10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2009

or

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

For the transition period from              to             

Commission File Number: 1-13245

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

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

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

(972) 444-9001

(Registrant’s telephone number, including area code)

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  x    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  x    No  ¨

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

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Number of shares of Common Stock outstanding as of November 2, 2009 115,320,979

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, 2009 and December 31, 2008	5
	Consolidated Statements of Operations for the three and nine months ended September 30, 2009 and 2008	7
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2009	8
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008	9
	Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2009 and 2008	10
	Notes to Consolidated Financial Statements	11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	62
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	63
Item 6.	Exhibits	64
Signatures		65
Exhibit Index		66

2

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,” “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 with third parties on mutually acceptable terms, international operations and associated international political and economic instability, litigation, the costs and results of drilling and operations, access to and availability of drilling equipment and transportation, processing and refining facilities, Pioneer’s ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer’s credit facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, 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 Securities and Exchange Commission. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse impact 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 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” 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, 2008 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. The Company undertakes no duty to publicly update these statements except as required by law.

3

PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

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

• “Bbl” means a standard barrel containing 42 United States gallons.

• “Bcf “ means one billion cubic feet.

• “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 6.0 Mcf of gas to 1.0 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.

• “CBM” means coal bed methane.

• “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.

• “MBbl” means one thousand Bbls.

• “MBOE” means one thousand BOEs.

• “Mcf” means one thousand cubic feet and is a measure of natural gas volume.

• “MMBbl” means one million Bbls.

• “MMBOE” means one million BOEs.

• “MMBtu” means one million Btus.

• “MMcf” means one million cubic feet.

• “MMcfpd” means one million cubic feet per day.

• “Mont Belvieu–posted-price” 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 Mont Belvieu, Texas.

• “NGL” means natural gas liquid.

• “NYMEX” means the New York Mercantile Exchange.

• “NYSE” means the New York Stock 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 estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (C) crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources.

• “SEC” means the United States Securities and Exchange Commission.

• “Standardized Measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs in effect at the specified date and a ten percent discount rate.

• “U.S.” means United States.

• “VPP” means volumetric production payment.

• With respect to information on the working interest in wells, drilling locations and acreage, “net” wells, drilling locations and acres are determined by multiplying “gross” wells, drilling locations and acres by the Company’s working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.

• Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.

4

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)

(Unaudited)

	September 30, 2009			December 31, 2008 (a)
ASSETS
Current assets:
Cash and cash equivalents	$	55,615		$	48,337
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,437 and $22,464 as of September 30, 2009 and December 31, 2008, respectively		136,893			206,794
Due from affiliates		624			759
Income taxes receivable		16,290			60,573
Inventories		145,976			76,901
Prepaid expenses		12,553			12,464
Deferred income taxes		3,417			6,510
Other current assets:
Derivatives		41,280			59,622
Other, net of allowance for doubtful accounts of $5,566 and $5,491 as of September 30, 2009 and December 31, 2008, respectively		10,314			14,951
Total current assets		422,962			486,911
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		10,170,341			10,167,220
Unproved properties		212,818			204,183
Accumulated depletion, depreciation and amortization		(2,819,643	)		(2,511,401	)
Total property, plant and equipment		7,563,516			7,860,002
Deferred income taxes		2,572			553
Goodwill		309,371			310,563
Other property and equipment, net		154,956			161,266
Other assets:
Derivatives		35,772			72,594
Other, net of allowance for doubtful accounts of $7,172 and $4,410 as of September 30, 2009 and December 31, 2008, respectively		191,919			269,896
	$	8,681,068		$	9,161,785

(a) Retrospectively adjusted as described in Note B.

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.

5

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)

(Unaudited)

	September 30, 2009			December 31, 2008 (a)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	201,768		$	322,688
Due to affiliates		18,562			34,284
Interest payable		28,481			43,247
Income taxes payable		12,745			3,618
Deferred income taxes		307			—
Discontinued operations held for sale		1,802			—
Other current liabilities:
Derivatives		91,967			49,561
Deferred revenue		104,743			147,905
Other		57,445			93,694
Total current liabilities		517,820			694,997
Long-term debt		2,867,298			2,899,241
Derivatives		65,664			20,584
Deferred income taxes		1,408,481			1,501,459
Deferred revenue		109,497			177,236
Other liabilities		178,076			187,409
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 125,191,035 and 124,566,963 shares issued at September 30, 2009 and December 31, 2008, respectively		1,252			1,246
Additional paid-in capital		2,935,897			2,909,735
Treasury stock, at cost: 10,863,513 and 10,020,502 shares at September 30, 2009 and December 31, 2008, respectively		(416,566	)		(411,659	)
Retained earnings		861,922			988,786
Accumulated other comprehensive income - deferred hedge gains, net of tax		64,851			88,788
Total stockholders’ equity attributable to common stockholders		3,447,356			3,576,896
Noncontrolling interests in consolidating subsidiaries		86,876			103,963
Total stockholders’ equity		3,534,232			3,680,859
Commitments and contingencies
	$	8,681,068		$	9,161,785

(a) Retrospectively adjusted as described in Note B.

The financial information included as of September 30, 2009 has been prepared by management

without audit by independent registered public accountants.

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

6

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008 (a)			2009			2008 (a)
Revenues and other income:
Oil and gas	$	409,969		$	600,413		$	1,148,512		$	1,777,579
Interest and other		503			2,285			99,761			33,697
Gain (loss) on disposition of assets, net		(385	)		190			(447	)		4,768
		410,087			602,888			1,247,826			1,816,044
Costs and expenses:
Oil and gas production		90,394			107,159			285,617			297,299
Production and ad valorem taxes		28,089			46,124			79,503			129,670
Depletion, depreciation and amortization		162,605			121,265			509,422			338,153
Impairment of oil and gas properties		—			89,753			21,091			89,753
Exploration and abandonments		25,073			109,420			77,861			172,714
General and administrative		34,799			31,622			102,728			103,739
Accretion of discount on asset retirement obligations		2,754			1,981			8,259			5,885
Interest		43,438			41,176			128,051			123,124
Hurricane activity, net		1,830			541			18,280			2,400
Derivative losses, net		15,222			3,858			85,583			1,451
Other		21,363			33,964			89,467			54,153
		425,567			586,863			1,405,862			1,318,341
Income (loss) from continuing operations before income taxes		(15,480	)		16,025			(158,036	)		497,703
Income tax benefit (provision)		5,206			(13,165	)		47,671			(217,615	)
Income (loss) from continuing operations		(10,274	)		2,860			(110,365	)		280,088
Income from discontinued operations, net of tax		12,107			327			13,868			14,718
Net income (loss)	$	1,833			3,187			(96,497	)		294,806
Net income attributable to the noncontrolling interests		(8,998	)		(8,422	)		(12,269	)		(15,388	)
Net income (loss) attributable to common stockholders	$	(7,165	)	$	(5,235	)	$	(108,766	)	$	279,418
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.17	)	$	(0.04	)	$	(1.07	)	$	2.22
Income from discontinued operations attributable to common stockholders		0.11			—			0.12			0.12
Net income (loss) attributable to common stockholders	$	(0.06	)	$	(0.04	)	$	(0.95	)	$	2.34
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.17	)	$	(0.04	)	$	(1.07	)	$	2.20
Income from discontinued operations attributable to common stockholders		0.11			—			0.12			0.12
Net income (loss) attributable to common stockholders	$	(0.06	)	$	(0.04	)	$	(0.95	)	$	2.32
Weighted average shares outstanding:
Basic		114,123			118,110			114,118			118,136
Diluted		114,123			118,110			114,118			118,765
Dividends declared per share	$	0.04		$	0.16		$	0.08		$	0.30
Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	(19,272	)	$	(5,562	)	$	(122,634	)	$	264,700
Discontinued operations		12,107			327			13,868			14,718
Net income (loss)	$	(7,165	)	$	(5,235	)	$	(108,766	)	$	279,418

(a) Retrospectively adjusted as described in Note B.

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

7

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in thousands, except dividends per share)

(Unaudited)

			Stockholders’ Equity Attributable To Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interests			Total Stockholders’ Equity
Balance as of December 31, 2008 (a)	114,546		$	1,246	$	2,909,735		$	(411,659	)	$	988,786		$	88,788		$	103,963		$	3,680,859
Dividends declared ($0.08 per share)	—			—		—			—			(9,405	)		—			—			(9,405	)
Exercise of long-term incentive plan stock options and employee stock purchases	431			—		—			16,648			(8,693	)		—			—			7,955
Purchase of treasury stock	(1,273	)		—		—			(21,555	)		—			—			—			(21,555	)
Purchase of subsidiary noncontrolling units																		(258	)		(258	)
Tax provision related to stock-based compensation	—			—		(3,583	)		—			—			—			—			(3,583	)
Compensation costs:
Vested compensation awards, net	624			6		(6	)		—			—			—			—			—
Compensation costs included in net income (loss)	—			—		29,751			—			—			—			164			29,915
Cash contributions of noncontrolling interests	—			—		—			—			—			—			150			150
Cash distributions to noncontrolling interests	—			—		—			—			—			—			(15,042	)		(15,042	)
Net income (loss)	—			—		—			—			(108,766	)		—			12,269			(96,497	)
Other comprehensive loss:
Deferred hedging activity, net of tax:
Hedge fair value changes, net	—			—		—			—			—			10,477			3,692			14,169
Net hedge gains included in continuing operations	—			—		—			—			—			(34,414	)		(18,062	)		(52,476	)
Balance as of September 30, 2009	114,328		$	1,252	$	2,935,897		$	(416,566	)	$	861,922		$	64,851		$	86,876		$	3,534,232

(a) Retrospectively adjusted as described in Note B.

The financial information included herein has been prepared by management without audit by independent registered public accountants.

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

8

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Nine Months Ended September 30,
	2009			2008 (a)
Cash flows from operating activities:
Net income (loss)	$	(96,497	)	$	294,806
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		509,422			338,153
Impairment of oil and gas properties		21,091			89,753
Exploration expenses, including dry holes		40,699			93,996
Hurricane activity, net		16,200			—
Deferred income taxes		(67,397	)		160,346
(Gain) loss on disposition of assets, net		447			(4,768	)
Accretion of discount on asset retirement obligations		8,259			5,885
Discontinued operations		(5,373	)		24,609
Interest expense		20,694			21,252
Derivative related activity		48,305			31,118
Amortization of stock-based compensation		29,319			25,571
Amortization of deferred revenue		(110,901	)		(118,644	)
Other noncash items		30,664			30,495
Change in operating assets and liabilities
Accounts receivable, net		71,074			(39,039	)
Income taxes receivable		44,762			(9,522	)
Inventories		(52,069	)		(54,990	)
Prepaid expenses		(6,900	)		(7,152	)
Other current assets		98,532			(2,561	)
Accounts payable		(94,238	)		15,364
Interest payable		(14,766	)		(12,724	)
Income taxes payable		9,127			11,528
Other current liabilities		(89,629	)		(76,972	)
Net cash provided by operating activities		410,825			816,504
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold		24,247			143,352
Additions to oil and gas properties		(319,928	)		(996,721	)
Additions to other assets and other property and equipment, net		(17,310	)		(31,350	)
Net cash used in investing activities		(312,991	)		(884,719	)
Cash flows from financing activities:
Borrowings under long-term debt		386,269			794,998
Principal payments on long-term debt		(434,269	)		(732,775	)
Distributions to noncontrolling interests, net		(14,892	)		(2,941	)
Proceeds from issuance of partnership common units, net of issuance costs		—			165,978
Borrowings (payments) of other liabilities		(1,069	)		4,686
Exercise of long-term incentive plan stock options and employee stock purchase plan		7,955			8,008
Purchases of treasury stock and subsidiary noncontrolling units		(21,813	)		(86,201	)
Excess tax (provisions) benefits from share-based payment arrangements		(3,583	)		381
Payment of financing fees		(4,475	)		(12,377	)
Dividends paid		(4,679	)		(16,896	)
Net cash provided by (used in) financing activities		(90,556	)		122,861
Net increase in cash and cash equivalents		7,278			54,646
Cash and cash equivalents, beginning of period		48,337			12,171
Cash and cash equivalents, end of period	$	55,615		$	66,817

(a) Retrospectively adjusted as described in Note B.

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

9

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008 (a)			2009			2008 (a)
Net income (loss)	$	1,833		$	3,187		$	(96,497	)	$	294,806
Other comprehensive income (loss):
Hedge activity:
Hedge fair value changes, net		—			580,567			22,490			(168,801	)
Net hedge (gains) losses included in continuing operations		(25,887	)		145,106			(103,039	)		389,016
Income tax provision (benefit)		7,272			(269,973	)		42,242			(82,322	)
Other comprehensive income (loss)		(18,615	)		455,700			(38,307	)		137,893
Comprehensive income (loss)		(16,782	)		458,887			(134,804	)		432,699
Comprehensive (income) loss attributable to noncontrolling interest		(3,417	)		(40,097	)		853			(28,031	)
Comprehensive income (loss) attributable to common stockholders	$	(20,199	)	$	418,790		$	(133,951	)	$	404,668

(a) Retrospectively adjusted as described in Note B.

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.

10

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

NOTE A.    Organization and Nature of Operations

Pioneer 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 continuing operations in the United States, South Africa and Tunisia.

NOTE B.    Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2009 and for the three and nine months ended September 30, 2009 and 2008 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 GAAP have been condensed or omitted in this Report pursuant to the rules and regulations of the SEC. These consolidated financial statements should be read in connection 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, 2008.

Discontinued operations. During June and August 2009, the Company sold its Mississippi assets and substantially all of its shelf properties in the Gulf of Mexico, respectively. The Company has reflected the results of operations of both of these asset groups as discontinued operations, rather than as components of continuing operations. In April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries, respectively. During the three and nine months ended September 30, 2008, the Company continued to realize certain net costs and expenses associated with these divestitures. See Note R for additional information regarding discontinued operations.

Allowances for doubtful accounts. As of September 30, 2009 and December 31, 2008, the Company’s allowances for doubtful accounts totaled $14.2 million and $32.4 million, respectively. The Company establishes allowances for doubtful accounts equal to the estimable portions of accounts and notes receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company’s consolidated balance sheets and as charges to other expense in the Company’s consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.

Changes in the Company’s allowance for doubtful accounts during the three and nine months ended September 30, 2009 are summarized in the following table:

	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
	(in thousands)
Beginning allowance for doubtful accounts balance	$	12,205		$	32,365
Amount recorded in other expense for bad debt expense		1,985			1,241
Write-offs of uncollectible accounts (a)		(15	)		(19,431	)
Ending allowance for doubtful accounts balance	$	14,175		$	14,175

(a) Write-offs of uncollectible accounts for the nine months ended September 30, 2009 are primarily comprised of the allowance for doubtful accounts established to reduce the carrying value of the Company’s pre-petition claims receivable from SemGroup, L.P. (“SemGroup”), which filed bankruptcy during 2008. The Company sold all of its pre-petition SemGroup claims during April 2009 for approximately $10.1 million.

Inventories. Inventories consisted of $212.3 million and $158.7 million of materials and supplies and $4.0 million and $8.4 million of commodities as of September 30, 2009 and December 31, 2008, respectively. The Company’s materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as

11

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to charge to the joint accounts when the inventory is used in joint operations under joint operating agreements to which the Company is a party. Any valuation reserve allowances of materials and supplies inventory are recorded as reductions to the carrying values of the materials and supply inventories in the Company’s consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. As of September 30, 2009 and December 31, 2008, the Company’s materials and supplies inventory was net of $5.9 million and $4.7 million, respectively, of valuation reserve allowances. The Company estimated that approximately $70.4 million and $90.2 million of its September 30, 2009 and December 31, 2008 materials and supplies inventories, respectively, would not be utilized within one year based on current drilling plans. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company’s commodities inventories consist of oil and natural gas liquids (“NGLs”) held in storage. Any valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included in the Company’s consolidated balance sheets and as charges to other expense in the consolidated statements of operations. As of December 31, 2008, the Company’s commodities inventories were net of $159 thousand of valuation allowances.

