	19,187
Credit Suisse	16,605
Toronto Dominion	15,144
Societe Generale	13,218
Morgan Stanley	8,852
Merrill Lynch	7,726
Den Norske Bank	6,161
Credit Agricole	2,099
Wells Fargo Bank, N.A.	756
BP Corporation North America	462
Macquarie Bank	454
Vitol	154
Royal Bank of Canada	(362		)
Deutsche Bank	(766		)
UBS	(3,095		)
Total	$	284,170

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

The following table summarizes the Company's asset retirement obligation activity during the three and nine months ended September 30, 2012 and 2011:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Beginning asset retirement obligations	$	145,457		$	151,970		$	136,742		$	152,291
Liabilities assumed in acquisitions	—			—			8,515			6
New wells placed on production	1,251			1,132			3,662			3,206
Changes in estimates	48			(5,453		)	1,651			(5,331		)
Liabilities reclassified to discontinued operations held for sale	(5,919		)	—			(5,919		)	—
Disposition of wells	(2,536		)	—			(2,536		)	(448		)
Liabilities settled	(4,506		)	(2,808		)	(13,248		)	(10,277		)
Accretion of discount from continuing operations	2,369			1,993			6,994			5,930
Accretion of discount from integrated services (a)	23			—			77			—
Accretion of discount from discontinued operations	127			813			376			2,270
Ending asset retirement obligations	$	136,314		$	147,647		$	136,314		$	147,647

_____________________


(a)	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 M 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, 2012 and December 31, 2011, the current portions of the Company's asset retirement obligations were $16.1 million and $14.2 million, respectively.

NOTE J. Incentive Plans

Stock-based compensation

For the three and nine months ended September 30, 2012, the Company recorded $22.8 million and $66.0 million, respectively, of stock-based compensation expense for all plans, as compared to $11.7 million and $38.1 million for the same respective periods of 2011. As of September 30, 2012, there was $143.9 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $28.3 million attributable to stock-based awards that are expected to be settled in cash on their vesting date, 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 September 30, 2012 and December 31, 2011, accounts payable – due to affiliates includes $13.5 million and $9.2 million, respectively, of liabilities attributable to Liability Awards.

The Company's issued shares, as reflected in the consolidated balance sheets at September 30, 2012 and December 31, 2011, do not include 304,260 and 533,125 common shares, respectively, associated with unvested stock-based compensation awards that have voting rights.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

The following table summarizes the activity that occurred during the nine months ended September 30, 2012, for each type of share-based incentive award issued by Pioneer:



	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units		Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2011	1,857,612		322,925		114,128	564,044		7,492		65,157
Awards granted	912,543		240,524		47,875	98,819		7,496		37,487
Awards vested	(1,220,841	)	(127,919	)	—	—		(7,492	)	—
Options exercised	—		—		—	(190,377	)	—		—
Awards forfeited	(21,472	)	(18,360	)	—	—		—		—
Outstanding as of September 30, 2012	1,527,842		417,170		162,003	472,486		7,496		102,644

Postretirement Benefit Obligations

As of September 30, 2012 and December 31, 2011, the Company had $8.1 million and $7.5 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities 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 two funded plans that the Company assumed sponsorship for in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of September 30, 2012 or December 31, 2011. The Company's funding policy for the Premier Silica plans 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.

NOTE K. Commitments and Contingencies

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

NOTE L. Net Income (Loss) Per Share

The Company uses the two-class method of calculating net income (loss) 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 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.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

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, 2012 and 2011:



	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	$	(15,426	)	$	34,650		$	19,224		$	403,925		$	(240,474	)	$	163,451
Participating basic earnings	—			(357		)	(357		)	(2,499		)	—			(2,499		)
Basic net income (loss) attributable to common stockholders	(15,426		)	34,293			18,867			401,426			(240,474		)	160,952
Reallocation of participating earnings	—			—			—			134			—			134
Diluted income (loss) attributable to common stockholders	$	(15,426	)	$	34,293		$	18,867		$	401,560		$	(240,474	)	$	161,086



	Three Months Ended September 30, 2011									Nine Months Ended September 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income attributable to common stockholders	$	351,134		$	330		$	351,464		$	535,079		$	410,556		$	945,635
Participating basic earnings	(6,791		)	(6		)	(6,797		)	(9,725		)	(7,461		)	(17,186		)
Basic income attributable to common stockholders	344,343			324			344,667			525,354			403,095			928,449
Reallocation of participating earnings	189			—			189			259			199			458
Diluted income attributable to common stockholders	$	344,532		$	324		$	344,856		$	525,613		$	403,294		$	928,907

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(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, 2012 and 2011:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
	(in thousands)
Weighted average common shares outstanding:
Basic	123,111	116,281	122,874	116,122
Dilutive common stock options (a)	—	166	196	181
Convertible senior notes dilution (a)	—	185	2,866	1,618
Contingently issuable performance unit shares (a)	—	443	175	429
Diluted	123,111	117,075	126,111	118,350

____________________

(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.

NOTE M. Interest and Other Income

The following table provides the components of the Company's interest and other income:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)
Equity in income of unconsolidated affiliate (a)	$	9,629	$	1,641	$	24,471	$	2,442
Alaskan Petroleum Production Tax credits and refunds (b)	3,979		95		15,825		27,547
Third-party income from vertical integration services (c)	3,465		3,612		6,194		11,524
Other income	1,372		1,596		3,607		5,931
Deferred compensation plan income	204		288		1,727		1,454
Interest income	84		79		1,400		480
Total interest and other income	$	18,733	$	7,311	$	53,224	$	49,378

____________________


(a)	Represents the Company's equity in the earnings of EFS Midstream LLC ("EFS Midstream"), which owns and operates gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas.


(b)	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.


(c)	Third-party income from vertical integration services reflects earnings from third-party working interest owners in Company-operated wells in which the Company provided fracture stimulation, drilling and related services.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

NOTE N. Other Expense

The following table provides the components of the Company's other expense:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in thousands)
Transportation commitment charges (a)	$	9,694	$	5,141	$	27,374	$	16,101
Above market drilling rig and well services equipment rates (b)	12,720		4,632		23,466		15,201
Terminated drilling rig contract charges (c)	6,807		—		15,768		—
Other	2,340		4,951		10,136		9,867
Inventory valuation charges (d)	46		1,745		6,093		2,332
Premier Silica acquisition costs	246		—		2,419		—
Contingency and environmental accrual adjustments	70		588		772		3,470
Total other expense	$	31,923	$	17,057	$	86,028	$	46,971

____________________


(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 and fracture stimulation fleet fees, neither of which are charged to joint operations.


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


(d)	Represents valuation charges on excess materials and supplies inventories; principally related to dry gas assets.

NOTE O. Impairment

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 past year, reductions in management's outlook for commodity prices have provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in Southeastern Colorado. As a result of management's assessments, during the fourth quarter of 2011 and second quarter of 2012, the Company recognized pretax noncash impairment charges of $354.4 million and $444.9 million, respectively, to reduce the carrying values of the Edwards Trend/Austin Chalk fields and the Barnett Shale field to their estimated fair values. 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 outlook for (i) oil and gas prices of $87.09 per BBL for oil and $4.64 per MCF of 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. The Barnett Shale field's impairment charge is recorded as discontinued operations in the accompanying consolidated statement of operations for the nine months ended September 30, 2012. See Note C for more information about Barnett Shale field discontinued operations.

Impairment risk. The Company's estimates of undiscounted future net cash flows attributable to the Raton field have indicated that its carrying amount is expected to be recovered. However, the carrying value of the field continues to be at risk for impairment if future estimates of undiscounted cash flows decline. As of September 30, 2012, the Company's Raton field had a carrying value of $2.2 billion.

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to the Raton field 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 futures cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's commodity price outlooks and (iv) increases or decreases in production and capital costs associated with the properties.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

NOTE P. Subsequent Event

Distribution declaration. In October 2012, Pioneer Southwest declared a cash distribution of $0.52 per common unit for the period from July 1 to September 30, 2012. The distribution is payable on November 9, 2012 to unitholders of record at the close of business on November 2, 2012 . Associated therewith, Pioneer Southwest expects to pay $18.6 million of aggregate distributions.

Table of Contents

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 2012 included the following highlights:


•	Net income attributable to common stockholders for the third quarter of 2012 was $19.2 million ($0.15 per diluted share), as compared to $351.5 million ($2.95 per diluted share) for the third quarter of 2011. The decrease in net income attributable to common stockholders is primarily comprised of a $398.2 million decrease in net income (loss) from continuing operations, which includes:


▪	recognizing net derivative losses of $124.0 million for the three months ended September 30, 2012, as compared to net derivative gains of $401.1 million for the three months ended September 30, 2011;


▪	a $65.9 million increase in DD&A expense, primarily due to increased sales volumes;


▪	a $64.1 million increase in oil and gas production costs, primarily due to increases in variable lease operating expenses and third-party transportation fees due to higher sales volumes; partially offset by


▪	a $174.3 million decline in income tax provisions attributable to continuing operations; and


▪	a $121.3 million increase in oil and gas revenues as a result of an increase in sales volumes, partially offset by lower average commodity prices.

•

During the third quarter of 2012, average daily sales volumes increased by 28 percent to 153,016 BOEPD, as compared to 119,597 BOEPD during the third quarter of 2011. The increase in third quarter 2012 average daily sales volumes, as compared to the third quarter of 2011, was primarily due to the Company's successful drilling program during the last three months of 2011 and the first nine months of 2012;


•	Average reported oil, NGL and gas prices decreased during the third quarter of 2012 to $89.87 per BBL, $31.28 per BBL and $2.62 per MCF, respectively, as compared to $92.11 per BBL, $48.33 per BBL and $4.05 per MCF, respectively, in the third quarter of 2011;

•

Average oil and gas production costs per BOE increased to $12.55 for the third quarter of 2012, as compared to $10.23 for the third quarter of 2011, primarily due to increases in lease operating expenses, third party transportation charges and net natural gas plant charges. The increase in lease operating expenses is primarily due to increases in salt water disposal costs (principally comprised of water hauling fees) and higher repair and maintenance activity during the third quarter of 2012. The increase in third-party transportation costs is primarily due to gathering, treating and transportation costs associated with increasing sales volumes in the Eagle Ford Shale field. Net natural gas plant charges increased primarily due to a reduction in third-party gas volumes in Company-owned facilities as a result of lower gas and NGL prices being realized on the volumes retained as processing fees. See "Results of Operations," below for more information about changes in production costs;


•	Net cash provided by operating activities decreased to $432.1 million for the three months ended September 30, 2012, as compared to $465.6 million for the three months ended September 30, 2011. The $33.5 million decrease in net cash provided by operating activities is primarily due to working capital changes during the third quarter of 2012;


•	In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal closing adjustments. The Company recorded a pretax gain of $28.6 million on the sale of Pioneer South Africa in income (loss) from discontinued operations for the three and nine months ended September 30, 2012;


•	In early August 2012, the Company announced plans to pursue a joint venture partner to accelerate the development of the horizontal Wolfcamp Shale play in the southern 200,000 acres of the Company's total prospective position. See "Operations and Drilling Highlights" for more information about the Company's Wolfcamp Shale play;

•

In early September 2012, the Company announced plans to divest of its properties in the Barnett Shale field. The Company has opened a data room and is targeting completing the transaction during the first quarter of 2013. Accordingly, the Company has classified its (i) Barnett Shale assets and liabilities as discontinued operations held for sale in the accompanying consolidated balance sheet as of September 30, 2012 and (ii) Barnett Shale results of operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations (representing a recasting of the Barnett Shale field results of operations for the three and nine months ended September 30, 2011 and the six months ended June 30, 2012, which were originally classified as continuing operations). See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about discontinued operations;


•	As of September 30, 2012, the Company's net debt to book capitalization was 36 percent, as compared to 26 percent as

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of December 31, 2011. The Company was upgraded to investment grade by one of its debt rating agencies during the fourth quarter of 2011 and by another rating agency during the second quarter of 2012.

Fourth Quarter 2012 Outlook

Based on current estimates, the Company expects the following operations and financial results from continuing operations for the quarter ending December 31, 2012:

Production is forecasted to average 154,000 to 158,000 BOEPD. This assumes the remaining NGL inventory at Mont Belvieu, Texas of 90,000 barrels will be drawn down during the fourth quarter, but will be offset by line fill requirements in the fourth quarter for the new Lone Star NGL pipeline in which the Company will be a shipper. The fourth quarter production estimate also assumes a negative impact ranging from 1,000 BOEPD to 2,000 BOEPD due to reduced ethane recoveries associated with gas processing facilities in the Spraberry field nearing capacity. See "Results of Operations" for more information about NGL inventories, the Lone Star NGL pipeline fill and related Spraberry gas processing limitations.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $14.50 to $16.50 per BOE based on continuing higher salt water disposal and electricity costs, higher per-BOE costs resulting from the gas processing capacity limitations negatively impacting sales volumes and current NYMEX strip commodity prices. DD&A expense is expected to average $13.50 to $15.50 per BOE.

Total exploration and abandonment expense is expected to be $25 million to $35 million. General and administrative expense is expected to be $60 million to $65 million. Interest expense is expected to be $53 million to $58 million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 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 $2 million to $7 million, primarily attributable to state taxes.

Operations and Drilling Highlights

The following table summarizes the Company's average daily oil, NGL, gas and total production from continuing operations by asset area during the nine months ended September 30, 2012:



	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	43,186	12,926	59,855	66,088
South Texas - Eagle Ford Shale	9,267	6,616	57,132	25,405
Raton Basin	—	—	151,648	25,275
Mid-Continent	3,213	6,979	47,802	18,159
South Texas - Edwards and Austin Chalk	78	1	37,921	6,399
Alaska	4,325	—	—	4,325
Other	1	4	110	23
	60,070	26,526	354,468	145,674

During 2012 and 2011, the Company has focused its capital budgets and expenditures on oil- and liquids-rich-gas drilling activities as a result of the decline in gas prices. As a result of these capital activities and commodity price changes, the Company's total liquids production and revenue from continuing operations has increased to 59 percent and 88 percent, respectively, for the nine months ended September 30, 2012 from 51 percent and 77 percent, respectively, for the same period last year.