Derivatives and hedging. Prior to December 2008, the Company had elected to designate the majority of its commodity derivative instruments as cash flow hedges. During December 2008, the Company began entering into commodity derivative contracts that were not designated as hedges. Changes in the fair values of non-hedge derivative instruments are recognized as gains or losses in the earnings of the period in which they occur. Effective February 1, 2009, the Company discontinued hedge accounting on all existing hedge contracts. The effective portions of the discontinued deferred hedges as of January 31, 2009 are included in accumulated other comprehensive income – deferred hedge gains, net of tax (“AOCI – Hedging”), in the stockholders’ equity section of the accompanying consolidated balance sheets, and are being reclassified to earnings during the same periods in which the hedged transactions are recognized in the Company’s earnings. For the period from February 1, 2009 through September 30, 2009, the Company recognized, and in the future will recognize, all changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities by commodity, whichever the case may be. 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 credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates are based on an independent market-quoted credit default swap rate curve for the Company’s or the counterparties’ debt plus the United States Treasury Bill yield curve as of September 30, 2009.

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 2009, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment. See Note M for additional information regarding the Company’s impairment assessments. In connection with the August 2009 sale of its Gulf of Mexico shelf properties, the Company reduced its goodwill attributable to the carrying value of those properties by $1.2 million.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 68.3 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties previously owned by the Company in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations, and cash flows of Pioneer Southwest are consolidated with those of the Company.

12

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

In addition to Pioneer Southwest, the Company owns the majority interests in certain other subsidiaries with operations in the United States. Noncontrolling interest in the net assets of consolidated subsidiaries totaled $86.9 million and $104.0 million as of September 30, 2009 and December 31, 2008, respectively. The Company recorded net income attributable to the noncontrolling interests of $9.0 million and $12.3 million for the three and nine months ended September 30, 2009, (principally related to Pioneer Southwest) compared to $8.4 million and $15.4 million for the three and nine months ended September 30, 2008, respectively. See “New accounting pronouncements” and “Reclassifications and retrospective adjustments” for information regarding the Company’s accounting for noncontrolling interests.

Stock-based compensation. For stock-based compensation awards, compensation expense is being recognized in the Company’s financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day’s closing stock price on the date of grant for the fair value of restricted stock awards and (iii) the Monte Carlo simulation method for the fair value of performance unit awards.

For the three and nine month periods ended September 30, 2009, the Company recorded $10.1 million and $29.3 million of stock-based compensation costs for all plans, respectively, as compared to $8.3 million and $25.6 million for the same respective periods of 2008.

In accordance with GAAP, the Company’s issued shares, as reflected in the consolidated balance sheets at September 30, 2009 and December 31, 2008, do not include 987,696 and 1,078,267, respectively, of issued but unvested shares awarded under stock-based compensation plans which have voting rights.

The following table summarizes all stock-based awards, lapses and forfeitures that occurred during the nine months ended September 30, 2009:

	Restricted Stock Shares	Restricted Stock Units	Performance Units	Stock Options
Awards	378,497	1,638,711	189,247	361,021
Lapsed restrictions	452,018	172,054	—	—
Exercises	—	—	—	288,114
Forfeitures	17,050	47,712	—	99,250

As of September 30, 2009, there was approximately $52.5 million of unrecognized compensation expense related to unvested share-based compensation plan awards, restricted stock, restricted stock units, performance unit awards and stock options. This compensation will be recognized over the remaining vesting periods of the awards, which on a weighted average basis is a period of less than three years.

New accounting pronouncements. On June 30, 2009, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS 168”). SFAS 168 creates a new source of authoritative U.S. accounting and reporting standards for nongovernmental entities, known as the FASB “Accounting Standards Codification” (“ASC”). This statement was effective for interim and annual periods ending after September 15, 2009. On September 30, 2009, the Company adopted the provisions of SFAS 168. Hereafter, all new and existing accounting pronouncements will be referred to by their section in the ASC.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measures” (“ASC 820”). ASC 820 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. During February 2008, the FASB issued FASB Staff Position No. 157-2, “FSP FAS 157-2”, which delayed the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities until fiscal years beginning after November 15, 2008, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis at least annually. On January 1, 2009, the Company adopted the remaining provisions of ASC 820, for which delayed adoption was allowed.

13

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“ASC 805”). ASC 805 replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. ASC 805 requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquired entity at the acquisition date, measured at their fair values as of the date that the acquirer achieves control over the business acquired. This includes the measurement of the acquirer’s shares issued in consideration for a business combination, the recognition of contingent consideration, the recognition of pre-acquisition contractual and certain non-contractual gain and loss contingencies, the recognition of capitalized research and development costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. The provisions of ASC 805 also require that restructuring costs resulting from the business combination that the acquirer expects but is not required to incur and costs incurred to effect the acquisition be recognized separate from the business combination. ASC 805 is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. The Company became subject to the provisions of ASC 805 on January 1, 2009.

In December 2007, the FASB issued SFAS 160 (“ASC 810”). ASC 810 amends Accounting Research Bulletin (“ARB”) No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. ASC 810 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, ASC 810 requires consolidated earnings to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. The Company adopted the provisions of ASC 810 on January 1, 2009.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“ASC 815”). ASC 815 changes the disclosure requirements for derivative instruments and hedging activities by requiring entities to provide enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under ASC 815 and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. ASC 815 was adopted by the Company on January 1, 2009. See Note G for disclosures about the Company’s derivative instruments and hedging activities.

In May 2008, the FASB issued FASB Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (“ASC 470”). ASC 470 specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company adopted the provisions of ASC 470 on January 1, 2009. The adoption of ASC 470 increases the annual interest expense that the Company recognizes on its $480 million of 2.875% convertible senior notes due 2038 (“2.875% Convertible Senior Notes”) from an annual yield of 2.875 percent to 6.75 percent, the annual yield equivalent to a nonconvertible debt borrowing at the time of issuance. The adoption of ASC 470 also resulted in the reclassification of the estimated issuance date fair value of the 2.875% Convertible Senior Notes conversion privilege from long-term debt to shareholders’ equity in the accompanying consolidated balance sheets. See “Reclassifications and retrospective adjustments” and Note F for additional information regarding the Company’s adoption of ASC 470.

In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“ASC 260”), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income (loss) allocation in computing basic and diluted earnings per share under the two class method prescribed under SFAS 128, “Earnings per Share”. The Company adopted the provisions of ASC 260 on January 1, 2009 and, in accordance with ASC 260, applied its provisions retrospectively to prior-period earnings per share computations. See Note K for additional information regarding the Company’s basic and diluted earnings per share computations for the three and nine months ended September 30, 2009 and 2008.

In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”). The Reserve Ruling revises oil and gas reporting disclosures. The Reserve Ruling also permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The Reserve Ruling will also allow companies to disclose their probable

14

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor, (ii) file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit and (iii) report oil and gas reserves using an average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than a year-end price. The Reserve Ruling becomes effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. During February 2009, the FASB announced a project to amend SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (“ASC 932”) to conform to the Reserve Ruling. The Company is currently assessing the impact that adoption of the provisions of the Reserve Ruling will have on its financial position, results of operations and disclosures.

In April 2009, the FASB issued FASB Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825”), which amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments” and Accounting Principles Board Opinion No. 28, “Interim Financial Reporting”. ASC 825 requires fair value disclosures by publicly traded companies of financial instruments for interim reporting purposes. ASC 825 was adopted by the Company during the second quarter of 2009. See Note D for disclosures about the fair values of the Company’s financial instruments.

Reclassifications and retrospective adjustments. Certain reclassifications have been made to the 2008 amounts in order to conform to the 2009 presentation and for the retrospective application of the adoption of ASC 810. The retrospective application of ASC 810 resulted in the reclassification of $59.2 million from minority interest in consolidated subsidiaries and $44.8 million from AOCI – Hedging to Noncontrolling interest in consolidated subsidiaries at December 31, 2008. In addition, the adoption of ASC 470 and ASC 260 required retrospective adjustments to the Company’s financial statements as of December 31, 2008 and the three and nine months ended September 30, 2008. The retrospective adjustments related to the adoption of ASC 470 decreased the Company’s net income attributable to common stockholders by $2.2 million (approximately $.01 per diluted share) and $6.1 million (approximately $.05 per diluted share), respectively, for the three and nine months ended September 30, 2008. The retrospective application of ASC 470 also increased additional paid-in capital by $49.5 million and decreased retained earnings by $10.0 million as of December 31, 2008. The retrospective application of the provisions of ASC 260 did not change the Company’s diluted earnings for the three months ended September 30, 2008 and reduced the Company’s diluted earnings for the nine months ended September 30, 2008 by approximately $.05 per share, exclusive of the effects from the adoption of ASC 470.

In the second quarter of 2009, the Company inadvertently overstated its depletion, depreciation and amortization (“DD&A”) expense by $7.3 million ($4.6 million net of associated income taxes) attributable to oil and gas volumes sold during that quarter. This overstatement primarily resulted from an exclusion of certain proved reserves from the calculation of the Company’s DD&A expense for the three months ended June 30, 2009. This error also overstated the Company’s accumulated depletion, depreciation and amortization and income taxes payable by $7.3 million and $178 thousand, respectively, and understated the Company’s deferred tax liabilities by $2.9 million. The Company has concluded that the effect of the overstatement was not material to the reported financial position and earnings of the Company as of and for the three and six months ended June 30, 2009 and has reflected the correction in its reported financial position and results of operations as of and for the nine months ended September 30, 2009. The correction reduced the Company’s diluted per share net loss attributable to common stockholders by $.04 for the three and six months ended June 30, 2009.

NOTE C.    Exploratory Well Costs

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

15

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

The following table reflects the Company’s capitalized exploratory well activity during the three and nine months ended September 30, 2009:

	Three Months Ended September 30, 2009			Nine Months Ended September 30, 2009
	(in thousands)
Beginning capitalized exploratory well costs	$	113,997		$	124,014
Additions to exploratory well costs pending the determination of proved reserves		20,420			46,758
Reclassification due to determination of proved reserves		(5,949	)		(33,150	)
Exploratory well costs charged to exploration expense		(6,798	)		(15,952	)
Ending capitalized exploratory well costs	$	121,670		$	121,670

The following table provides an aging, as of September 30, 2009 and December 31, 2008, of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:

	September 30, 2009		December 31, 2008
	(in thousands, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	30,850	$	54,423
More than one year		90,820		69,591
	$	121,670	$	124,014
Number of projects with exploratory well costs that have been suspended for a period greater than one year		5		4

The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of September 30, 2009:

	Total		2009		2008		2007		2006
	(in thousands)
United States:
Cosmopolitan Unit	$	60,613	$	1,952	$	6,344	$	51,488	$	829
Tunisia		30,207		962		20,866		4,434		3,945
Total	$	90,820	$	2,914	$	27,210	$	55,922	$	4,774

Cosmopolitan Unit. The Company owns a 100 percent working interest in, and is the operator of, the Cosmopolitan Unit in the Cook Inlet of Alaska. During 2007, the Company drilled the Hansen #1A L1 well, a lateral sidetrack from an existing wellbore, to appraise the resource potential of the unit. The initial unstimulated production test results were encouraging. The Company plans to workover the well in the fourth quarter 2009 to repair the casing. The well may be fracture stimulated in 2010 contingent upon the results of the casing repair and subsequent flow testing. The Company will continue to conduct permitting activities and facilities planning during the fourth quarter of 2009 and may drill another appraisal well in 2010.

16

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

Tunisia – Cherouq. The Company has $17.5 million and $5.0 million of suspended well costs recorded for the Hayaat #1 and Hilal #1 wells, respectively, in the Company’s Cherouq production concession area, which is operated by the Company. The Hayaat #1 well began drilling in April 2008 to test several targeted formations. Mechanical failures were encountered during the testing of the well that did not allow completion of the formation assessments. The Company is analyzing seismic and other data to determine the optimal plan forward for completing the well, which may utilize the existing wellbore or a new wellbore adjacent to the existing well. The Company expects to finalize its Hayaat #1 plans and complete its assessment activities during 2010 or 2011.

The Hilal #1 well was originally drilled as an exploration well during 2007. The well was unsuccessful; however, the well is being re-completed to a formation that will be used for water disposal in support of other Cherouq operations. The Company recorded a $1.5 million dry hole charge for the Hilal #1 during 2007, representing the portion of the well costs that will not be used in disposal operations. Installation of the surface equipment is underway and disposal operations are planned to start during the fourth quarter of 2009.

Tunisia – Borj El Khadra. The Company has $7.6 million of suspended well costs attributable to the Nahkil #1 and Abir #1 wells in the Borj El Khadra exploration permit area, which is operated by a third-party. The Nahkil #1 well encountered oil-bearing sands and the Abir #1 well encountered gas-bearing sands. The Company does not record proved reserves associated with discoveries in exploration permit areas until a production concession is granted. Infrastructure planning is underway and further exploration of the permit area is planned to occur in the fourth quarter of 2009 or 2010.

NOTE D.    Disclosures About Fair Value Measurements

The valuation framework of ASC 820, which addresses fair value measurements, is based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. 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. These two types of inputs are further prioritized into the following fair value input hierarchy:

• 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.

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.

17

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

The following table presents the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2009, for each of the fair value hierarchy levels:

	Fair Value Measurements at Reporting Date 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, 2009
	(in thousands)
Assets:
Trading securities	$	231	$	73	$	—	$	304
Commodity derivatives		—		71,706		5,346		77,052
Deferred compensation plan assets		25,582		—		—		25,582
Total assets	$	25,813	$	71,779	$	5,346	$	102,938
Liabilities:
Commodity derivatives	$	—	$	146,741	$	3,939	$	150,680
Interest rate derivatives		—		6,951		—		6,951
Total liabilities	$	—	$	153,692	$	3,939	$	157,631

The following tables present the changes in the fair values of the Company’s net commodity derivative assets classified as Level 3 in the fair value hierarchy:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months Ended September 30, 2009
	NGL Swap Contracts
	(in thousands)
Beginning balance	$	5,466
Total gains (losses) (a):
Net unrealized losses included in earnings		(1,695	)
Net realized losses included in earnings		(2,423	)
Settlements		59
Ending balance	$	1,407

(a) The hedge-effective portions of realized gains and losses on commodity derivatives in AOCI – Hedging are included in oil and gas revenues, while non-hedge derivatives or ineffective portions of realized and unrealized gains and losses are included in derivative losses, net in the accompanying consolidated statements of operations.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Nine Months Ended September 30, 2009
	NGL Swap Contracts			Gas Three-Way Collars			Oil Three-Way Collars			Total
	(in thousands)
Beginning balance	$	18,560		$	—		$	—		$	18,560
Total gains (losses):
Net unrealized gains (losses) included in earnings (a)		(8,260	)		(1,697	)		3,364			(6,593	)
Net derivative losses included in other comprehensive income		(1,855	)		—			—			(1,855	)
Net realized gains transferred to earnings (a)		(2,794	)		—			—			(2,794	)
Settlements		(4,244	)		—			—			(4,244	)
Transfers into/out of Level 3		—			1,697			(3,364	)		(1,667	)
Ending balance	$	1,407		$	—		$	—		$	1,407

18

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(Unaudited)

(a) The hedge-effective portions of realized gains and losses on commodity derivatives are included in oil and gas revenues, while non-hedge derivatives or ineffective portions of realized and unrealized gains and losses are included in derivative losses, net in the accompanying consolidated statements of operations.