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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, 2012:



	Acquisition Costs				Exploration		Development		Asset Retirement
	Proved		Unproved		Costs		Costs		Obligations		Total
	(in thousands)
Permian Basin	$	3,099	$	56,157	$	280,853	$	1,273,779	$	2,375	$	1,616,263
South Texas - Eagle Ford Shale	—		9,740		131,179		4,973		62		145,954
Raton Basin	—		—		6,397		6,469		—		12,866
Mid-Continent	—		4,153		3,524		14,712		—		22,389
South Texas - Edwards and Austin Chalk	—		130		3,525		5,845		—		9,500
Barnett Shale	8,673		7,732		171,476		47,528		337		235,746
Alaska	—		—		62,522		88,641		2,532		153,695
Other	47		39,967		1,777		9		—		41,800
	$	11,819	$	117,879	$	661,253	$	1,441,956	$	5,306	$	2,238,213

The following table summarizes the Company's development and exploration/extension drilling activities for the nine months ended September 30, 2012:



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	161	500	547	8	106
Raton Basin	5	—	4	1	—
Barnett Shale	—	4	4	—	—
Alaska	1	3	2	—	2
Total United States	167	507	557	9	108



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	—	31	16	—	15
South Texas - Eagle Ford Shale	39	99	102	—	36
Mid-Continent	5	—	—	5	—
Barnett Shale	26	27	39	—	14
Alaska	1	2	—	1	2
Total United States	71	159	157	6	67

Permian Basin area. The Company currently has 30 rigs operating in the Spraberry field, of which 25 are drilling vertical wells and five are drilling Wolfcamp Shale horizontal wells. During 2012, the Company expects to drill approximately 625 vertical wells and 30 to 35 horizontal Wolfcamp Shale wells.

In the horizontal Wolfcamp Shale play, the Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Wolfcamp A, B, C and D intervals and its drilling results to-date. The Company's horizontal drilling activity for the remainder of 2012 and 2013 will be primarily focused on the 200,000 acres in the southern part of the play where the Company expects to drill approximately 90 horizontal wells by the end of 2013 to hold approximately 50,000 expiring acres. The Company plans to continue drilling in the B interval and the A interval in this area.

The Company's first two successful horizontal Wolfcamp Shale wells were drilled in northern Upton County in the Upper B interval in the Giddings Estate area. The first well had its one-year anniversary from the date of first production in mid-October and has produced 135 MBOE to date. The second well has been on production for ten months and has delivered cumulative production of 105 MBOE.

During the third quarter of 2012, the Company initiated plans to delineate the northern part of its Spraberry acreage position by drilling in Midland, Martin and Gaines Counties. Wells drilled in this area are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths. Pioneer believes a successful drilling program in this area could substantially increase its prospective horizontal Wolfcamp Shale acreage position.

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During the third quarter of 2012, the Company opened a data room and initiated plans to pursue a joint venture partner to accelerate the development of the horizontal Wolfcamp Shale in the southern 200,000 acres of the Company's total prospective acreage position. The Company is offering 33 percent to 50 percent of its working interest in the southern acreage. No assurance can be provided that the Company will be successful in attracting a joint venture partner or that a joint venture partner will offer an acquisition price that is acceptable to the Company.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval. This deeper drilling includes the Strawn, Atoka and Mississippian intervals. Production from these deeper intervals has contributed to the Company's production growth during 2012. The original 2012 drilling program planned for the Wolfcamp to be the deepest interval completed in approximately 50 percent of the wells. The remaining 50 percent of the wells were to be deepened below the Wolfcamp interval. The current drilling program reflects 65 percent of the wells being deepened below the Wolfcamp interval. Based on results to-date, the Company estimates that 70 percent of its Spraberry acreage position is prospective for the Strawn interval, 40 percent to 50 percent of its acreage position is prospective for the Atoka interval and that the Mississippian interval is prospective in 20 percent of the Company's Spraberry acreage.

In the Spraberry interval, the Company drilled two successful horizontal Jo Mill wells with lateral lengths of 2,628 and 2,178 feet. The Company is continuing to analyze the results of the two wells and plans to drill additional horizontal Jo Mill wells in the future.

The Company has expanded its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has 15 Company-owned drilling rigs, five Company-owned vertical fracture stimulation fleets and two Company-owned horizontal fracture stimulation fleets currently operating 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, in early April 2012, the Company completed the acquisition of Premier Silica, which is expected to supply the Company's growing brown sand requirements for fracture stimulating wells in the vertical Spraberry and horizontal Wolfcamp Shale plays.

Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2012 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2012 drilling program has been focused on liquids-rich drilling, with only 10 percent of the wells designated to hold strategic dry gas acreage.

The Company completed 102 horizontal Eagle Ford Shale wells during the first nine months of 2012, all of which were successful, with average lateral lengths of approximately 5,500 feet and, on average, 13-stage fracture stimulations. The Company is currently running 11 drilling rigs and three fracture stimulation fleets, two of which are Pioneer-owned fleets, in the play.

The Company has also been testing the use of 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 is continuing to monitor the performance of these wells and expects that 50 percent of its 2012 drilling program will have used lower-cost white sand proppant. During 2013, the Company expects that greater than 50 percent of the wells drilled will use white sand proppant.

The unconsolidated affiliate formed by the Company to operate gathering facilities in the Eagle Ford Shale area, EFS Midstream, is obligated to construct midstream assets in the Eagle Ford Shale area. Eleven of the 13 planned central gathering plants ("CGPs") were completed as of September 30, 2012. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term. During 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that is being used to fund infrastructure investments that exceed its operating cash flows.

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 16 production wells and 10 injection wells to develop this project. During the first quarter of 2012, the Company drilled an exploration well which was drilled from an onshore location to further 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. The well had a gross initial production rate of approximately 2,000 barrels of oil per day. The well is now shut in awaiting permanent onshore production facilities, for which an onshore development front-end engineering design (FEED) study has been initiated. In September 2012, the Company entered into a contract for a drilling rig that is now committed to drill a second well in this formation during the upcoming winter to further appraise this interval.

During the first quarter of 2012, the Company also completed its first successful mechanically diverted fracture stimulation

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of a Nuiqsut interval well from the Oooguruk development facilities. Gross initial production from the test was at a rate of 4,000 barrels of oil per day. Based on the success of this fracture stimulation, the Company plans to fracture stimulate four new wells this winter using a similar completion design.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $695.4 million and $2.0 billion for the three and nine months ended September 30, 2012, respectively, as compared to $574.1 million and $1.6 billion for the same respective periods in 2011.

The increase in oil and gas revenues during the three months ended September 30, 2012, as compared to the same period in 2011, is reflective of 52 percent, 40 percent and six percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the quarter-to-quarter comparison were declines of two percent, 35 percent and 35 percent in reported oil, NGL and gas prices, respectively. The increase in oil and gas revenues during the nine months ended September 30, 2012, as compared to the same period in 2011, is reflective of 63 percent, 32 percent and eight percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the nine month comparisons were declines of four percent, 25 percent and 41 percent in reported oil, NGL and gas prices, respectively.