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of September 30, 2009 and December 31, 2008:

	September 30, 2009				December 31, 2008
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	77,052	$	77,052	$	132,216	$	132,216
Trading securities	$	304	$	304	$	356	$	356
Deferred compensation plan assets	$	25,582	$	25,582	$	18,276	$	18,276
Notes receivable due 2008 to 2011	$	10,573	$	10,573	$	11,258	$	11,258
Liabilities:
Commodity price derivatives	$	150,680	$	150,680	$	60,242	$	60,242
Interest rate derivatives	$	6,951	$	6,951	$	9,903	$	9,903
Pioneer Natural Resources Credit facility	$	730,000	$	723,653	$	913,000	$	868,597
Pioneer Southwest Credit facility	$	135,000	$	132,562	$	—	$	—
2.875% senior convertible notes due 2038	$	425,890	$	459,600	$	415,194	$	345,600
5.875 % senior notes due 2012	$	6,174	$	6,183	$	6,191	$	5,233
5.875 % senior notes due 2016	$	387,274	$	418,954	$	382,010	$	301,583
6.65 % senior notes due 2017	$	483,883	$	458,420	$	483,792	$	339,570
6.875 % senior notes due 2018	$	449,154	$	424,777	$	449,132	$	292,175
7.20 % senior notes due 2028	$	249,923	$	222,750	$	249,922	$	145,000

Trading securities and deferred compensation plan assets. The Company’s trading securities represent equity securities that are not actively traded on major exchanges and trading securities that are 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 plus unallocated contributions as of the measurement date. As of September 30, 2009, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs except inputs for trading securities that are not actively traded on major exchanges, which were provided by broker quotes representing Level 2 inputs.

Notes receivable. The fair value of the Company’s notes receivable approximates the carrying values based on the adequacy of the collateral security and interest yields.

Interest rate derivatives. The Company’s interest rate derivative liabilities represent swap contracts for $400 million notional amount of debt, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate and $50 million notional amount of debt, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. The net derivative liability values attributable to the Company’s interest rate derivative contracts as of September 30, 2009 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company’s commodity derivatives represent oil, NGL and gas swap and collar contracts. The Company’s oil and gas swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority while NGL derivative contract asset and liability measurements represent Level 3 inputs in the hierarchy priority.

Oil derivatives. The Company’s oil derivatives are swap, collar and three-way collar contracts for notional Bbls of oil at fixed (in the case of swap contracts) or interval (in the case of collar and three-way collar contracts) NYMEX

19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

West Texas Intermediate (“WTI”) oil prices. The asset and liability values attributable to the Company’s oil derivatives as of September 30, 2009 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts were determined based on market-quoted volatility factors adjusted for estimated volatility skews and corroborated with average volatility factors provided by the Company’s counterparties.

NGL derivatives. The Company’s NGL derivatives are swap contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs. The asset and liability values attributable to the Company’s NGL derivatives as of September 30, 2009 are based on (i) the contracted notional volumes, (ii) independent broker-supplied forward Mont Belvieu-posted-price quotes and (iii) the applicable credit-adjusted risk-free rate yield curve.

Gas derivatives. The Company’s gas derivatives are swap, collar and three-way collar contracts for notional MMBtus of gas contracted at various posted price indexes, including NYMEX Henry Hub (“HH”) swap contracts coupled with basis swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company’s gas derivative contracts as of September 30, 2009 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) averages of forward posted price quotes supplied by independent brokers who are active in buying and selling gas derivatives at the indexes other than HH (iv) the applicable credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts were determined based on market-quoted volatility factors adjusted for estimated volatility skews and corroborated with average volatility factors provided by the Company’s counterparties.

The Company corroborated independent broker-supplied forward price quotes by comparing price quote samples to alternate observable market data.

Credit facility. The fair value of the Company’s credit facility is based on (i) contractual interest and fees, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

Senior notes. The Company’s senior notes represent debt securities that are actively traded on major exchanges.

NOTE E.    Income Taxes

The Company accounts for income taxes in accordance with the provisions of ASC 740 (formerly SFAS 109), “Income Taxes” (“ASC 740”). ASC 740 requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors to assess the likelihood that the Company’s net operating loss carryforwards (“NOLs”) and other deferred tax attributes in the U.S. federal, state and foreign tax jurisdictions will be utilized prior to their expiration. As of September 30, 2009 and December 31, 2008, the Company’s valuation allowances (relating primarily to foreign tax jurisdictions) were $44.2 million and $37.5 million, respectively.

ASC 740 also clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of September 30, 2009, the Company had no unrecognized tax benefits. The Company’s policy is to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. 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 tax authorities for years before 2004. As of September 30, 2009, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company’s future results of operations or financial position.

On June 30, 2009, pursuant to Tunisian law, the Company established an investment reserve equal to 20 percent of 2008 taxable profits on the Adam and Cherouq concessions and thereby reduced current taxes payable by $13.1 million with a corresponding offset to deferred income taxes in the Company’s accompanying consolidated balance sheets. The investment reserve will be used to fund future drilling activity or pipeline infrastructure projects in Tunisia.

20

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

In the reported results for the nine months ended September 30, 2009, the Company recognized an additional deferred provision of $2.9 million and a current tax benefit of $178 thousand related to the Company’s correction of the understatement of reported earnings for the three months ended June 30, 2009. See Note B for additional information regarding this correction.

Income tax (provisions) benefits. 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, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)
Current:
U.S. federal	$	(1,335	)	$	(124	)	$	(934	)	$	8,784
U.S. state		(2,206	)		967			(9,142	)		(630	)
Foreign		(8,708	)		(24,972	)		(9,650	)		(65,423	)
		(12,249	)		(24,129	)		(19,726	)		(57,269	)
Deferred:
U.S. federal		15,273			17,455			68,796			(125,565	)
U.S. state		3,696			(1,377	)		9,460			(4,246	)
Foreign		(1,514	)		(5,114	)		(10,859	)		(30,535	)
		17,455			10,964			67,397			(160,346	)
Income tax (provision) benefit	$	5,206		$	(13,165	)	$	47,671		$	(217,615	)

Discontinued operations. The Company’s income tax (provisions) benefits attributable to income from discontinued operations consisted of the following for three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)
Current:
Foreign	$	—		$	(135	)	$	—		$	(306	)
		—			(135	)		—			(306	)
Deferred:
U.S. federal		(7,153	)		(438	)		(8,102	)		(6,746	)
Foreign		—			65			—			935
		(7,153	)		(373	)		(8,102	)		(5,811	)
Income tax provision	$	(7,153	)	$	(508	)	$	(8,102	)	$	(6,117	)

NOTE F.    Long-term Debt

Lines of credit. During April 2007, the Company entered into an Amended and Restated 5-Year Revolving Credit Agreement (the “Credit Facility”) that matures in April 2012, unless extended in accordance with the terms of the Credit Facility. The Credit Facility provides for initial aggregate loan commitments of $1.5 billion, which may be increased to a maximum aggregate amount of $2.0 billion if the lenders increase their loan commitments or if loan commitments of new financial institutions are added. As of September 30, 2009, the Company had $730.0 million of outstanding borrowings under the Credit Facility and $46.0 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $724.0 million of unused borrowing capacity under the Credit Facility.

21

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

Effective April 29, 2009, the Company and the lenders under the Company’s Credit Facility amended the Credit Facility to provide the Company additional financial flexibility. The Credit Facility contains certain financial covenants, one of which required the Company to maintain a ratio of the net present value of the Company’s oil and gas properties to total debt of at least 1.75 to 1.0 until the Company achieves an investment grade rating by Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Group, Inc. The amendment changed that ratio to 1.5 to 1.0 through the period ending March 31, 2011, after which time the ratio would revert to 1.75 to 1.0, and provides that the Company may include in the calculation of the present value of its oil and gas properties 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest. The covenant requiring the Company to maintain a ratio of total debt to total capitalization of no more than 0.60 to 1.0 was not changed.

The amendment also adjusted certain borrowing rates and commitment fees, and changed certain provisions relating to the consequences if a lender under the Credit Facility defaults in its obligations under the agreement. After taking into account the amendment, revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus .5 percent plus a defined alternate base rate spread margin (“ABR Margin”), which is currently one percent based on the Company’s debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the “Applicable Margin”), which is currently two percent and is also determined by the Company’s debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the “ASK” rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus ..125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company’s debt rating (currently 0.375 percent).

On August 31, 2009, Pioneer Southwest borrowed $138.0 million under its $300 million credit facility (the “Pioneer Southwest Credit Facility”) that matures during 2013 to fund a portion of the purchase consideration of oil and gas properties acquired from Pioneer Natural Resources USA, Inc. (“Pioneer USA”), a wholly-owned subsidiary of the Company, for $169.6 million, including estimated customary closing adjustments, and assumed net obligations associated with certain commodity price derivative positions and certain other liabilities that were assigned by Pioneer USA to Pioneer Southwest. 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. Eurodollar rate loans bear interest annually at LIBOR, plus a margin (the “Applicable Rate”) (currently 0.875 percent) that is determined by a reference grid based on Pioneer Southwest’s consolidated leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate plus 0.5 percent or (ii) the Bank of America prime rate (the “Base Rate”) plus a margin (currently zero percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate. As of September 30, 2009, there were $135.0 million of outstanding borrowings under the Pioneer Southwest Credit Facility.

The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter-end consolidated leverage ratio (representing a ratio of consolidated indebtedness of Pioneer Southwest to consolidated earnings before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense; accretion of discount on asset retirement obligations; interest expense; income taxes; gain or loss on the disposition of assets; noncash commodity hedge related activity; and noncash equity-based compensation, (“EBITDAX”) of not more than 3.5 to 1.0, (ii) an interest coverage ratio (representing a ratio of EBITDAX to interest expense) of not less than 2.5 to 1.0 and (iii) the maintenance of a ratio of the net present value of Pioneer Southwest’s projected future cash flows from its oil and gas assets to total debt of at least 1.75 to 1.0.

Because of the net present value covenant, the remaining available borrowing capacity under the Pioneer Southwest Credit Facility was limited to approximately $140 million as of September 30, 2009. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rate) are subject to adjustment by the lenders. As a result, declines in commodity prices could reduce Pioneer Southwest’s borrowing capacity under the Pioneer

22

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

Southwest Credit Facility. In addition, the Pioneer Southwest Credit Facility contains various covenants that limit, among other things, Pioneer Southwest’s ability to grant liens, incur additional indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity, and sell its assets. If any default or event of default (as defined in the Pioneer Southwest Credit Facility) were to occur, the Pioneer Southwest Credit Facility would prohibit Pioneer Southwest from making distributions to unitholders. Such events of default include, among others, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and liabilities.

As of September 30, 2009, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Senior convertible notes. During January 2008, the Company issued $500 million principal amount of 2.875% Convertible Senior Notes, of which $480.0 million remains outstanding at September 30, 2009. Effective January 1, 2009, the Company adopted the provisions of ASC 470 (formerly FSP APB 14-1) and, in accordance therewith, the Company applied the provisions of ASC 470 on a retrospective basis. The initial adoption of ASC 470 decreased the carrying value of the 2.875% Convertible Senior Notes by $63.5 million, increased stockholders’ equity by $39.5 million and increased deferred tax liabilities by $24.0 million. For the three and nine months ended September 30, 2009, the adoption of ASC 470 had the effect of adding $3.6 million and $10.7 million to the Company’s reported interest expense, respectively, and approximately $2.3 million ($.02 per diluted share) and $6.7 million ($.06 per diluted share) to the Company’s respective net losses.

NOTE G.    Derivative Financial Instruments

The Company uses financial derivative contracts to manage exposures to commodity price, interest rate and foreign currency fluctuations. The Company generally does not enter into derivative financial instruments for speculative or trading purposes. The Company also may enter physical delivery contracts to effectively provide commodity price protection. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, physical delivery contracts are not accounted for as derivative financial instruments in the financial statements.

All derivative contracts are recorded on the balance sheet at estimated fair value. Fair value is generally determined based on the credit-adjusted present value difference between the fixed contract price and the underlying market price at the determination date. Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments and since that date has accounted for derivative instruments using the mark-to-market accounting method. Therefore, the Company will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

Changes in the fair value of effective cash flow hedges prior to the Company’s discontinuance of hedge accounting on February 1, 2009 were recorded as a component of AOCI – Hedging, which has been or will be transferred to earnings when the hedged transaction is recognized in earnings. Any ineffective portion of changes in the fair value of hedge derivatives prior to February 1, 2009 was recorded in the earnings of the period of change. The ineffective portion was calculated as the difference between the change in fair value of the hedge derivative and the estimated change in cash flows from the item hedged.

Fair value derivatives. The Company monitors the debt capital markets and interest rate trends to identify opportunities to enter into and terminate interest rate derivative contracts, with the objective of reducing the Company’s costs of capital. As of September 30, 2009 and December 31, 2008, the Company was not a party to any fair value hedges.

Cash flow derivatives. The Company utilizes commodity swap and collar contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (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 and forward currency exchange agreements to reduce the effect of exchange rate volatility.

23

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

Oil prices. All material physical sales contracts governing the Company’s oil production have been tied directly or indirectly to the NYMEX prices. The following table sets forth the volumes in Bbls underlying the Company’s outstanding oil derivative contracts and the weighted average NYMEX prices per Bbl for those contracts as of September 30, 2009:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production non-hedge derivatives (a):
2009 – Swap Contracts
Volume (Bbl)								11,250		11,250
Price per Bbl							$	63.41	$	63.41
2009 – Collar Contracts
Volume (Bbl)								2,000		2,000
Price per Bbl:
Ceiling							$	70.38	$	70.38
Floor							$	52.00	$	52.00
2009 – Collar Contracts with Short Puts
Volume (Bbl)								15,000		15,000
Price per Bbl:
Ceiling							$	69.72	$	69.72
Floor							$	51.47	$	51.47
Short Put							$	41.47	$	41.47
2010 – Swap Contracts
Volume (Bbl)		2,500		2,500		2,500		2,500		2,500
Price per Bbl	$	93.34	$	93.34	$	93.34	$	93.34	$	93.34
2010 – Collar Contracts with Short Puts
Volume (Bbl)		24,750		25,000		25,000		25,250		25,000
Price per Bbl:
Ceiling	$	83.57	$	83.61	$	83.61	$	83.74	$	83.63
Floor	$	66.20	$	66.24	$	66.24	$	66.28	$	66.24
Short	$	53.46	$	53.48	$	53.48	$	53.50	$	53.48
2011 – Swap Contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	77.25	$	77.25	$	77.25	$	77.25	$	77.25
2011 – Collar Contracts
Volume (Bbl)		2,000		2,000		2,000		2,000		2,000
Price per Bbl:
Ceiling	$	170.00	$	170.00	$	170.00	$	170.00	$	170.00
Floor	$	115.00	$	115.00	$	115.00	$	115.00	$	115.00
2011 – Collar Contracts with Short Puts
Volume (Bbl)		25,000		25,000		25,000		25,000		25,000
Price per Bbl:
Ceiling	$	94.60	$	94.60	$	94.60	$	94.60	$	94.60
Floor	$	72.80	$	72.80	$	72.80	$	72.80	$	72.80
Short Put	$	58.52	$	58.52	$	58.52	$	58.52	$	58.52
2012 – Swap Contracts
Volume (Bbl)		3,000		3,000		3,000		3,000		3,000
Price per Bbl	$	79.32	$	79.32	$	79.32	$	79.32	$	79.32

24

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

2012 – Collar Contracts with Short Puts
Volume (Bbl)		1,000		1,000		1,000		1,000		1,000
Price per Bbl:
Ceiling	$	103.50	$	103.50	$	103.50	$	103.50	$	103.50
Floor	$	80.00	$	80.00	$	80.00	$	80.00	$	80.00
Short Put	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00
2013 – Swap Contracts
Volume (Bbl)		3,000		3,000		3,000		3,000		3,000
Price per Bbl	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02
2013 – Collar Contracts with Short Puts
Volume (Bbl)		1,250		1,250		1,250		1,250		1,250
Price per Bbl:
Ceiling	$	111.50	$	111.50	$	111.50	$	111.50	$	111.50
Floor	$	83.00	$	83.00	$	83.00	$	83.00	$	83.00
Short Put	$	68.00	$	68.00	$	68.00	$	68.00	$	68.00

(a) Subsequent to September 30, 2009, the Company entered into additional collar contracts with short puts for (i) 2,000 Bbls per day of the Company’s 2010 production with a ceiling price of $86.50 per Bbl, a floor price of $75.00 per Bbl and a short put price of $60.00 per Bbl, (ii) 9,000 Bbls per day of the Company’s 2011 production with a ceiling price of $107.37 per Bbl, a floor price of $75.00 per Bbl and a short put price of $60.00 per Bbl and (iii) 4,000 Bbls per day of the Company’s 2012 production with a ceiling price of $107.50 per Bbl, a floor price of $80.00 per Bbl and a short put price of $65.00 per Bbl.