The following table provides average daily sales volumes for the three and nine months ended September 30, 2012 and 2011:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
Oil (BBLs)	63,125	41,463	60,070	36,943
NGLs (BBLs)	30,352	21,748	26,526	20,132
Gas (MCF)	357,232	338,321	354,468	328,464
Total (BOE)	153,016	119,597	145,674	111,819

Average daily BOE sales volumes increased by 28 percent and 30 percent for the three and nine months ended September 30, 2012, as compared to the same respective periods in 2011, principally due to the Company's successful drilling program and the sale of NGLs that were placed in storage during the second quarter of 2012. Specifically, portions of the Company's gas production include NGLs that are separated at the Midkiff/Benedum and Sale Ranch gas processing facilities in West Texas. These NGLs are then transported to third-party fractionation facilities at Mont Belvieu. During May, a significant third-party facility was shut down for planned maintenance. When the facility came back on line in late May, it had operating problems and was not able to achieve its pre-shutdown fractionation capacity. As a result of these problems and the fractionation capacity limitations across the Mont Belvieu complex, the Company built an NGL inventory of 256 thousand barrels that could not be processed for sale in June, thereby reducing production for the second quarter by 2,800 BOEPD. During the third quarter of 2012, the Company was periodically able to utilize some available fractionation capacity across the Mont Belvieu complex to reduce its inventory levels. In addition, during September of 2012, the fractionation facility was able to partially increase its processing rates, thereby allowing the Company to begin selling a portion of its NGL inventory. Sales volumes for the third quarter of 2012 included 1,805 BOEPD of NGL inventory fractionated and sold, leaving approximately 90,000 barrels in NGL inventory that could not be processed as of September 30, 2012. The remaining NGL inventory is expected to be fractionated and sold during the three months ended December 31, 2012.

In addition to the NGL inventory changes discussed above, production growth for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, was negatively impacted by approximately 4,000 BOEPD and 2,000 BOEPD, respectively, due to the Midkiff/Benedum gas processing plants being forced to reject ethane into the residue gas stream during the second and third quarters of 2012 as a result of the NGL fractionation capacity limitations at Mont Belvieu. In early October 2012, the fractionation facility resolved its operating problems and restored its processing rates to its pre-shutdown processing capacity. However, the Company's fourth quarter production will be negatively impacted by volumes that will not be sold but used to fill a new NGL sales line. The impact of using fourth quarter volumes for line fill is expected to be 1,000 BOEPD to 1,200 BOEPD. Fourth quarter 2012 production is also expected to be 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. For the fourth quarter, production is expected to be 1,000 BOEPD to 2,000 BOEPD lower as a result of the gas processing capacity limitations, leading to reduced recoveries of ethane. New gas processing facilities are being built and are expected to be on production in late March or early April of 2013.

The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities adjusted for transfers of the Company's deferred hedge gains and losses from AOCI-Hedging and the amortization of deferred VPP revenue. See "Derivative activities" and "Deferred revenue" discussion below for additional information regarding the Company's past cash

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flow hedging activities and the amortization of deferred VPP revenue.

The following table provides the Company's average reported prices (including transfers of deferred hedge gains and losses and the amortization of deferred VPP revenue) and average realized prices (excluding transfers of deferred hedge gains and losses and the amortization of deferred VPP revenue) for the three and nine months ended September 30, 2012 and 2011:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Average reported prices:
Oil (per BBL)	$	89.87	$	92.11	$	92.83	$	97.06
NGL (per BBL)	$	31.28	$	48.33	$	35.10	$	46.59
Gas (per MCF)	$	2.62	$	4.05	$	2.39	$	4.02
Total (per BOE)	$	49.40	$	52.18	$	50.48	$	52.27
Average realized prices:
Oil (per BBL)	$	88.05	$	86.96	$	91.11	$	91.28
NGL (per BBL)	$	31.28	$	48.33	$	35.10	$	46.59
Gas (per MCF)	$	2.62	$	4.05	$	2.39	$	4.02
Total (per BOE)	$	48.65	$	50.39	$	49.77	$	50.36

Derivative activities. 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 and nine months ended September 30, 2012, the Company transferred nil and $3.2 million, respectively, of deferred oil hedge losses from AOCI-Hedging to oil revenue, as compared to transferring $8.3 million and $24.6 million of deferred oil hedge gains, respectively, from AOCI-Hedging to oil revenue during the same respective periods in 2011.

Deferred revenue. During the three and nine months ended September 30, 2012, the Company's amortization of deferred VPP revenue increased oil revenues by $10.6 million and $31.5 million as compared to increases of $11.3 million and $33.6 million during the same respective periods in 2011.

Derivative gains, net. During the three months ended September 30, 2012, the Company recorded $124.0 million of net derivative losses on commodity price and interest rate derivatives, of which $237.1 million represented unrealized net losses and $113.1 million represented realized net gains. During the nine months ended September 30, 2012, the Company recorded $243.6 million of net derivative gains on commodity price and interest rate derivatives, of which $89.9 million represented unrealized net losses and $333.5 million represented realized net gains. During the three and nine months ended September 30, 2011, the Company recorded $401.1 million of net derivative gains and $386.1 million of net derivative gains, respectively. Derivative gains and losses result from changes in the fair values of the Company's derivative contracts. During the nine months ended September 30, 2012, the Company terminated (i) swap, collar, collar contracts with short puts and basis swap derivative contracts for 2014 and 2015 gas production, (ii) swap derivative contracts for 2012 and 2013 diesel fuel and (iii) $200 million notional amount of interest rate derivative contracts. As a result of these transactions, the Company realized $44.5 million of net proceeds during the third quarter of 2012 and $118.2 million of net proceeds during the nine months ended September 30, 2012. See Notes E and H 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.

Interest and other income. Interest and other income for the three and nine months ended September 30, 2012 was $18.7 million and $53.2 million, respectively, as compared to $7.3 million and $49.4 million, respectively, for the same periods in 2011. The $11.4 million increase in interest and other income during the three months ended September 30, 2012, as compared to the same period in 2011, was primarily due to an $8.0 million increase in equity in earnings of EFS Midstream and a $3.9 million increase in Alaskan PPT credit recoveries. The $3.8 million increase in interest and other income during the nine months ended September 30, 2012, as compared to the same period in 2011, was primarily due to a $22.0 million increase in equity in earnings of EFS Midstream, partially offset by a $11.7 million decrease in Alaskan PPT credit recoveries and a $5.3 million decrease in third-party income from vertical integration services. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding interest and other income.

Gain (Loss) on disposition of assets, net. The Company recorded net gains on the disposition of assets of $13.2 million and $58.0 million, respectively, during the three and nine months ended September 30, 2012, as compared to a net gain on the disposition

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of assets of $1.0 million and a net loss on the disposition of assets of $1.4 million, respectively, for the same periods of 2011. 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 includes the first quarter sale of a portion of the Company's interest in an unproved oil and gas property in the Eagle Ford Shale field to unaffiliated third parties for 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 $176.7 million and $449.9 million during the three and nine months ended September 30, 2012, respectively, as compared to $112.7 million and $305.1 million during the same respective periods in 2011. In general, 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, 2012 increased by 23 percent and 13 percent, respectively, as compared to the same periods in 2011. The increase in production costs per BOE during the three months ended September 30, 2012, as compared to the third quarter of 2011, is primarily reflective of increases in lease operating expenses, third-party transportation charges and net natural gas plant/gathering charges. Lease operating costs increased during the three and nine months ended September 30, 2012 primarily due to $0.48 per BOE and $0.56 per BOE increases in salt water disposal costs, respectively, (principally comprised of water hauling fees), higher repair and maintenance activity during the third quarter ($0.35 per BOE) and the aforementioned production loss of approximately 4,000 BOEPD that resulted from NGL fractionation capacity limitations at Mont Belvieu. The increase in third-party transportation charges during the three and nine months ended September 30, 2012 is primarily due to gathering, treating and transportation costs associated with increasing sales volumes from the Company's successful drilling program in the Eagle Ford Shale field. Net natural gas plant charges increased during the three and nine months ended September 30, 2012, primarily due to a reduction in third-party revenues from processing third-party gas volumes in Company-owned facilities as a result of lower gas and NGL prices being realized on the volumes retained as a processing fee.

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, 2012 and 2011:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Lease operating expenses	$	9.36	$	8.14	$	8.20	$	7.94
Third-party transportation charges	1.82		1.16		1.77		1.09
Net natural gas plant charges	0.61		0.14		0.51		0.09
Workover costs	0.76		0.79		0.79		0.87
Total production costs	$	12.55	$	10.23	$	11.27	$	9.99

Production and ad valorem taxes. The Company's production and ad valorem taxes were $49.0 million and $137.8 million during the three and nine months ended September 30, 2012, respectively, as compared to $37.7 million and $106.0 million for the same respective periods in 2011. 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, 2012 and 2011:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Ad valorem taxes	$	1.37	$	1.20	$	1.33	$	1.37
Production taxes	2.11		2.23		2.12		2.10
Total ad valorem and production taxes	$	3.48	$	3.43	$	3.45	$	3.47

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Depletion, depreciation and amortization expense. The Company's DD&A expense was $204.3 million ($14.51 per BOE) and $557.1 million ($13.96 per BOE) for the three and nine months ended September 30, 2012, respectively, as compared to $138.4 million ($12.58 per BOE) and $387.3 million ($12.69 per BOE) during the same respective periods in 2011. The increases in per BOE depletion expense during the three and nine months ended September 30, 2012, as compared to the same periods of 2011, are primarily due to increases in depletion expense per BOE on oil and gas properties.

Depletion expense on oil and gas properties was $13.86 per BOE and $13.32 per BOE during the three and nine months ended September 30, 2012, respectively, as compared to $12.09 and $12.06 per BOE during the same respective periods in 2011. The 15 percent and 10 percent increases in per-BOE depletion expense during the three and nine months ended September 30, 2012, as compared to the same respective periods in 2011, are primarily due to (i) increased drilling expenditures on proved undeveloped locations, primarily in the Spraberry field and (ii) declines in proved gas reserves due to lower first-day-of-the-month gas prices during the 12-month period ending on September 30, 2012, partially offset by (iii) the impact of the fourth quarter 2011 impairment of $354.4 million of South Texas Edwards and Austin Chalk field carrying values.

Impairment of oil and gas properties. 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 past year, reductions in management's outlook for commodity prices have provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in Southeastern Colorado. As a result of management's assessments, during the fourth quarter of 2011 and second quarter of 2012, the Company recognized pretax noncash impairment charges of $354.4 million and $444.9 million, respectively, to reduce the carrying values of the South Texas Edwards Trend/Austin Chalk fields and Barnett Shale field to their estimated fair values. The Barnett Shale field impairment charge is included in the loss from discontinued operations in the accompanying consolidated statement of operations for the nine months ended September 30, 2012. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about discontinued operations.

The Company's estimates of undiscounted future net cash flows attributable to the Raton field oil and gas properties indicated on September 30, 2012 that its carrying amount was expected to be recovered. However, the carrying value of this field continues to be at risk for impairment if future estimates of undiscounted cash flows decline. For example, the Company estimates that the carrying value of the Raton field may become partially impaired if management's long-term outlook for gas prices, which was $4.99 per MCF as of September 30, 2012, were to decline by approximately $0.50 per MCF to $0.60 per MCF, assuming none of the other impairment inputs changed. The Company's Raton field is a relatively long-lived asset that had a carrying value of $2.2 billion as of September 30, 2012. If the Raton field were to become impaired in a future quarter, the Company would recognize noncash, pretax impairment charges in that period that could range from $1.5 billion to $1.8 billion.

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 risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's outlook for commodity prices and (iv) increases or decreases in production and capital costs associated with these fields.

See Note O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about impairment of oil and gas properties and continuing impairment risks.

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, 2012 and 2011 (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Geological and geophysical	$	14,288	$	12,380	$	56,672	$	36,979
Exploratory dry holes	1,564		124		29,851		628
Leasehold abandonments and other	10,800		1,517		22,391		5,202
	$	26,652	$	14,021	$	108,914	$	42,809

The Company's geological and geophysical costs increased by $1.9 million and $19.7 million during the three and nine months ended September 30, 2012, as compared to the same respective periods in 2011, primarily as a result of increased seismic and seismic interpretation expenditures supportive of drilling activities in the Spraberry field. The Company's exploratory dry holes increased by $1.4 million and $29.2 million during the three and nine months ended September 30, 2012, as compared to the same respective periods in 2011, primarily due to dry hole provisions of $721 thousand and $20.9 million, respectively, related

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to an unsuccessful exploration well in Alaska that was drilled during the first quarter of 2012, and first quarter 2012 dry hole provisions in the South Texas Austin Chalk field and Mid-Continent area. The Company's leasehold abandonments and other expense increased by $9.3 million and $17.2 million during the three and nine months ended September 30, 2012, as compared to the same respective periods in 2011, primarily due to increases in leasehold abandonments in dry gas areas.

During the nine months ended September 30, 2012, the Company drilled and evaluated 163 exploration/extension wells, 157 of which were successfully completed as discoveries. During the same period in 2011, the Company drilled and evaluated 116 exploration/extension wells, all of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and nine months ended September 30, 2012 was $62.6 million and $180.6 million, respectively, as compared to $49.6 million and $137.9 million during the same respective periods in 2011. The increases in general and administrative expense for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, are primarily due to increases in compensation expense related to staffing increases in support of the Company's capital expansion and integrated services initiatives.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.4 million and $7.0 million for the three and nine months ended September 30, 2012, respectively, as compared to $2.0 million and $5.9 million during the same respective periods in 2011. 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 $54.4 million and $150.3 million for the three and nine months ended September 30, 2012, respectively, as compared to $45.6 million and $135.8 million during the same respective periods in 2011. The weighted average interest rate on the Company's indebtedness for the three and nine months ended September 30, 2012, including the effects of capitalized interest, was 6.3 percent and 6.6 percent, as compared to 7.2 percent for each of the same respective periods in 2011. Interest expense increased by $8.8 million and $14.5 million during the three and nine months ended September 30, 2012, respectively, as compared to the same periods in 2011, primarily due to increases of $7.3 million and $9.1 million, respectively, in interest on credit facility and senior note borrowings (due to increases in average outstanding borrowings), increases of $581 thousand and $1.6 million, respectively, in amortization of debt issuance costs and decreases of $1.0 million and $1.9 million, respectively, in capitalized interest.