Natural gas liquids prices. All material physical sales contracts governing the Company’s NGL production have been tied directly or indirectly to Mont Belvieu prices. The following table sets forth the volumes in Bbls under outstanding NGL derivative contracts and the weighted average Mont Belvieu-posted-prices per Bbl for those contracts as of September 30, 2009:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production non-hedge derivatives:
2009 – Swap Contracts
Volume (Bbl)								3,750		3,750
Price per Bbl							$	34.28	$	34.28
2010 – Swap Contracts
Volume (Bbl)		1,250		1,250		1,250		1,250		1,250
Price per Bbl	$	47.36	$	47.37	$	47.38	$	47.38	$	47.38
2011 – Swap Contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	34.65	$	34.65	$	34.65	$	34.65	$	34.65
2010 – Swap Contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03

25

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

Gas prices. All material physical sales contracts governing the Company’s gas production have been tied directly or indirectly to regional index prices where the gas is produced. The Company uses derivative contracts to mitigate gas price volatility and reduce basis risk between NYMEX prices and actual index prices upon which the gas is sold. The following table sets forth the volumes in MMBtus under outstanding gas derivative contracts and the weighted average index prices per MMBtu for those contracts as of September 30, 2009:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production non-hedge derivatives (a):
2009 – Swap Contracts
Volume (MMBtu)											137,500			137,500
Price per MMBtu										$	6.13		$	6.13
2009 – Collar Contracts
Volume (MMBtu)											20,000			20,000
Price per MMBtu:
Ceiling										$	5.90		$	5.90
Floor										$	4.00		$	4.00
2009 – Collar Contracts with Short Puts
Volume (MMBtu)											150,000			150,000
Price per MMBtu:
Ceiling										$	5.35		$	5.35
Floor										$	4.18		$	4.18
Short Put										$	3.18		$	3.18
2009 – Basis Swap Contracts
Volume (MMBtu)											285,000			285,000
Price per MMBtu										$	(0.96	)	$	(0.96	)
2010 – Swap Contracts
Volume (MMBtu)		177,500			177,500			127,500			127,500			152,295
Price per MMBtu	$	6.30		$	6.30		$	6.59		$	6.59		$	6.42
2010 – Collar Contracts
Volume (MMBtu)		30,000			30,000			30,000			30,000			30,000
Price per MMBtu:
Ceiling	$	7.52		$	7.52		$	7.52		$	7.52		$	7.52
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
2010 – Collar Contracts with Short Puts
Volume (MMBtu)		95,000			95,000			95,000			95,000			95,000
Price per MMBtu:
Ceiling	$	7.94		$	7.94		$	7.94		$	7.94		$	7.94
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short Put	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2010 – Basis Swap Contracts
Volume (MMBtu)		215,000			215,000			215,000			215,000			215,000
Price per MMBtu	$	(0.77	)	$	(0.77	)	$	(0.77	)	$	(0.77	)	$	(0.77	)
2011 – Swap Contracts
Volume (MMBtu)		2,500			2,500			2,500			2,500			2,500
Price per MMBtu	$	6.65		$	6.65		$	6.65		$	6.65		$	6.65
2011 – Collar Contracts with Short Puts
Volume (MMBtu)		175,000			175,000			175,000			175,000			175,000
Price per MMBtu:
Ceiling	$	8.69		$	8.69		$	8.69		$	8.69		$	8.69
Floor	$	6.36		$	6.36		$	6.36		$	6.36		$	6.36
Short Put	$	4.93		$	4.93		$	4.93		$	4.93		$	4.93
2011 – Basis Swap Contracts
Volume (MMBtu)		100,000			100,000			100,000			100,000			100,000
Price per MMBtu	$	(0.71	)	$	(0.71	)	$	(0.71	)	$	(0.71	)	$	(0.71	)

26

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

2012 – Swap Contracts
Volume (MMBtu)		2,500			2,500			2,500			2,500			2,500
Price per MMBtu	$	6.77		$	6.77		$	6.77		$	6.77		$	6.77
2012 – Collar Contracts with Short Puts
Volume (MMBtu)		50,000			50,000			50,000			50,000			50,000
Price per MMBtu:
Ceiling	$	8.81		$	8.81		$	8.81		$	8.81		$	8.81
Floor	$	6.25		$	6.25		$	6.25		$	6.25		$	6.25
Short Put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2012 – Basis Swap Contracts
Volume (MMBtu)		20,000			20,000			20,000			20,000			20,000
Price per MMBtu	$	(0.78	)	$	(0.78	)	$	(0.78	)	$	(0.78	)	$	(0.78	)
2013 – Swap Contracts
Volume (MMBtu)		2,500			2,500			2,500			2,500			2,500
Price per MMBtu	$	6.89		$	6.89		$	6.89		$	6.89		$	6.89
2013 – Basis Swap Contracts
Volume (MMBtu)		10,000			10,000			10,000			10,000			10,000
Price per MMBtu	$	(0.71	)	$	(0.71	)	$	(0.71	)	$	(0.71	)	$	(0.71	)

(a) Subsequent to September 30, 2009, the Company unwound gas swap contracts for 24,795 MMBtu per day of the Company’s 2010 production at an average price of $5.56 per MMBtu.

Interest rate. During August 2009 and January 2008, the Company entered into interest rate swap contracts. The August 2009 contracts were fixed-for-variable-rate swaps on $50 million notional amount of debt at a weighted average fixed annual rate of 3.09 percent. The August 2009 contracts had an effective start date of August 2009 and were scheduled to terminate in August 2014. The January 2008 contracts were variable-for-fixed-rate swaps on $400 million notional amount of debt at a weighted average fixed annual rate of 2.87 percent, excluding any applicable margins. The January 2008 interest rate swaps had an effective start date of February 2008, with $200 million terminating during February 2010 and $200 million during February 2011. During October 2009, the Company terminated the $50 million notional amount, fixed-for-variable rate swap contracts and $111 million notional amount of the variable-for-fixed rate swap contracts. The resulting gains and losses from the terminated contracts completely offset and will have no impact on the Company’s 2009 results of operations

Hedge ineffectiveness. On February 1, 2009, the Company discontinued hedge accounting on all existing derivative contracts. As a result, the Company only recorded ineffectiveness during January 2009, which was nominal. During the three and nine months ended September 30, 2008, the Company recorded net ineffectiveness charges of $4.5 million and $2.6 million, respectively. Hedge ineffectiveness represents the ineffective portions of changes in the fair values of the Company’s cash flow hedging instruments. The primary causes of hedge ineffectiveness were changes in forecasted hedged sales volumes and commodity price correlations.

Tabular disclosure of derivative fair value. Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments, and since that date forward has accounted for derivative instruments using the mark-to-market accounting method. All of the Company’s derivatives were made up of non-hedge derivatives as of September 30, 2009 and both hedge derivatives and non-hedge derivatives as of December 31, 2008.

27

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

The following tables provide disclosure of the Company’s derivative instruments:

Fair Value of Derivative Instruments as of September 30, 2009
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	71,422	Derivatives - current	$	95,248
Interest rate derivatives	Derivatives - current		1,280	Derivatives - current		7,027
Commodity price derivatives	Derivatives - noncurrent		38,537	Derivatives - noncurrent		62,942
Interest rate derivatives	Derivatives - noncurrent		653	Derivatives - noncurrent		1,856
Total derivatives not designated as hedging instruments			111,892			167,073
Derivatives designated as hedging instruments (b)
Commodity price derivatives	Derivatives - current		—	Derivatives - current		21,114
Commodity price derivatives	Derivatives - noncurrent		—	Derivatives - noncurrent		4,284
Total derivatives designated as hedging instruments			—			25,398
Total derivatives		$	111,892		$	192,471
Fair Value of Derivative Instruments as of December 31, 2008
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	3,606	Derivatives - current	$	20,233
Commodity price derivatives	Derivatives - noncurrent		3,972	Derivatives - noncurrent		—
Total derivatives not designated as hedging instruments			7,578			20,233
Derivatives designated as hedging instruments
Commodity price derivatives	Derivatives - current		57,367	Derivatives - current		24,195
Interest rate derivatives	Derivatives - current		—	Derivatives - current		6,484
Commodity price derivatives	Derivatives - noncurrent		68,622	Derivatives - noncurrent		17,165
Interest rate derivatives	Derivatives - noncurrent		—	Derivatives - noncurrent		3,419
Total derivatives designated as hedging instruments			125,989			51,263
Total derivatives		$	133,567		$	71,496

(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.

(b) Represent derivative obligations under terminated hedge arrangements.

28

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

		Amount of Gain/(Loss) Recognized in OCI on Effective Portion
Derivatives in Cash Flow Hedging Relationships		Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008			2009			2008
		(in thousands)
Interest rate derivatives		$	—		$	(1,424	)	$	(433	)	$	3,677
Commodity price derivatives			—			617,321			4,968			(172,478	)
Total		$	—		$	615,897		$	4,535		$	(168,801	)
	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
Derivatives in Cash Flow Hedging Relationships		Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008			2009			2008
					(in thousands)
Interest rate derivatives	Interest expense	$	(1,621	)	$	(467	)	$	(5,893	)	$	(772	)
Commodity price derivatives	Oil and gas revenue		26,261			(144,030	)		96,173			(388,244	)
Total		$	24,640		$	(144,497	)	$	90,280		$	(389,016	)
	Location of Gain/(Loss) Recognized in Earnings on Ineffective Portion	Amount of Gain/(Loss) Recognized in Earnings on Ineffective Portion
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships		2009			2008			2009			2008
		(in thousands)
Commodity price derivatives	Derivative losses, net	$	—		$	(4,493	)	$	—		$	(2,585	)
	Location of Gain/(Loss) Recognized in Earnings on Derivative	Amount of Gain/(Loss) Recognized in Earnings on Derivative
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivatives Not Designated as Hedging Instruments		2009			2008			2009			2008
					(in thousands)
Interest rate derivatives	Interest expense	$	131		$	—		$	(3,120	)	$	—
Commodity price derivatives	Derivative losses, net		(15,353	)		634			(82,463	)		1,134
Total		$	(15,222	)	$	634		$	(85,583	)	$	1,134

AOCI - Hedging. The fair value of the effective portion of the Company’s derivative contracts that were designated as cash flow hedges on January 31, 2009 was recorded in AOCI-Hedging and is being transferred to oil and gas revenue (for commodity derivatives) and interest expense (for interest rate derivatives) over the remaining term of the contracts. In accordance with the mark-to-market method of accounting, the Company will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which the changes occur.

As of September 30, 2009 and December 31, 2008, AOCI - Hedging represented net deferred gains of $64.9 million and $88.8 million, respectively. The AOCI - Hedging balance as of September 30, 2009 was comprised of $142.2 million of net deferred gains on the effective portions of discontinued commodity hedges, $7.6 million of net deferred losses on the effective portions of discontinued interest rate hedges, $38.1 million of associated net deferred tax provisions and a charge for $31.6 million of AOCI – Hedging attributable to noncontrolling interests. The $23.9 million decrease in net deferred hedge gains comprising AOCI - Hedging during the nine months ended September 30, 2009 was primarily attributable to the transfer of net deferred hedge gains to earnings, partially offset by deferred fair value gains during January 2009 and a decrease in AOCI – Hedging attributable to noncontrolling interests. AOCI - Hedging attributable to noncontrolling interests represented $44.7 million of deferred gains, net of taxes as of December 31, 2008.

29

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

During the twelve months ending September 30, 2010, the Company expects to reclassify approximately $92.0 million of AOCI – Hedging net deferred gains to oil and gas revenues and $4.4 million of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify approximately $32.4 million of net deferred income tax provisions associated with hedge derivatives during the year ending September 30, 2010 from AOCI - Hedging to income tax expense.

Discontinued commodity hedges. Effective on February 1, 2009, the Company discontinued all of its commodity and interest rates hedges and began accounting for the associated derivatives using the mark-to-market accounting method. Prior to February 1, 2009, the Company periodically discontinued commodity hedges by terminating the derivative positions when the underlying commodity prices reached a point that the Company believed would be near the high or low price of the commodity prior to the scheduled settlement of the open commodity position. This allowed the Company to lock in gains or minimize losses associated with the open hedge positions. At the time of hedge discontinuation, the amounts recorded in AOCI—Hedging are maintained and amortized to earnings over the periods the production was scheduled to occur.

The following table sets forth, as of September 30, 2009, the scheduled amortization of net deferred gains and (losses) on discontinued commodity hedges that will be recognized as increases or (decreases) to the Company’s future oil and gas revenues:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(in thousands)
2009 net deferred hedge gains										$	24,622		$	24,622
2010 net deferred hedge gains	$	21,700		$	22,029		$	22,353		$	22,417		$	88,499
2011 net deferred hedge gains	$	7,989		$	8,072		$	8,159		$	8,021		$	32,241
2012 net deferred hedge losses	$	(810	)	$	(791	)	$	(783	)	$	(773	)	$	(3,157	)

NOTE H.    Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations. The following table summarizes the Company’s asset retirement obligation transactions during the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)
Beginning asset retirement obligations	$	154,172		$	185,911		$	172,433		$	208,184
Liabilities assumed in acquisitions		—			756			—			777
New wells placed on production and changes in estimates (a)		1,202			1,592			16,568			(6,200	)
Liabilities reclassified to discontinued operations held for sale		—			—			(1,756	)		—
Disposition of wells		(491	)		—			(13,334	)		—
Liabilities settled		(15,587	)		(31,774	)		(40,562	)		(50,578	)
Accretion of discount on continuing operations		2,754			1,981			8,259			5,885
Accretion of discount on discontinued operations		88			199			530			597
Ending asset retirement obligations	$	142,138		$	158,665		$	142,138		$	158,665

(a) During the nine months ended September 30, 2008, the Company recorded a $9.0 million decrease in the abandonment estimates and associated insurance recovery estimates for the East Cameron facility that was destroyed by Hurricane Rita in 2005. During the nine months ended September 30, 2009, the Company recorded a $16.2 million increase to the abandonment estimate associated with the East Cameron facility. See Note O for additional information regarding the East Cameron facility.