Other expense. Other expense for the three and nine months ended September 30, 2012 was $31.9 million and $86.0 million, respectively, as compared to $17.1 million and $47.0 million for the same respective periods in 2011. The $14.8 million increase in other expense for the three months ended September 30, 2012, as compared to the same period in 2011, is primarily attributable to $8.1 million of idle drilling rig charges and $6.8 million of contract rig termination fees incurred during the third quarter of 2012. The $39.0 million increase in other expense for the nine months ended September 30, 2012, as compared to the same period in 2011, is primarily attributable to $8.3 million of idle drilling rig charges, $15.8 million in rig contract termination fees, an $11.3 million increase in unused gas transportation commitment charges and a $3.8 million increase in inventory valuation charges. See Note N of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision. The Company recorded income tax provisions from continuing operations of $8.4 million and $248.5 million for the three and nine months ended September 30, 2012, as compared to income tax provisions of $182.7 million and $278.7 million for the same respective periods in 2011. The Company's effective tax rates, excluding net income attributable to noncontrolling interests, for the three and nine months ended September 30, 2012 were (119) percent and 38 percent, respectively, as compared to the Company's combined United States federal and state statutory rate of approximately 37 percent. The effective tax rate for the three months ended September 30, 2012, as compared to the same period of the prior year, is primarily due to the impact of non-deductible items and adjustments to state taxes on a pretax loss, excluding net income attributable to noncontrolling interests, of $7.0 million for the three months ended September 30, 2012, as compared to similar adjustments on pretax income, excluding net income attributable to noncontrolling interests, of $533.9 million for the three months ended September 30, 2011.

See Note F 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 income from discontinued operations, net of tax, of $34.7 million for the three months ended September 30, 2012 and a loss of $240.5 million for the nine months ended September 30, 2012 as compared to income from discontinued operations, net of tax, of $330 thousand and $410.6 million for the three and nine months ended September 30, 2011, respectively.

During the third quarter of 2012, the Company committed to a plan to divest of its Barnett Shale field net assets. The Company is currently targeting to close the sale during the first quarter of 2013; however, no assurance can be provided that the Company will be successful in attracting a purchaser or that a purchaser will offer an acquisition price that is acceptable to the Company. The Company has classified its (i) Barnett Shale assets and liabilities as discontinued operations held for sale in the

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accompanying consolidated balance sheet as of September 30, 2012 and (ii) Barnett Shale results of operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

In August 2012 the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal post-closing adjustments. The sale resulted in a pretax gain of $28.6 million.

During February 2011, the Company completed the sale of 100 percent of the Company's share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $802.5 million, resulting in a pretax gain of $645.2 million.

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, 2012 was $2.5 million and $39.7 million, respectively, as compared to $34.1 million and $49.5 million for the same respective periods of 2011. The $31.6 million and $9.8 million decreases in income attributable to noncontrolling interests for the three and nine months ended September 30, 2012, as compared to the same respective periods in 2011, are primarily due to fluctuations in Pioneer Southwest's mark-to-market derivative gains and losses.

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, proceeds from the disposition of nonstrategic assets, joint ventures or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2012 is focused on oil- and liquids-rich-gas drilling activities with total expenditures of $3.0 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), consisting of $2.5 billion for drilling operations and $500 million for vertical integration and infrastructure facilities additions, including the April 2012 acquisition of Premier Silica for $297.0 million. Based on results for the nine months ended September 30, 2012 and management's commodity price outlook, the Company expects its cash flows from operating activities, proceeds from asset divestitures and availability under its credit facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2012.

Investing activities. Investing activities used $2.5 billion of cash during the nine months ended September 30, 2012 as compared to $854.9 million of cash used in investing activities during the nine months ended September 30, 2011. The $1.7 billion increase in cash used in investing activities for the nine months ending September 30, 2012, as compared to the nine months ended September 30, 2011, is primarily due to (i) a $727.2 million decrease in proceeds from disposition of assets (primarily attributable to the 2011 sale of Pioneer Tunisia, partially offset by proceeds from the sales of Pioneer South Africa and a partial interest in an Eagle Ford Shale unproved leasehold during 2012), (ii) a $753.7 million increase in additions to oil and gas properties and (iii) the $297.0 million acquisition of Premier Silica, partially offset by (iv) an $89.6 million decrease in investments in EFS Midstream and (v) a $26.9 million decrease in additions to other assets and other property and equipment. During the nine months ended September 30, 2012, the Company's investing activities were funded by net cash provided by operating activities, cash on hand and borrowings under long term debt.

Dividends/distributions. During February and August of both 2012 and 2011, the Company's board of directors ("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 2012, April 2012 and July 2012, the Pioneer Southwest board of directors (the "Pioneer Southwest Board") declared a quarterly distribution of $0.51, $0.52 and $0.52 per limited partner unit, respectively, compared to the quarterly distributions of $0.50, $0.51 and $0.51 per limited partner unit declared in January, April and July 2011, respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $26.3 million and $19.1 million during the nine months ended September 30, 2012 and 2011, respectively. During October 2012, the Pioneer Southwest Board declared a quarterly distribution of $0.52 per limited partner unit for unitholders of record on November 2, 2012, payable November 9, 2012. Future distributions by Pioneer Southwest are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the distribution amount based on Pioneer Southwest's liquidity and capital resources at the time.

Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportation and other purchase commitments, VPP obligations, EFS Midstream capital funding commitments and other liabilities. From time-to-time, the Company enters into

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arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of September 30, 2012, the material off-balance sheet arrangements and transactions that the Company has entered into included (i) operating lease agreements, (ii) drilling, gathering, treating, fractionation and transportation commitments, (iii) open purchase commitments, (iv) a VPP obligation (to physically deliver volumes and pay related lease operating expenses and capital costs) 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. 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, 2011, the material changes in the Company's contractual obligations include (i) a $1.0 billion increase in the principal balances of outstanding long-term debt, (ii) a $31.5 million decrease in the Company's VPP obligations and (iii) an $89.9 million decrease in the Company's derivative net assets. During 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility to fund infrastructure investments that are in excess of operating cash flow; accordingly, future capital needs of EFS Midstream are expected to be funded from its operating cash flow and the borrowings under its credit facility.

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, 2012, these contracts represented net assets of $284.2 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, 2012. See Note H 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 net cash provided by operating activities, proceeds from sales of nonstrategic assets and proceeds from financing activities (principally borrowings under the Company's credit facility). 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 asset sales or joint ventures.