30

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

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, 2009 and December 31, 2008, the current portions of the Company’s asset retirement obligations were $9.9 million and $29.9 million, respectively.

NOTE I.    Postretirement Benefit Obligations

As of September 30, 2009 and December 31, 2008, the Company had $9.2 million and $9.6 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the consolidated balance sheets. These obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of September 30, 2009 or December 31, 2008. Other than participants in the Company’s retirement plan, the participants of these plans are not current employees of the Company.

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	9,364		$	10,341		$	9,612		$	10,494
Net benefit payments		(361	)		(599	)		(1,052	)		(1,162	)
Service costs		57			47			171			142
Accretion of interest		164			158			493			473
Ending accumulated postretirement benefit obligations	$	9,224		$	9,947		$	9,224		$	9,947

NOTE J.    Commitments and Contingencies

Legal actions. The Company is party to the legal actions that are described below. The Company is also a party to other proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company will continue to evaluate its litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then current status of litigation.

MOSH Holding. On April 11, 2005, the Company and its principal United States subsidiary, Pioneer Natural Resources USA, Inc., were named as defendants in MOSH Holding, L.P. v Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc.; Woodside Energy (USA) Inc.; and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (the “Trust”), which was formerly pending before the Judicial District Court of Harris County, Texas (334th Judicial District) (the “Court”).

In April, 2009, the Company and all parties in the lawsuit reached an agreement to settle the lawsuit. Under the terms of the settlement agreement, the Company will pay to the Trust the sum of $13 million in exchange for a full and final release of all claims made or that could have been made in the lawsuit (the “Claims”). The Company will also contribute to the Trust any proceeds obtained from the Company’s sale of its complete interest, including its working interest, in the Brazos Block A-39 tract, which will be offered for sale in conjunction with the Trust’s sale of its assets.

31

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

The settlement agreement is subject to customary conditions, including a condition that the settlement is not final until it is approved by the Court and the Court issues a final, non-appealable judgment disposing of all Claims. In September, 2009, the Court entered a final judgment approving the settlement and dismissing all Claims. Subsequently, certain unit-holders in the Trust filed an appeal in Texas state court seeking to reverse the Court’s final judgment. The settlement will not be final and completed until such appeal is dismissed and any other post-judgment proceedings are exhausted. Pioneer expects to prevail with respect to any such appeal or any other post-judgment proceedings attempting to avoid the settlement.

Colorado Notice of Violation. On May 13, 2008, the Company was served with a Notice of Violation/Cease and Desist Order by the State of Colorado Department of Public Health and Environmental Water Quality Control Division. The Notice alleges violations of stormwater discharge permits in the Company’s Raton Basin and Lay Creek operations, specifically deficiencies in the Company’s stormwater management plans, failure to implement and maintain best management practices to protect stormwater runoff and failure to conduct inspections of the stormwater management system. The Company has filed an answer to the Notice asserting defenses to the allegations. The Company does not believe that the outcome of this proceeding will materially impact the Company’s liquidity, financial position or future results of operations.

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations. The Company does not believe that these obligations, which primarily pertain to matters of litigation, environmental contingencies, royalty obligations and income taxes, are probable of having a material impact on its liquidity, financial position or future results of operations.

The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale in 2007 of its Canadian assets.

NOTE K.    Earnings Per Share From Continuing Operations

Basic earnings per share from continuing operations is computed by dividing earnings from continuing operations attributable to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted earnings per share from continuing operations reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive to income from continuing operations were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. During periods that the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to loss per share and conversion into common stock is assumed not to occur.

The Company’s earnings from continuing operations attributable to common stockholders is computed as income (loss) from continuing operations less participating share-based earnings. The following table is a reconciliation of the Company’s income (loss) from continuing operations to income (loss) from continuing operations attributable to common stockholders for the three- and nine-month periods ended September 30, 2009 and 2008:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2009			2008		2009			2008
	(in thousands)
Income (loss) from continuing operations	$	(10,274	)	$	2,860	$	(110,365	)	$	280,088
Participating share-based earnings (a)		—			—		(94	)		(3,440	)
Income (loss) from continuing operations available to common stockholders	$	(10,274	)	$	2,860	$	(110,459	)	$	276,648

32

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

(a) In accordance with ASC 260 (formerly FSP EITF 03-6-1), unvested restricted stock share awards and restricted stock unit awards represent participating securities because they participate in nonforfeitable dividends with the Company’s common stock. Participating share-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and restricted stock unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

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-month periods ended September 30, 2009 and 2008:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2009	2008	2009	2008
	(in thousands)
Weighted average common shares outstanding (a):
Basic	114,123	118,110	114,118	118,136
Dilutive common stock options (b)	—	—	—	312
Contingently issuable - performance shares (b)	—	—	—	120
Convertible notes dilution (c)	—	—	—	197
Diluted	114,123	118,110	114,118	118,765

(a) In 2007, the Company’s board of directors (“Board”) approved a $750 million share repurchase program of which $355.8 million remained available for purchase as of September 30, 2009. During the first nine months of 2009 and 2008, the Company purchased $16.3 million and $12.8 million of common stock pursuant to the program, respectively.

(b) Diluted earnings per share were calculated using the two-class method for the three- and nine-months ended September 30, 2009 and 2008. The following common stock equivalents were excluded from the diluted loss per share calculations for the three and nine months ended September 30, 2009 because they would have been anti-dilutive to the calculations: 1,194,518 and 768,049 unvested restricted shares or restricted stock units, respectively; 180,124 and 154,946 outstanding options to purchase the Company’s common stock, respectively; and 203,835 and 126,091 performance units, respectively. Additionally, 1,594,793 unvested restricted shares or restricted stock units, 277,034 outstanding options to purchase the Company’s common stock and 276,544 performance units were excluded from the diluted loss per share calculation for the three months ended September 30, 2008 because they would have been anti-dilutive to the calculation.

(c) During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes. Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the 2.875% Convertible Senior Notes had qualified for and been converted during the nine-months ended September 30, 2008. The 2.875% Convertible Senior Notes were not dilutive to the per share calculations of 2009 or the three months ended September 30, 2008.

NOTE L.    Geographic Operating Segment Information

The Company’s only operations are oil and gas exploration and producing activities; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable operations in the United States, South Africa and Tunisia.

The following tables provide the Company’s geographic operating segment data for the three and nine months ended September 30, 2009 and 2008. Geographic operating segment income tax (provisions) benefits have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The “Headquarters” table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis and operations in Equatorial Guinea and Nigeria, where the Company concluded exploration activities during 2007.

33

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended September 30, 2009
Revenues and other income:
Oil and gas	$	350,034		$	20,836		$	39,099		$	—		$	409,969
Interest and other		—			—			—			503			503
Gain (loss) on disposition of assets, net		80			—			—			(465	)		(385	)
		350,114			20,836			39,099			38			410,087
Costs and expenses:
Oil and gas production		84,083			822			5,489			—			90,394
Production and ad valorem taxes		28,089			—			—			—			28,089
Depletion, depreciation and amortization		128,954			20,813			5,639			7,199			162,605
Exploration and abandonments		19,908			114			4,910			141			25,073
General and administrative		—			—			—			34,799			34,799
Accretion of discount on asset retirement obligations		—			—			—			2,754			2,754
Interest		—			—			—			43,438			43,438
Hurricane activity, net		1,830			—			—			—			1,830
Derivative losses, net		—			—			—			15,222			15,222
Other		9,702			—			—			11,661			21,363
		272,566			21,749			16,038			115,214			425,567
Income (loss) from continuing operations before income taxes		77,548			(913	)		23,061			(115,176	)		(15,480	)
Income tax benefit (provision)		(28,693	)		265			(12,227	)		45,861			5,206
Income (loss) from continuing operations	$	48,855		$	(648	)	$	10,834		$	(69,315	)	$	(10,274	)

34

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended September 30, 2008
Revenues and other income:
Oil and gas	$	499,606		$	33,418		$	67,389		$	—		$	600,413
Interest and other		—			—			—			2,285			2,285
Gain on disposition of assets, net		—			—			—			190			190
		499,606			33,418			67,389			2,475			602,888
Costs and expenses:
Oil and gas production		91,933			10,389			4,837			—			107,159
Production and ad valorem taxes		46,124			—			—			—			46,124
Depletion, depreciation and amortization		106,085			4,109			3,739			7,332			121,265
Impairment of oil and gas properties		89,753			—			—			—			89,753
Exploration and abandonments		99,613			—			8,074			1,733			109,420
General and administrative		—			—			—			31,622			31,622
Accretion of discount on asset retirement obligations		—			—			—			1,981			1,981
Interest		—			—			—			41,176			41,176
Hurricane activity, net		541			—			—			—			541
Derivative losses, net											3,858			3,858
Other		5,079			—			—			28,885			33,964
		439,128			14,498			16,650			116,587			586,863
Income (loss) from continuing operations before income taxes		60,478			18,920			50,739			(114,112	)		16,025
Income tax benefit (provision)		(22,377	)		(5,487	)		(29,268	)		43,967			(13,165	)
Income (loss) from continuing operations	$	38,101		$	13,433		$	21,471		$	(70,145	)	$	2,860

35

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2009:
Revenues and other income:
Oil and gas	$	991,849		$	50,801		$	105,862		$	—		$	1,148,512
Interest and other		—			—			—			99,761			99,761
Gain (loss) on disposition of assets, net		87			—			—			(534	)		(447	)
		991,936			50,801			105,862			99,227			1,247,826
Costs and expenses:
Oil and gas production		257,580			4,763			23,274			—			285,617
Production and ad valorem taxes		79,503			—			—			—			79,503
Depletion, depreciation and amortization		414,135			57,812			15,706			21,769			509,422
Impairment of oil and gas properties		21,091			—			—			—			21,091
Exploration and abandonments		61,276			403			15,458			724			77,861
General and administrative		—			—			—			102,728			102,728
Accretion of discount on asset retirement obligations		—			—			—			8,259			8,259
Interest		—			—			—			128,051			128,051
Hurricane activity, net		18,280			—			—			—			18,280
Derivative losses, net		—			—			—			85,583			85,583
Other		48,852			—			3,768			36,847			89,467
		900,717			62,978			58,206			383,961			1,405,862
Income (loss) from continuing operations before income taxes		91,219			(12,177	)		47,656			(284,734	)		(158,036	)
Income tax benefit (provision)		(33,751	)		3,531			(26,911	)		104,802			47,671
Income (loss) from continuing operations	$	57,468		$	(8,646	)	$	20,745		$	(179,932	)	$	(110,365	)

36

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2008:
Revenues and other income:
Oil and gas	$	1,496,590		$	100,983		$	180,006		$	—		$	1,777,579
Interest and other		—			—			—			33,697			33,697
Gain on disposition of assets, net		513			—			—			4,255			4,768
		1,497,103			100,983			180,006			37,952			1,816,044
Costs and expenses:
Oil and gas production		254,464			28,738			14,097			—			297,299
Production and ad valorem taxes		129,670			—			—			—			129,670
Depletion, depreciation and amortization		294,009			13,152			9,116			21,876			338,153
Impairment of oil and gas properties		89,753			—			—			—			89,753
Exploration and abandonments		144,249			52			21,074			7,339			172,714
General and administrative		—			—			—			103,739			103,739
Accretion of discount on asset retirement obligations		—			—			—			5,885			5,885
Interest		—			—			—			123,124			123,124
Hurricane activity, net		2,400			—			—			—			2,400
Derivative losses, net		—			—			—			1,451			1,451
Other		19,657			—			—			34,496			54,153
		934,202			41,942			44,287			297,910			1,318,341
Income (loss) from continuing operations before income taxes		562,901			59,041			135,719			(259,958	)		497,703
Income tax benefit (provision)		(208,273	)		(17,122	)		(80,517	)		88,297			(217,615	)
Income (loss) from continuing operations	$	354,628		$	41,919		$	55,202		$	(171,661	)	$	280,088
	September 30,			December 31,
	2009			2008
	(in thousands)
Segment Assets:
United States	$	8,171,882		$	8,524,622
South Africa		207,819			241,619
Tunisia		251,036			299,168
Headquarters		50,331			96,376
Total consolidated assets	$	8,681,068		$	9,161,785

NOTE M.     Impairment of Oil and Gas Properties

Oil and gas properties assessments. During the first quarter of 2009 and the third quarter of 2008, the downward adjustments to economically recoverable resource potential in the Company’s Uinta/Piceance area associated with declines in commodity prices and well performance led to the impairment of the net assets in that area. The Company’s estimates of the undiscounted future cash flows attributed to the assets indicated that their carrying amounts were not expected to be recovered. Consequently, the Company recorded noncash charges during the first quarter of 2009 and the third quarter of 2008 of $21.1 million and $89.8 million, respectively, to reduce the carrying value of the Uinta/Piceance area oil and gas properties. The impairment charges reduced the oil and gas properties’ carrying values to their estimated fair values on those dates, represented by the estimated discounted future cash flows attributable to the assets, which were derived from Level 3 fair value inputs.

The Company’s primary assumptions of the estimated future cash flows attributable to oil and gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves and (ii) management’s commodity price outlook.

37

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

Goodwill assessments. The Company’s goodwill is attributable to a business combination that was completed in 2004 and is entirely attributable to United States reporting unit. In accordance with ASC 350 (formerly SFAS 142), the Company assesses its goodwill for impairment annually, during the third quarter using a July 1 assessment date, and whenever facts or circumstances indicate that the carrying value of its goodwill may be impaired. The Company’s assessments of goodwill during the third quarters of 2009 and 2008 indicated that it was not impaired. As a result of declines in commodity prices and a significant decline in the Company’s market capitalization during the second half of 2008, the Company assessed whether the carrying value of the United States reporting unit’s goodwill was impaired at December 31, 2008, March 31, 2009 and June 30, 2009 and concluded that it was not impaired based on those assessments. During 2009, commodity prices and the Company’s market capitalization increased, providing an indicator that the carrying value of goodwill is not impaired.

The Company’s assessments of goodwill for impairment include estimates of the fair value of its United States reporting unit and comparisons of those fair value estimates with the United States reporting unit’s carrying value. The Company’s estimates of the fair value of its United States reporting unit entail estimating the fair values of the reporting unit’s assets and liabilities. The primary component of those assets and liabilities is comprised of the reporting unit’s oil and gas properties, whose estimated values were based on the estimated discounted future net cash flows expected to be recovered from the properties. The Company’s primary assumptions in preparing the estimated discounted future net cash flows expected to be recovered from the properties are based on (i) proved reserves and risk-adjusted probable reserves, (ii) management’s price outlook, including assumptions as to inflation of costs and expenses, (iii) the estimated discount rate that would be used by purchasers to assess the fair value of the assets and liabilities attributable to the United States reporting unit and (iv) future income tax expense attributable to the net cash flows.

Due to the significant decline in the Company’s market capitalization during the second half of 2008, the Company expanded its assessment of goodwill impairment to consider the fair value of the United States reporting unit as determined using both the previously described discounted future net cash flow approach and a market approach. The Company assessed market capitalization over the 30-day and 60-day periods prior to July 1, 2009, June 30, 2009, March 31, 2009 and December 31, 2008 and performed sensitivity valuations of the United States reporting unit’s net assets based on varying valuation combinations of future discounted cash flow assumptions (including assessing future cash flows from proved properties only), market capitalization, control premiums, price inflation assumptions and discount rate assumptions. The Company will assess its goodwill for impairment when facts and circumstances indicate that it may be impaired, but no less often than annually, and such assessments may be affected by (i) additional United States reserve adjustments, both positive and negative, (ii) results of drilling activities, (iii) changes in management’s outlook on commodity prices and costs and expenses, (iv) changes in the Company’s market capitalization, (v) changes in the Company’s weighted average cost of capital and (vi) changes in income taxes.

NOTE N.     Volumetric Production Payments

During 2005, the Company sold 27.8 MMBOE of proved reserves by means of three VPP agreements for net proceeds of $892.6 million, including the assignment of the Company’s obligations under certain derivative hedge agreements. Proceeds from the VPPs were used to reduce outstanding indebtedness. The first VPP sold 58 Bcf of gas volumes over an expected five-year term that began in February 2005. The second VPP sold 10.8 MMBbls of oil volumes over an expected seven-year term that began in January 2006. The third VPP sold 6.0 Bcf of gas volumes over an expected 32-month term from May 2005 through December 2007, and 6.2 MMBbls of oil volumes over an expected five-year term that began in January 2006.

The Company’s VPPs represent limited-term overriding royalty interests in oil and gas reserves that: (i) entitle the purchaser to receive production volumes over a period of time from specific lease interests, (ii) are free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) are nonrecourse to the Company (i.e., the purchaser’s only recourse is to the reserves acquired), (iv) transfer title of the reserves to the purchaser and (v) allow the Company to retain the remaining reserves after the VPPs volumetric quantities have been delivered.

The Company (i) removed the proved reserves associated with the VPPs, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil and gas revenues over the term of each VPP, (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests and (iv) no longer recognizes production associated with the VPP volumes.

38

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

The following table provides information about the deferred revenue carrying values of the Company’s VPPs.

	Gas			Oil			Total
	(in thousands)
Deferred revenue at December 31, 2008	$	49,435		$	275,706		$	325,141
Less: 2009 amortization		(36,975	)		(73,926	)		(110,901	)
Deferred revenue at September 30, 2009	$	12,460		$	201,780		$	214,240

The above deferred revenue amounts will be recognized in oil and gas revenues in the consolidated statements of operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):

Remaining 2009	$	37,005
2010		90,215
2011		44,951
2012		42,069
	$	214,240

NOTE O.     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,
	2009			2008			2009		2008
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	—		$	—		$	94,989	$	17,770
Interest income		108			445			1,289		1,305
Other income (expense)		(36	)		(72	)		1,122		1,199
Deferred compensation plan income		52			96			913		1,642
Foreign currency remeasurement and exchange gains (b)		174			1,508			790		4,033
Credit card rebate		205			308			658		862
Change in asset retirement estimate		—			—			—		4,391
Legal settlements		—			—			—		2,495
Total interest and other income	$	503		$	2,285		$	99,761	$	33,697

(a) The Company earns Alaskan Petroleum Production Tax (“PPT”) credits on qualifying capital expenditures. The Company recognizes income from PPT credits at the time they are realized through a cash refund or sale.

(b) The Company’s operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

39

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

NOTE P.     Other Expense

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2009		2008			2009		2008
	(in thousands)
Idle rig related costs (a)	$	9,702	$	5,079		$	52,620	$	19,657
Transportation commitment loss (b)		29		—			6,811		—
Contingency and environmental accrual adjustments		913		8,123			6,998		4,342
Well servicing operations (c)		5,169		(319	)		10,551		1,320
Foreign currency remeasurement and exchange losses (d)		1,249		(256	)		5,982		82
Inventory impairment (e)		291		—			1,894		—
Other		2,025		1,346			3,370		2,152
Bad debt expense		1,985		19,991			1,241		23,218
Rig impairment		—		—			—		3,382
Total other expense	$	21,363	$	33,964		$	89,467	$	54,153

(a) Represents stacked drilling rig costs under contractual drilling rig commitments and costs incurred to terminate contractual drilling rig commitments prior to their contractual maturities.

(b) Primarily represents transportation contract deficiency payment obligations not supported by future production.

(c) Represents idle well servicing costs.

(d) The Company’s operations in Africa periodically recognize monetary assets and liabilities in currencies other than their functional currencies. Associated therewith, the Company realizes foreign currency remeasurement and transaction gains and losses.

(e) Represents impairment charges to reduce the carrying value of excess lease and well equipment and supplies inventories to their estimated net realizable values.

NOTE Q.     Insurance Claims

As a result of Hurricane Rita in September 2005, the Company’s East Cameron facility, located in the Gulf of Mexico shelf, was destroyed. As of September 30, 2009, the Company estimates that it will cost approximately $4 million to $5 million to complete the reclamation and abandonment of the East Cameron facility. The operations to reclaim and abandon the East Cameron facilities began in January 2007. The estimate of the remaining costs to reclaim and abandon the East Cameron facility is based upon an estimate by the Company.

The Company has expended approximately $196.2 million on the reclamation and abandonment of the East Cameron facility through September 30, 2009. During the three and nine months ended September 30, 2009, the Company recorded charges of $1.2 million and $16.2 million, respectively, to hurricane activity, net in the accompanying statements of operations to increase its estimate of the total costs to reclaim and abandon the East Cameron facility.

The Company filed a claim with its insurance providers regarding the loss at East Cameron. Under the Company’s insurance policies, the East Cameron facility had the following coverages: (a) $14 million of scheduled property value for the platform, which was received in 2005, (b) $4 million of scheduled business interruption insurance after a deductible waiting period, which was received in 2006, (c) $100 million of well restoration and safety, in total, for all assets per occurrence and (d) $400 million for debris removal coverage for all assets per occurrence.

During the nine months ended September 30, 2009, the Company received $29.7 million from one of its insurance providers related to debris removal, for which the Company had previously recorded a receivable. At the present time, no recoveries have been reflected related to certain costs associated with plugging and abandonment and the well restoration and safety coverages. In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues, primarily related to debris removal, certain costs associated with plugging and abandonment, and the well restoration and safety coverages. The Company believes that a substantial portion of the loss will be recoverable from insurance.

40

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2009

(Unaudited)

NOTE R.    Discontinued Operations

During the three months ended June 30, 2009, the Company committed to a plan to sell its shelf properties in the Gulf of Mexico and sold its Mississippi assets. The Company completed the sale of substantially all of its shelf properties in the Gulf of Mexico on August 6, 2009. As of September 30, 2009, the Company had $1.8 million of asset retirement obligations attributable to certain unsold shelf properties in the Gulf of Mexico that are classified as discontinued operations available for sale in the accompanying consolidated balance sheet as of September 30, 2009. The Company had no asset carrying values attributable to these unsold properties as of September 30, 2009, and expects to complete its plans to divest the properties during the fourth quarter of 2009 or the first half of 2010. The Company has reflected the results of operations of these properties as discontinued operations, rather than as a component of continuing operations, in the accompanying consolidated statements of operations. Additionally, in April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries. During the three and nine months ended September 30, 2008, the Company continued to realize certain net costs and expense increments associated with these divestitures. The following table represents the components of the Company’s discontinued operations for the three and nine month periods ended September 30, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in thousands)
Revenues and other income:
Oil and gas	$	2,000		$	11,787		$	13,722		$	46,406
Interest and other		—			146			—			2,135
Gain (loss) on disposition of assets, net (a)		17,823			—			18,129			(6	)
		19,823			11,933			31,851			48,535
Costs and expenses:
Oil and gas production		477			2,384			5,126			5,659
Production and ad valorem taxes		(155	)		95			(37	)		309
Depletion, depreciation and amortization (a)		1			6,202			3,863			13,620
Exploration and abandonments (a)		7			1,655			290			7,127
General and administrative		144			225			108			440
Accretion of discount on asset retirement obligations (a)		89			199			531			597
Other		—			338			—			(51	)
		563			11,098			9,881			27,701
Income from discontinued operations before income taxes		19,260			835			21,970			20,834
Income tax provision:
Current		—			(135	)		—			(306	)
Deferred (a)		(7,153	)		(373	)		(8,102	)		(5,811	)
Income from discontinued operations	$	12,107		$	327		$	13,868		$	14,718

(a) Represents the significant noncash components of discontinued operations.

NOTE S.    Subsequent Events

In accordance with ASC 855 (formerly SFAS 165), the Company has evaluated subsequent events through November 5, 2009, the date of issuance of the unaudited consolidated financial statements. The Company is not aware of any reportable subsequent events through November 5, 2009, except as disclosed in Note J.

41

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 2009 included the following highlights:

• Earnings attributable to common stockholders was a net loss of $7.2 million ($.06 per diluted share), as compared to net loss attributable to common stockholders of $5.2 million ($.04 per diluted share) for the third quarter of 2008. The decrease in earnings attributable to common stockholders is primarily due to:

• A decline in oil and gas revenues due to NGL and gas price declines, partially offset by increases in oil price and sales volumes,

• $13.4 million of third quarter 2009 net unrealized derivative losses recorded under the mark-to-market accounting method and

• Negative price revisions to proved reserves associated with the commodity price declines, which increased depreciation, depletion and amortization expense, partially offset by

• Oil and gas production cost declines resulting from the Company’s cost reduction initiatives,

• Production and ad valorem tax declines, primarily due to commodity price declines and

• A decline in impairment of oil and gas properties, associated with impairment of the Company’s Uinta/Piceance assets during the third quarter of 2008.

• Daily sales volumes from continuing operations increased on a per-BOE basis by two percent to 112,623 BOEPD during the third quarter of 2009, as compared to 110,538 BOEPD during the third quarter of 2008. The increase in third quarter 2009 sales volumes, as compared to the third quarter of 2008, was primarily due to September 2008 production curtailments as a result of damage caused by Hurricanes Gustav and Ike to third-party NGL fractionation facilities.

• Average reported oil, NGL and gas prices from continuing operations decreased during the third quarter of 2009 to $78.20 per Bbl, $33.13 per Bbl and $3.64 per Mcf, respectively, as compared to respective prices of $80.37 per Bbl, $62.23 per Bbl and $7.98 per Mcf during the third quarter of 2008.

• Average oil and gas production costs and total ad valorem and production taxes per BOE from continuing operations decreased during the third quarter of 2009 to $8.72 and $2.71, respectively, as compared to respective costs of $10.55 and $4.53 per BOE during the third quarter of 2008, primarily as a result of cost reduction initiatives and commodity price declines.

Commodity prices. During the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. During this same time period, North American gas supply was increasing as a result of the rise in domestic unconventional gas production. The combination of lower energy demand due to the economic slowdown and higher North American gas supply resulted in significant declines in oil, NGL and gas prices during the second half of 2008 and continued into early 2009. Beginning in the second quarter of 2009, oil and NGL prices have generally been increasing, while gas prices have remained volatile. Although the Company has entered into derivative contracts on a large portion of its production volumes through 2011, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company’s internal cash flows would be reduced for affected periods. The timing and magnitude of commodity price declines or recoveries cannot be predicted. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively impact the Company’s liquidity, financial position and future results of operations. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information about the Company’s derivative contracts.

Cost reduction initiatives. During the fourth quarter of 2008, the Company implemented initiatives to reduce capital spending, operating costs and administrative expenses to support its goal of delivering net cash flow from operating activities in excess of capital requirements in 2009 and to enhance and preserve financial flexibility. These initiatives include minimizing drilling activities until margins improve as a result of (i) commodity prices increasing and/or (ii) well cost reductions. As a result, the Company significantly reduced its 2009 rig activity and has realized and continues to pursue reductions in operating expenses and well costs to align costs with a lower commodity price environment. Rigs have been terminated or stacked in the Spraberry, Raton, Edwards Trend and

42

PIONEER NATURAL RESOURCES COMPANY

Barnett Shale areas and in Tunisia. Since the third quarter of 2008, when drilling and completion costs peaked, the Company has achieved an average reduction of approximately 30 percent in the cost of drilling and completing a well in the Spraberry field of West Texas. The Company’s asset teams have also implemented initiatives that have reduced 2009 lease operating expense per BOE from continuing operations by 22 percent during the third quarter of 2009, as compared to the third quarter of 2008. The cost savings reflect reductions in electricity, water disposal and compression rental costs and an expansion of the Company’s use of internal well services.

As a result of the successes realized from the aforementioned cost reduction initiatives and increases in 2009 oil prices, the Company is implementing a plan to resume oil- and liquids-rich-gas-focused drilling activities during 2010 and has preliminarily targeted its 2010 capital budget to be in a range of $800 million to $900 million (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs). The Company’s 2009 annual capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) are expected to total approximately $300 million. During the first nine months of 2009, the Company’s capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $224 million, as compared to $947 million during the first nine months of 2008, representing a 76 percent decrease.

Fourth Quarter 2009 Outlook

Based on current estimates, the Company expects that fourth quarter 2009 production will average 105,000 to 110,000 BOEPD, reflecting reduced 2009 drilling activity, downtime associated with a gas plant maintenance shutdown in South Africa and gas pipeline repairs and variability in the timing of oil cargo shipments in Tunisia.

Fourth quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $11.50 to $13.50 per BOE, based on NYMEX strip prices for oil, NGLs and gas. Production costs are expected to be impacted by higher production, lower production volumes and increased workover activity. Depletion, depreciation and amortization (“DD&A”) expense is expected to average $15.50 to $17.00 per BOE based on the new SEC reserve pricing methodology that is expected to be implemented during the fourth quarter of 2009.

Total exploration and abandonment expense for the quarter is expected to be $20 million to $30 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs. General and administrative expense is expected to be $35 million to $39 million. Interest expense is expected to be $42 million to $45 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ net income is expected to be $8 million to $10 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company also expects to recognize $5 million to $10 million of charges in other expense associated with certain drilling rigs being stacked as a result of the low commodity price environment.

The Company’s fourth quarter effective income tax rate is expected to range from 40 percent to 50 percent, assuming current capital spending plans, higher tax rates in certain foreign jurisdictions and no significant mark-to-market changes in the Company’s derivative position. Cash income taxes are expected to range from $10 million to $15 million, principally related to Tunisian income taxes.

Fourth quarter 2009 amortization of deferred hedge gains on discontinued and terminated oil and gas hedges is expected to be $25 million.

Operations and Drilling Highlights

The Company intends to limit 2009 capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, to internally-generated operating cash flow. During the nine month period ended September 30, 2009, cash flow from operating activities was $410.8 million and the Company’s capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, were $224.2 million.

43

PIONEER NATURAL RESOURCES COMPANY

The following table summarizes by geographic area the Company’s finding and development costs incurred during the nine month period ended September 30, 2009:

	Acquisition Costs					Exploration Costs		Development Costs			Asset Retirement Obligations		Total
	Proved		Unproved
	(in thousands)
United States:
Permian Basin	$	3,586	$	5,971		$	6,686	$	72,971		$	1	$	89,215
Mid-Continent		—		—			352		2,852			—		3,204
Rocky Mountains		58		1,038			10,854		19,220			—		31,170
Barnett Shale		367		1,368			12,048		446			—		14,229
Gulf of Mexico		—		—			304		(36	)		—		268
Onshore Gulf Coast		4,224		33,685			24,105		856			328		63,198
Alaska		—		(347	)		2,876		79,072			38		81,639
		8,235		41,715			57,225		175,381			367		282,923
South Africa		65		—			403		910			—		1,378
Tunisia		—		—			16,521		10,291			—		26,812
Other		—		—			724		—			—		724
		65		—			17,648		11,201			—		28,914
Total Worldwide	$	8,300	$	41,715		$	74,873	$	186,582		$	367	$	311,837

The following table summarizes the Company’s development and exploration/extension drilling activities for the nine months ended September 30, 2009:

	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
United States	7	22	27	—	2
Tunisia	—	1	—	—	1
Total Worldwide	7	23	27	—	3

	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
United States	10	9	8	2	9
Tunisia	5	1	—	3	3
Total Worldwide	15	10	8	5	12

Permian Basin area. In the Spraberry field, production averaged 31,827 BOEPD and 34,520 BOEPD during the three and nine months ended September 30, 2009, respectively, representing associated increases of six percent and thirteen percent, as compared to the same periods of 2008. As a result of the Company’s reduced 2009 capital budget, the Company only completed four additional wells in the Spraberry field during the three months ended September 30, 2009. During the nine months ended September 30, 2009, the Company completed 21 Spraberry field wells. The Company expects to drill a total of 44 to 48 wells during 2009 in the Spraberry field. The Company resumed drilling in the Spraberry field in August and has three rigs operating in the area. The Company has plans to add 11 additional rigs by year end, increasing to 19 rigs by mid-2010 and 24 rigs by the end of 2010.