In early August 2012, the Company announced plans to pursue a joint venture partner to accelerate the development of the horizontal Wolfcamp Shale in the southern 200,000 acres of the Company's total prospective acreage position. The Company plans to offer a 33 percent to 50 percent working interest in the southern acreage. No assurance can be provided that the Company will be successful in attracting a joint venture partner or that a joint venture partner will offer an acquisition price that is acceptable to the Company.

In early September 2012, the Company announced plans to divest of its properties in the Barnett Shale field. The Company has opened a data room and is targeting completing the transaction during the first quarter of 2013. No assurance can be provided that the Company will be successful in attracting a purchaser or that a purchaser will offer an acquisition price that is acceptable to the Company.

Operating activities. Net cash provided by operating activities during the nine months ended September 30, 2012 was $1.4 billion as compared to $1.0 billion during the same period of 2011. The increase in net cash provided by operating activities for the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011, is primarily due to increases in oil and gas sales and realized derivative gains.

Asset divestitures. In August 2012 the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal post-closing adjustments. The sale resulted in a pretax gain of $28.6 million.

During the first quarter of 2012, the Company completed a sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale to unaffiliated third parties for proceeds of $54.7 million. Associated therewith, the Company recorded a pretax gain of $42.6 million.

During February 2011, the Company completed the sale of 100 percent of the Company's share holdings in Pioneer Tunisia to an unaffiliated third party for net cash proceeds of $802.5 million, resulting in a pretax gain of $645.2 million. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information regarding the Company's discontinued operations and divestitures.

Financing activities. Net cash provided by financing activities during the nine months ended September 30, 2012 was $955.0 million as compared to net cash used in financing activities of $75.8 million during the nine months ended 2011. The $1.0 billion increase in cash provided by financing activities during the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011, is primarily due to an increase in net borrowings on long-term debt.

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During March 2012, Pioneer Southwest entered into the Pioneer Southwest Credit Facility with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility provides for aggregate loan commitments of $300.0 million. As of September 30, 2012, there were $88.0 million of outstanding borrowings under the Pioneer Southwest Credit Facility. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information about the available loans, interest rates and debt covenant terms of the Company's credit facility and the Pioneer Southwest Credit Facility.

Effective April 1, 2012, the Company's 2.875% Convertible Senior Notes became convertible at the option of the holders for the quarter ended June 30, 2012. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $15 thousand principal amount of the notes for conversion. The Company paid certain of the tendering holders a total of $15 thousand cash and issued to the tendering holders 55 shares of the Company's common stock in May 2012 in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

During September 2012, the Company's stock price performance met the average price threshold that causes the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders for the three months ending December 31, 2012. The Company's 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock price or other conditions.

On January 15, 2013, the 2.875% Convertible Senior Notes become redeemable at the option of the Company and on January 15, 2013, January 15, 2018, January 15, 2023, January 15, 2028 and January 15, 2033 the holders may require the Company to repurchase the notes for cash. The Company has the intent and ability to fund cash payments that may be required upon the conversion, redemption or repurchase of the 2.875% Convertible Senior Notes with borrowing capacity under its credit facility. Accordingly, the 2.875% Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

The Company currently anticipates that it will redeem the 2.875% Convertible Senior Notes on or about January 15, 2013. The decision to exercise the redemption option will be dependent on market and other conditions and the Company may choose not to redeem the 2.875% Convertible Senior Notes or delay its decision to redeem the 2.875% Convertible Senior Notes beyond January 15, 2013. If the Company exercises its redemption option, the 2.875% Convertible Senior Notes will automatically become convertible during the period of time between when the Company gives notice of its intent to redeem the 2.875% Convertible Senior Notes and the date on which the 2.875% Convertible Senior Notes are actually redeemed. If the Company exercises its redemption option and the conversion price for the 2.875% Convertible Senior Notes is in the money during the conversion period, the Company expects that the note holders will exercise their right to convert the 2.875% Convertible Senior Notes rather than allow their securities to be redeemed by the Company. If the 2.875% Convertible Senior Notes had been converted on September 30, 2012, the note holders would have received $479.9 million of cash and approximately 3.3 million shares of the Company's common stock, which was valued at $345.8 million on September 30, 2012.

During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds to reduce outstanding borrowings under its credit facility.

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, 2012, the Company had $360.0 million in outstanding borrowings under its credit facility and was in compliance with all of its debt covenants. After adjusting for $2.2 million of undrawn and outstanding letters of credit under its credit facility, the Company had $887.8 million of unused borrowing capacity as of September 30, 2012. 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 asset sales or joint ventures. 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 asset sales and/or joint ventures and available capacity under the Company's credit facility will be adequate to fund 2012 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

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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. In November 2011, the Company achieved an investment grade rating with one of the credit rating agencies and in May 2012 received an investment grade rating from a second credit rating agency.

Book capitalization and current ratio. The Company's net book capitalization at September 30, 2012 was $9.0 billion, consisting of $333.9 million of cash and cash equivalents, debt of $3.6 billion and equity of $5.8 billion. The Company's net debt to net book capitalization was 36 percent and 26 percent at September 30, 2012 and December 31, 2011, respectively. The Company's ratio of current assets to current liabilities was 1.59 to 1.00 at September 30, 2012 as compared to 1.31 to 1.00 at December 31, 2011.

New accounting pronouncements. There are no new accounting pronouncements that are likely of having a material effect on the Company's consolidated financial statements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2011. 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, 2011.

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 of 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, 2012:



	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2011	$	389,753		$	(15,654	)	$	374,099
Changes in contract fair value (a)	267,806			(24,238		)	243,568
Contract maturities	(215,262		)	—			(215,262		)
Contract terminations	(146,593		)	28,358			(118,235		)
Fair value of contracts outstanding as of September 30, 2012	$	295,704		$	(11,534	)	$	284,170

____________________


(a)	At inception, new derivative contracts entered into by the Company had no intrinsic value.

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, 2012 and that are sensitive to changes in interest rates. For debt obligations, the table presents 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, 2012. 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 October 31, 2012.



	Three Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at September 30.
	2012			2013			2014			2015			2016			Thereafter			Total		2012
	($ in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	479,908		$	—		$	—		$	455,385		$	2,234,600		$	3,169,893	$	(3,982,769	)
Weighted average interest rate	6.02		%	5.41		%	5.26		%	6.78		%	6.88		%	5.89		%
Variable rate principal maturities:
Pioneer Natural Resources credit facility	$	—		$	—		$	—		$	—		$	360,000		$	—		$	360,000	$	(378,731	)
Weighted average interest rate	2.07		%	2.10		%	2.25		%	2.55		%	2.78		%	—
Pioneer Southwest credit facility	$	—		$	—		$	—		$	—		$	—		$	88,000		$	88,000	$	(87,588	)
Weighted average interest rate	1.94		%	1.98		%	2.13		%	2.42		%	2.66		%	2.89		%
Interest Rate Swaps:
Notional debt amount	$	—		$	—		$	—		$	250,000		$	—		$	—		$	250,000	$	(11,534	)
Fixed rate payable (%)	—		%	—		%	—		%	3.21		%	—		%	—		%
Variable rate receivable (%)	—		%	—		%	—		%	2.76		%	—		%	—		%