The Company plans to drill approximately 425 Spraberry wells during 2010. The majority of the Spraberry wells will be drilled deeper to add the Wolfcamp formation, which provides incremental production and proved reserve potential. Substantial declines in well costs, new oil price derivatives and forward market prices for oil exceeding $70 per Bbl are supportive of the Company’s plan to increase drilling activities during the fourth quarter of 2009 through 2010.

44

PIONEER NATURAL RESOURCES COMPANY

During 2008, the Company initiated a program to test 20-acre well down spacing performance as part of its announced recovery improvement initiatives, which also include secondary recovery waterflood projects, shale/silt interval testing and horizontal well initiative opportunities in the Spraberry field. The Company continues to monitor the 20-acre pilot wells and their offsets with available data. The Company drilled a total of twenty 20-acre wells prior to 2009. With all 20 wells on production, the results are encouraging and will continue to be monitored before determining future plans for 20-acre drilling.

The Company also plans to implement a 7,000-acre waterflood project in the Spraberry field during 2010.

The 20-acre well spacing, waterflood project and other initiatives described above are being performed to enhance hydrocarbon recovery, as a percentage of oil in place, in those areas of the Spraberry field that are expected to be conducive for these undertakings. However, the ultimate incremental recovery rates associated with these initiatives cannot be predicted at this time.

Mid-Continent area. In the Hugoton and West Panhandle fields, 2009 daily production averaged 17,683 BOEPD and 18,215 BOEPD during the three and nine months ended September 30, 2009, respectively, representing respective decreases of six percent and seven percent, as compared to the same periods of 2008. Third quarter 2009 production was negatively impacted by unplanned third-party pipeline repairs. The Company continues to achieve production benefits in both the Hugoton and West Panhandle fields through gathering system efficiencies and improved system surveillance.

In the Hugoton field, the Company has completed its testing of both re-completed and new drill wells that are commingled in the Chase and Council Grove formations. Future development plans will incorporate further expansion of this activity in the field. In the West Panhandle field, the Company is not planning any 2009 development drilling in support of the Company’s cost reduction initiatives. The Company is planning to maximize operating results in the field through well recompletions, fracture stimulations and continued replication of its successful lateral well cleanout program.

Rocky Mountain area. The Company’s Raton Basin production volumes averaged 31,525 BOEPD and 31,426 BOEPD during the three and nine months ended September 30, 2009, respectively, representing respective declines of six percent and four percent, as compared to the same periods of 2008. The Company has been able to maintain relatively stable production, with low rates of decline, through initiatives such as compressor upgrades and optimization of compressor configurations. Future drilling operations will resume once gas prices and drilling costs stabilize allowing the Company to achieve targeted rates of return.

South Texas area. In South Texas, the Company’s production volumes averaged 10,833 BOEPD and 12,688 BOEPD during the three and nine months ended September 30, 2009, respectively. Production volumes during the third quarter of 2009 decreased by 16 percent, as compared to the third quarter of 2008, primarily due to reduced drilling expenditures in support of the aforementioned cost reduction initiatives and normal well declines. Production volumes for the nine months ended September 30, 2009 increased by four percent as compared to the nine months ended September 30, 2008.

The Company has a substantial number of Edwards play locations in inventory for development of the previously discovered Moray, Sawfish, Skipjack and Amberjack fields, as well as several as yet undrilled exploration prospects. Drilling activity in the Edwards play will resume when forecasted operating margins increase to a level that provides adequate economic returns on drilling. In the meantime, the Company continues to maintain its strong position in South Texas through both the renewal of existing leases and the acquisition of new leases.

During the third quarter of 2009, the Company began drilling the recently announced Sinor#5 well. This well was designed to delineate the potential of the Eagle Ford play in an unexplored area while taking advantage of the technical knowledge gained through the Edwards wells in the area that were drilled through the Eagle Ford shale horizon. The well flowed at an initial rate of approximately 11.3 MMcf-equivalent per day (“MMCFEPD”) of gas (approximately 8.3 MMCFEPD of liquids-rich gas and 500 BOEPD of higher-valued condensate). As a result of the success of the well, the Company intends to expand its multi-well Eagle Ford drilling program to continuously operate one rig in the play through 2010 and test the benefits of longer laterals and additional fracture-stimulation stages. The Company is also exploring joint venture opportunities to accelerate Eagle Ford Shale development operations. The Eagle Ford Shale play is prospective over much of the 310,000 acres that the Company currently holds.

In order to accommodate its Edwards Trend and Eagle Ford Play growth, the Company added additional gas gathering and processing infrastructure during 2008. The expansion includes over 28 miles of gathering system pipeline, three additional operated gas treatment plants and two additional non-operated gas treatment plants.

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PIONEER NATURAL RESOURCES COMPANY

Barnett Shale. In the Barnett Shale area of Texas, the Company’s production volumes averaged 2,937 BOEPD and 3,061 BOEPD during the three and nine months ended September 30, 2009, respectively, representing respective increases of 46 percent and 44 percent, as compared to the same periods of 2008. During the third quarter of 2009, the Company continued to improve operational performance including multiple successful well workovers and an increase in the capacity of the Company’s water disposal system. During 2009, the Company participated in four non-operated successful wells, with three additional wells drilled and awaiting completion at quarter end, and is preparing to commence a 3-D seismic shoot over a portion of its acreage in the fourth quarter of 2009.

Alaska area. During the first three quarters of 2009, the Company continued drilling activities at its Oooguruk development project. The Company’s production from the project, which began in June 2008, averaged 5,530 BOPD and 4,271 BOPD during the three and nine months ended September 30, 2009, respectively. The Company drilled five horizontal wells within the project’s Nuiqsut reservoir during the second and third quarters, of which three were fracture-stimulated production wells and two were unstimulated water injection wells. Early results from the first three fracture-stimulated production wells, which had a combined initial flow rate of 7,400 BOPD, suggest that stabilized production may be as much as two-to-three times that of an unstimulated injector.

On the Company’s Cosmopolitan Unit project in the Cook Inlet, the Company drilled a lateral sidetrack during 2007 from an existing wellbore on an onshore site to further appraise the resource potential of the unit. The initial un-stimulated production test results were encouraging. The Company plans workover operations on the well in the fourth quarter of 2009 to repair the casing. The well may be fracture-stimulated in 2010, contingent upon the results of the casing repair and subsequent flow testing. The Company will continue to conduct permitting activities and facilities planning during the fourth quarter of 2009 and may drill another appraisal well during 2010.

South Africa. In South Africa, the Company’s production averaged 5,803 BOEPD and 5,674 BOEPD during the three and nine months ended September 30, 2009, respectively, representing increases of 52 percent and 51 percent, as compared to the same periods of 2008. The substantial increases in production are reflective of the commencement of production from the most prolific well in Pioneer’s South Coast Gas project during the fourth quarter of 2008. First production from the Company’s Sable gas well was initiated in mid-October 2008 and the other wells in the South Coast Gas project resumed production in late-October. The operator of the South Coast Gas project began a major plant maintenance shutdown on September 24, 2009 at the Mossel Bay gas-to-liquids plant where the gas production is sold. The plant turnaround is expected to be completed and the plant back to full production capacity in early November. As a result, fourth quarter forecasted production is expected to be reduced by approximately 2,000 BOEPD.

In addition, the operator has also notified the Company that past production volumes reported for the South Coast Gas project were (in the operator’s view) overstated due to potential meter measurement errors. During June 2009, the operator commenced reporting volumes for the Company’s account from the South Coast Gas project at the reduced amount. The Company is awaiting further technical information from the operator in order to assess the extent of the errors, if any, and will be working closely with the operator and metering specialists during the fourth quarter of 2009 and early 2010 to validate the operator’s position and better understand any metering errors to ensure that the Company has received, and will receive, its appropriate share of gas production from the South Coast Gas project. The Company does not expect that the resolution of this matter will have a material impact on its liquidity, results of operations or financial position.

Tunisia. The Company’s two production concessions in Southern Tunisia averaged 6,485 BOEPD and 6,890 BOEPD of production during the three and nine months ended September 30, 2009, respectively, representing a decrease of 12 percent in the quarter-to-quarter comparison and an increase of 13 percent in the year-to-date comparison. In the Company-operated Cherouq Concession, production averaged 4,359 BOEPD during the nine months ended September 30, 2009, representing an increase of 58 percent, as compared to the same period of 2008. During 2009, the Company is completing the processing of the 295 square kilometers of 3-D seismic data acquired in 2008. The geosciences work program includes the integration of existing geologic data sets into a comprehensive basin modeling project targeted at reducing uncertainty and high-grading prospective exploration and development locations. Plans are currently underway to drill three wells in early-2010. Additionally, the Company is in the process of upgrading its existing production facilities by installing permanent equipment that is expected to reduce production costs.

During the fourth quarter of 2009, the Company plans to continue its exploratory and appraisal activities on the Adam Concession by participating in up to two non-operated wells. The Company also plans to begin a 3-D seismic acquisition program on the Borj El Khadra Permit during 2010.

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PIONEER NATURAL RESOURCES COMPANY

In the Anaguid permit, the Company has prepared a plan of development in order to request approval to convert 308 square kilometers of the existing exploration permit into a production concession. Additionally, the Company plans to complete the interpretation of the previously acquired seismic data and drill an additional exploration well during early-2010.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $410.0 million and $1.1 billion for the three and nine months ended September 30, 2009, as compared to $600.4 million and $1.8 billion for the same respective periods of 2008.

The decrease in oil and gas revenues from continuing operations during the three and nine months ended September 30, 2009, as compared to the same periods of 2008, is reflective of decreases in revenues for all geographic operating segments. The decrease in revenues in the United States was due to decreases in average reported NGL and gas prices, partially offset by increases in average reported oil prices and sales volume increases. United States average daily sales volumes increased during the three months ended September 30, 3009, as compared to the three months ended September 30, 2008, primarily due to a six percent decrease in scheduled VPP deliveries. United States average daily sales volumes during the nine months ended September 30, 2009 increased as compared to the nine months ended September 30, 2008, primarily as a result of successful 2008 drilling activity, sales of approximately 876 BOEPD of NGLs that were in storage as of December 31, 2008 and a seven percent reduction in scheduled VPP deliveries. Revenues in Tunisia decreased due to decreases in average reported oil and gas prices during the three and nine months ended September 30, 2009, as compared to the three and nine months ended September 30, 2008. Tunisian sales volumes also declined during the three months ended September 30, 2009 as compared to the three months ended September 30, 2008, primarily due to decreases in drilling activity in support of the Company’s cost reduction initiatives and normal well declines. Tunisian average daily sales volumes increased during the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008, primarily due to the 2008 drilling program. Revenues in South Africa decreased during the three and nine months ended September 30, 2009, as compared to the same periods during 2008, due to decreases in average reported oil and gas prices, partially offset by increases in average daily gas sales volumes due to the initiation of gas production from the Sable field in the fourth quarter of 2008.

The following table provides average daily sales volumes from continuing operations, by geographic area and in total, for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
Oil (Bbls):
United States	24,754	19,824	24,989	19,919
South Africa	575	2,995	401	2,879
Tunisia	6,334	6,831	6,612	5,705
Worldwide	31,663	29,650	32,002	28,503
NGLs (Bbls):
United States	18,602	18,884	20,044	19,568
Gas (Mcf):
United States	341,874	364,357	360,896	365,438
South Africa	31,372	4,956	31,637	5,199
Tunisia	904	2,709	1,662	2,303
Worldwide	374,150	372,022	394,195	372,940
Total (BOE):
United States	100,335	99,434	105,182	100,394
South Africa	5,803	3,821	5,674	3,746
Tunisia	6,485	7,283	6,890	6,089
Worldwide	112,623	110,538	117,746	110,229

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PIONEER NATURAL RESOURCES COMPANY

The following table provides average daily sales volumes from discontinued operations, by geographic area and in total, for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2009	2008	2009	2008
Oil (Bbls):
United States	266	756	741	1,093
NGLs (Bbls):
United States	42	37	38	42
Gas (Mcf):
United States	1,085	3,041	2,534	4,063
Total (BOE):
United States	489	1,300	1,202	1,812

On a quarter-to-quarter BOE comparison, average daily sales volumes increased by one percent in the United States and by 52 percent in South Africa, but decreased by 11 percent in Tunisia. For the nine months ended September 30, 2009, as compared to the nine months ended September 30, 2008, average daily BOE sales volumes increased by 5 percent in the United States, by 51 percent in South Africa and by 13 percent in Tunisia.

During the three and nine month periods ended September 30, 2009, as compared to the three and nine month periods ended September 30, 2008, oil volumes delivered under the Company’s VPPs decreased by 38 MBbl (5 percent) and 119 MBbl (5 percent), respectively, while gas volumes delivered under the Company’s VPPs decreased by 230 MMcf (8 percent) and 713 MMcf (9 percent), respectively.

The oil, NGL and gas prices that the Company reports are based on the market price received for the commodities, adjusted by the results of the Company’s cash flow hedging activities prior to February 1, 2009 and the amortization of deferred VPP revenue.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides average reported prices from continuing operations (including the results of hedging activities and the amortization of deferred VPP revenue) and average realized prices from continuing operations (excluding the results of hedging activities and the amortization of deferred VPP revenue) by geographic area and in total, for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Average reported prices:
Oil (per Bbl):
United States	$	81.57	$	69.10	$	70.13	$	69.32
South Africa	$	70.30	$	107.89	$	63.08	$	113.39
Tunisia	$	65.76	$	101.01	$	56.83	$	109.38
Worldwide	$	78.20	$	80.37	$	67.29	$	81.79
NGL (per Bbl):
United States	$	33.13	$	62.23	$	27.33	$	57.41
Gas (per Mcf):
United States	$	3.42	$	7.92	$	3.69	$	8.09
South Africa	$	5.93	$	8.10	$	5.08	$	8.09
Tunisia	$	9.35	$	15.67	$	7.22	$	14.29
Worldwide	$	3.64	$	7.98	$	3.82	$	8.13
Average realized prices:
Oil (per Bbl):
United States	$	61.19	$	117.40	$	49.33	$	112.44
South Africa	$	70.30	$	107.89	$	63.08	$	113.39
Tunisia	$	65.76	$	101.01	$	56.83	$	109.38
Worldwide	$	62.27	$	112.67	$	51.05	$	111.92
NGL (per Bbl):
United States	$	31.75	$	63.07	$	26.04	$	58.09
Gas (per Mcf):
United States	$	2.95	$	8.36	$	3.10	$	8.40
South Africa	$	5.93	$	8.10	$	5.08	$	8.09
Tunisia	$	9.35	$	15.67	$	7.22	$	14.29
Worldwide	$	3.22	$	8.41	$	3.28	$	8.43

Derivative activities. The Company utilizes commodity swap, collar and 3-way collar contracts in order to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. Prior to February 1, 2009, the Company accounted for substantially all of its derivative activity using hedge accounting, which requires that the effective portions of changes in the fair values of the Company’s commodity price hedges be deferred as increases or decreases to AOCI – Hedging until the underlying hedged transaction occurs. Consequently, changes in the effective portions of commodity price hedges added volatility to the Company’s reported stockholders’ equity until the hedge derivative either matured or was terminated. Effective February 1, 2009, the Company discontinued hedge accounting on all of its existing derivative instruments and since that date has accounted for its derivative instruments using the mark-to-market accounting method. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for the scheduled amortization of net deferred gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil and gas revenues.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides the net effect of settlements of oil, NGL and gas price hedges on oil and gas revenue from continuing operations for the three and nine month periods ended September 30, 2009 and 2008:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
	(in thousands)
Increase (decrease) to oil revenue from hedging activity	$	21,668	$	(114,203	)	$	67,928	$	(313,469	)
Increase (decrease) to NGL revenue from hedging activity		2,364		(1,450	)		7,042		(3,669	)
Increase (decrease) to gas revenue from hedging activity		2,229		(28,377	)		21,203		(71,106	)
Total	$	26,261	$	(144,030	)	$	96,173	$	(388,244	)

Deferred revenue. During the three and nine months ended September 30, 2009 and 2008, the Company’s amortization of deferred VPP revenue increased oil and gas revenues by $37.2 million and $110.9 million, respectively, as compared to increases of $39.7 million and $118.6 million during the same respective periods of 2008. See Notes G and N of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s VPPs.