____________________


(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, 2012. 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 H 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,
	2012			2013			2014		2015		2012
											(in thousands)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (a)	53,110			54,029			60,000		26,000		$	100,822
Weighted average ceiling price per BBL	$	118.85		$	119.60		$	117.06	$	104.45
Weighted average floor price per BBL	$	85.09		$	89.71		$	92.67	$	95.00
Weighted average short put price per BBL	$	69.44		$	73.74		$	76.58	$	80.00
Collar contracts	2,000			—			—		—		$	584
Weighted average ceiling price per BBL	$	127.00		$	—		$	—	$	—
Weighted average floor price per BBL	$	90.00		$	—		$	—	$	—
Swap contracts (a)	11,000			20,000			—		—		$	22,424
Weighted average fixed price per BBL	$	89.34		$	97.27		$	—	$	—
Average forward NYMEX oil prices (b)	$	86.24		$	88.71		$	88.50	$	86.69
Rollfactor swap contracts	—			6,000			—		—		$	903
Weighted average fixed price per BBL (c)	$	—		$	0.43		$	—	$	—
Average forward rollfactor prices (b)	$	—		$	(0.27	)	$	—	$	—
Basis swap contracts	20,000			—			—		—		$	617
Weighted average fixed price per BBL	$	(1.15	)	$	—		$	—	$	—
Average forward basis differential prices (d)	$	(4.30	)	$	—		$	—	$	—
NGL Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts	3,000			1,000			1,000		—		$	6,387
Weighted average ceiling price per BBL	$	79.99		$	112.00		$	109.50	$	—
Weighted average floor price per BBL	$	67.70		$	95.00		$	95.00	$	—
Weighted average short put price per BBL	$	55.76		$	80.00		$	80.00	$	—
Swap contracts (e)	2,750			—			—		—		$	(968	)
Weighted average fixed price per BBL	$	67.85		$	—		$	—	$	—
Average forward NGL prices (f)	$	64.27		$	86.20		$	83.76	$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts (g)	—			—			—		155,000		$	(11,429	)
Weighted average ceiling price per MMBTU	$	—		$	—		$	—	$	4.97
Weighted average floor price per MMBTU	$	—		$	—		$	—	$	4.00
Weighted average short put price per MMBTU	$	—		$	—		$	—	$	3.00
Collar contracts	65,000			150,000			—		—		$	76,590
Weighted average ceiling price per MMBTU	$	6.60		$	6.25		$	—	$	—
Weighted average floor price per MMBTU	$	5.00		$	5.00		$	—	$	—
Swap contracts (g)	275,000			112,500			105,000		—		$	108,198
Weighted average fixed price per MMBTU	$	4.97		$	5.62		$	4.03	$	—
Average forward NYMEX gas prices (b)	$	3.69		$	3.90		$	4.22	$	4.40
Basis swap contracts	136,000			142,500			—		—		$	(8,315	)
Weighted average fixed price per MMBTU	$	(0.34	)	$	(0.22	)	$	—	$	—
Average forward basis differential prices (h)	$	(0.10	)	$	(0.11	)	$	—	$	—

___________________


(a)	Subsequent to September 30, 2012, the Company converted NYMEX swap contracts for 17,000 BBLs per day of 2013 production with a price of $100.14 per BBL into collar contracts with short puts for 17,000 BBLs per day of 2013 production with a ceiling price of $120.29 per BBL, a floor price of $100.41 per BBL and a short put price of $75.99 per BBL.

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PIONEER NATURAL RESOURCES COMPANY


(b)	The average forward NYMEX oil and gas prices are based on October 31, 2012 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 October 31, 2012 market quotes for basis differentials between Midland WTI and Cushing WTI.


(e)	Subsequent to September 30, 2012, the Company converted 2013 collar contracts with short puts for 1,000 BBLs per day into collar contracts with short puts for 1,064 BBLs per day of 2013 natural gasoline production with a ceiling price of $105.28 per BBL, a floor price of $89.30 per BBL and a short put price of $75.20 per BBL.


(f)	Forward component NGL prices are derived from active-market NGL component price quotes as of October 31, 2012.


(g)	Subsequent to September 30, 2012, the Company entered into additional (i) 2013 swap contracts for 50,000 MMBTU per day priced at $4.01 per MMBTU and (ii) 2015 collar contracts with short puts for 70,000 MMBTU per day with a ceiling price of $5.35 per MMBTU, a floor price of $4.00 per MMBTU and a short put price of $3.00 per MMBTU.


(h)	The average forward basis differential prices are based on October 31, 2012 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

Marketing and basis transfer derivative instruments and price sensitivity. The Company manages commodity price risk and mitigates firm transportation commitment costs with derivative contracts. Periodically, the Company enters into gas buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into gas index swaps to mitigate price risk. From time to time, the Company also enters into long and short gas swap contracts that transfer gas basis risk from one sales index to another sales index.

The following table provides information about the Company's marketing and basis transfer derivative financial instruments that were sensitive to changes in gas prices as of September 30, 2012:



	Three Months Ending December 31,			Year Ending December 31,		Asset Fair Value at September 30,
	2012			2013		2012
						(in thousands)
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	43,370			9,863		$	(110	)
Price differential ($/MMBTU)	$	0.24		0.25
Average forward basis differential prices (a)	$	0.27		$	0.26
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	1,685			—		$	1
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12		—
Index swap volume	(1,685		)	—
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)	—
Average forward basis differential prices (a)	$	0.24		$	—

____________________


(a)	The average forward basis differential prices are based on October 31, 2012 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, 2012 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

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PIONEER NATURAL RESOURCES COMPANY

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the information set forth in this Report, you should carefully consider the risks discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2011, 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 March 31, 2012, 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 Item 1A of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, there has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

The Company is growing production in areas of high industry activity, which may impact its ability to obtain the personnel, equipment, services, resources and facilities access needed to complete its development activities as planned or result in increased costs.

The Company's operations and drilling activity are concentrated in areas in which industry activity has increased rapidly, particularly in the Spraberry field in West Texas and the Eagle Ford Shale play in South Texas. As a result, demand for personnel, equipment, services and resources, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items. In addition, hydraulic fracturing and other operations require significant quantities of water, which supply may be impacted by drought conditions. Any delay or inability to secure the personnel, equipment, services, resources and facilities access necessary for the Company to complete its planned development activities, including the result of any changes in laws or regulations applicable to the Company's operations relating to water usage, could result in oil and gas production volumes being below the Company's forecasted volumes. In addition, any such negative impact on production volumes, or significant increases in costs, could have a material adverse effect on the Company's profitability.

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, 2012:



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 2012	—	$	—	—
August 2012	3,638	$	98.86	—
September 2012	—	$	—	—
Total	3,638	$	98.86	—	$	—

____________________


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

Item 4. Mine Safety Disclosures

The Company's sand mines are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Quarterly Report filed on Form 10-Q.

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PIONEER NATURAL RESOURCES COMPANY

Item 6. Exhibits

Exhibits



Exhibit Number		Description

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 5, 2012	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy
		Executive Vice President and Chief Financial Officer

Date: November 5, 2012	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

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.