Interest and other income. Interest and other income for the three and nine month periods ended September 30, 2009 was $0.5 million and $99.8 million, respectively, as compared to $2.3 million and $33.7 million for the same respective periods in 2008. The decrease in interest and other income from continuing operations during the three months ended September 30, 2009, as compared to the same period in 2008, was primarily due to decreases in foreign currency remeasurement and exchange gains. The increase in interest and other income from continuing operations during the nine months ended September 30, 2009, as compared to the same period in 2008, was primarily due to an increase of $77.2 million in Alaskan petroleum production tax credits. See Note O of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding interest and other income.

Oil and gas production costs. The Company recorded oil and gas production costs of $90.4 million and $285.6 million during the three and nine months ended September 30, 2009, respectively, as compared to $107.2 million and $297.3 million during the same respective periods of 2008. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company’s gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE from continuing operations decreased by 17 percent and 10 percent during the three and nine months ended September 30, 2009, respectively, as compared to the same periods in 2008. During 2008, the Company’s oil and gas production costs increased throughout the first nine months of the year, primarily due to inflation of well servicing expense, electricity expense and water hauling costs. As a result of the Company’s cost reduction initiatives that were started in late 2008 and continue in 2009, Pioneer has realized significant production cost reductions during the first three quarters of 2009, as compared to similar costs in 2008, and anticipates continued cost savings in the foreseeable future. The decrease in South Africa production costs is directly attributable to the shut in of the Sable oil field, which had a high fixed-cost component of production costs as compared to the South Coast Gas project, which has significantly lower production costs. The increase in Tunisia production costs is associated with the start-up of Cherouq production using rental facilities. Tunisia production costs are expected to decline with the installation of permanent facilities.

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PIONEER NATURAL RESOURCES COMPANY

The following tables provide the components of the Company’s oil and gas production costs per BOE from continuing operations and total production costs per BOE from continuing operations by geographic area for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
Lease operating expenses	$	6.91	$	8.87		$	7.09	$	8.14
Third-party transportation charges		0.91		1.14			0.93		1.08
Net natural gas plant/gathering charges		0.27		(0.34	)		0.29		(0.16	)
Workover costs		0.63		0.88			0.58		0.77
Total production costs	$	8.72	$	10.55		$	8.89	$	9.83
	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
United States	$	9.12	$	10.06		$	8.96	$	9.26
South Africa	$	1.54	$	29.55		$	3.08	$	28.00
Tunisia	$	9.20	$	7.22		$	12.38	$	8.45
Worldwide	$	8.72	$	10.55		$	8.89	$	9.83

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $28.1 million and $79.5 million during the three and nine month periods ended September 30, 2009, respectively, as compared to $46.1 million and $129.7 million for the same respective periods of 2008. In general, production taxes 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 commodity prices. Consequently, during the three and nine month periods ended September 30, 2009, the Company’s production taxes per BOE have declined 56 percent and 63 percent, respectively, reflecting the year-to-year decline in commodity prices, while ad valorem taxes have also decreased during the same period.

The following table provides the Company’s production and ad valorem taxes per BOE from continuing operations and total production and ad valorem taxes per BOE from continuing operations for the three and nine month periods ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Ad valorem taxes	$	1.40	$	1.58	$	1.42	$	1.44
Production taxes		1.31		2.95		1.05		2.85
Total ad valorem and production taxes	$	2.71	$	4.53	$	2.47	$	4.29

Depletion, depreciation and amortization expense. The Company’s total DD&A expense was $162.6 million ($15.69 per BOE) and $509.4 million ($15.85 per BOE) for the three and nine months ended September 30, 2009, respectively, as compared to $121.3 million ($11.92 per BOE) and $338.2 million ($11.20 per BOE) during the same respective periods of 2008. The increase in DD&A expense during the three and nine months ended September 30, 2009, as compared to the same respective period of 2008, is primarily due to an increase in depletion of oil and gas properties.

In the reported results for the nine months ended September 30, 2009, the Company reduced its DD&A expense by $7.3 million to correct the overstatement of depletion expense attributable to oil and gas volumes sold during the three months ended June 30, 2009. See Note B of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding this correction.

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PIONEER NATURAL RESOURCES COMPANY

Depletion expense was $15.00 per BOE and $15.17 per BOE during the three and nine months ended September 30, 2009, as compared to $11.20 per BOE and $10.47 per BOE during the same respective periods of 2008. The 34 percent and 47 percent increases in per BOE depletion expense during the three and nine months ended September 30, 2009 are primarily due to (i) losing end-of-life reserves that became uneconomic as a result of commodity price declines since September 30, 2008, (ii) a generally increasing trend through 2008 in the Company’s oil and gas properties’ cost bases per BOE of proved and proved developed reserves as a result of cost inflation in drilling rig rates and drilling supplies and (iii) the relatively higher depletion rate per BOE associated with production from the Oooguruk development, which began first production in June 2008, and the South African South Coast Gas project, which became fully operational in October 2008.

The following table provides depletion expense per BOE from continuing operations by geographic area for the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
United States	$	13.97	$	11.60	$	14.42	$	10.69
South Africa	$	38.98	$	11.69	$	37.33	$	12.81
Tunisia	$	9.45	$	5.58	$	8.35	$	5.46
Worldwide	$	15.00	$	11.20	$	15.17	$	10.47

Impairment of oil and gas properties and other assets. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. The Company recognized impairment charges of $21.1 million and $89.8 million to reduce the carrying value of the Company’s oil and gas properties in the Uinta/Piceance areas during the three months ended March 31, 2009 and the three months ended September 30, 2008, respectively. Declines in gas prices and downward adjustments to the economically recoverable resource potential of the Company’s Uinta/Piceance oil and gas properties during the first quarter of 2009 and the third quarter of 2008 led to the impairment charges.

Commodity price declines and a significant decrease in the Company’s market capitalization during the second half of 2008 provided indications that the Company’s $310.6 million carrying value of goodwill may have been impaired as of December 31, 2008. The Company assessed the carrying value of goodwill for impairment as of December 31, 2008, March 31, 2009, June 30, 2009 and during the third quarter of 2009 and found it not to be impaired. However, goodwill remains at risk for impairment in future periods if commodity prices decline further or if other impairment indicators were to erode. See Note M of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s impairment assessments and the primary factors that impact the Company’s assessments of goodwill and oil and gas properties for impairment.

Exploration and abandonments expense. The following tables provide the Company’s geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense by geographic area for the three and nine months ended September 30, 2009 and 2008 (in thousands):

	United States		South Africa		Tunisia		Other		Total
Three Months Ended September 30, 2009
Geological and geophysical	$	9,766	$	114	$	2,160	$	141	$	12,181
Exploratory dry holes		4,048		—		2,750		—		6,798
Leasehold abandonments and other		6,094		—		—		—		6,094
	$	19,908	$	114	$	4,910	$	141	$	25,073
Three Months Ended September 30, 2008
Geological and geophysical	$	16,541	$	—	$	1,619	$	1,688	$	19,848
Exploratory dry holes		68,186		—		6,455		45		74,686
Leasehold abandonments and other		14,886		—		—		—		14,886
	$	99,613	$	—	$	8,074	$	1,733	$	109,420

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PIONEER NATURAL RESOURCES COMPANY

	United States		South Africa		Tunisia		Other		Total
Nine Months Ended September 30, 2009
Geological and geophysical	$	29,051	$	403	$	6,291	$	724	$	36,469
Exploratory dry holes		6,757		—		9,167		—		15,924
Leasehold abandonments and other		25,468		—		—		—		25,468
	$	61,276	$	403	$	15,458	$	724	$	77,861
Nine Months Ended September 30, 2008
Geological and geophysical	$	56,826	$	52	$	13,369	$	6,851	$	77,098
Exploratory dry holes		69,300		—		7,705		488		77,493
Leasehold abandonments and other		18,123		—		—		—		18,123
	$	144,249	$	52	$	21,074	$	7,339	$	172,714

The Company’s exploration and abandonment expense during the three and nine months ended September 30, 2009 is primarily attributable to geological and geophysical personnel costs, dry hole expense and unproved property abandonments. During the three months ended September 30, 2009, the Company’s exploration and abandonment expense included exploratory dry holes and leasehold abandonment expenses of $12.9 million, which is primarily comprised of $5.9 million of U.S. unproved property abandonments and $4.0 million and $2.8 million of dry hole provisions in the U.S. and Tunisia, respectively. During the nine months ended September 30, 2009, the Company’s exploration and abandonment expense included exploratory dry holes and leasehold abandonment expenses of $41.4 million, which is primarily comprised of $24.8 million of U.S. unproved property abandonments and $6.8 million and $9.2 million of dry hole provisions in the U.S. and Tunisia, respectively.

The Company’s exploration and abandonment expense from continuing operations during the three and nine month periods ended September 30, 2008 was primarily attributable to continued seismic activity in the Company’s Rockies, Permian Basin, South Texas and Tunisian areas, and dry hole expense and unproved property abandonments. During the three and nine month periods ended September 30, 2008, the Company’s exploration and abandonment expense included dry hole and leasehold abandonment and other exploration expenses of $89.6 million and $95.6 million, respectively, which were primarily comprised of the Company’s unsuccessful Lay Creek CBM pilot project, the unsuccessful Delaware Basin exploration project and the unsuccessful exploration well in South Texas.

During the nine months ended September 30, 2009, the Company drilled and evaluated 13 exploration/extension wells, eight of which were successfully completed as discoveries. During the same period in 2008, the Company drilled and evaluated 52 exploration/extension wells, 37 of which were successfully completed as discoveries. The decline in the number of exploration/extension wells drilled by the Company is primarily due to the Company’s significant reduction in its capital budget in support of cost reduction initiatives.

General and administrative expense. General and administrative expense for the three and nine months ended September 30, 2009 was $34.8 million and $102.7 million, respectively, as compared to $31.6 million and $103.7 million during the same respective periods of 2008. The increase in general and administrative expense during the three months ended September 30, 2009, as compared to the three months ended September 30, 2008, was primarily due to an increase in compensation expenses, including amortization of 2009 restricted stock awards, and a decline in administrative overhead recoveries from third parties. The decrease in general and administrative expense during the nine months ended September 30, 2009, as compared to the same period in 2008, was primarily due to the Company’s costs reduction initiatives, partially offset by an increase in compensation expenses and a decline in administrative overhead recoveries from third parties.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.8 million and $8.3 million for the three and nine months ended September 30, 2009, respectively, as compared to $2.0 million and $5.9 million during the same respective periods of 2008. The increase in accretion of discount on asset retirement obligations during 2009 is primarily due to the accretion of larger asset retirement obligations as a result of declining commodity prices having the effect of reducing the economic life of the Company’s wells, thus accelerating their forecasted abandonment date, as well as new wells placed on production. See Note H of Notes to Consolidated Financial Statements in “Item 1. Financial Statements” for information regarding the Company’s asset retirement obligations.

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PIONEER NATURAL RESOURCES COMPANY

Interest expense. Interest expense was $43.4 million and $128.1 million for the three and nine month periods ended September 30, 2009, respectively, as compared to $41.2 million and $123.1 million during the same respective periods of 2008. The weighted average interest rate on the Company’s indebtedness for the three and nine months ended September 30, 2009, including the effects of interest rate derivatives and capitalized interest, was 5.2 percent and 5.5 percent as compared to 5.5 percent for the same respective periods of 2008.

Effective January 1, 2009, the Company adopted the provisions of ASC 470 (formerly FSP ABP 14-1). The provisions of ASC 470 resulted in a retrospective adjustment to increase the Company’s 2008 interest expense for the three and nine months ended September 30 by $3.5 million and $9.7 million, respectively, and added $3.6 million and $10.7 million to the Company’s interest expense for the three and nine months ended September 30, 2009, respectively. See Notes B and F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s adoption of ASC 470.

The $2.3 million increase in interest expense during the three months ended September 30, 2009, as compared to the same period of 2008, was primarily due to a $2.0 million decrease in capitalized interest related to the Oooguruk project as completed wells are placed on production. The $5.0 million increase in interest expense during the nine months ended September 30, 2009, as compared to the same period of 2008, was primarily due to (i) a $7.7 million decrease in capitalized interest related to the Oooguruk project as completed wells are placed on production and (ii) a $5.3 million increase in interest rate hedge losses, partially offset by (iii) an $8.0 million decrease in cash interest expense on long-term borrowings.

Hurricane activity, net. The Company recorded net hurricane related activity expenses of $1.8 million and $18.3 million during the three and nine months ended September 30, 2009, respectively, as compared to $0.5 million and $2.4 million during the same respective periods of 2008. Hurricane activity, net is associated with the Company’s East Cameron platform facility, located on the Gulf of Mexico shelf, which was destroyed during 2005 by Hurricane Rita.

The Company estimates that it will expend approximately $4 million to $5 million to complete the operations to reclaim and abandon the East Cameron platform facilities during 2010. Since January 2007, the Company has expended approximately $196.2 million on operations to reclaim and abandon the East Cameron platform facilities. The Company’s remaining estimate to reclaim and abandon the East Cameron facilities is based upon an analysis prepared by the Company. During 2007, the Company commenced legal actions against its insurance carriers regarding certain policy coverage issues. The Company continues to expect that a substantial portion of the loss will be recoverable from insurance. During the first three quarters of 2009, the Company received $29.7 million of insurance recoveries associated with East Cameron facilities that reduced the Company’s recorded receivable for debris removal from one insurance carrier. The Company also received related insurance proceeds of $5.3 million during October 2009 from the same carrier. See Note Q of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s East Cameron facility reclamation and abandonment.

Derivative losses, net. Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments, and from that date forward has accounted for derivative instruments using the mark-to-market accounting method. Under the mark-to-market accounting method, the Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which the changes occur. During the three months ended September 30, 2009, the Company’s commodity price derivatives increased derivative losses, net by $15.2 million, of which amount $13.4 million represented unrealized losses subject to continuing market risk, and $1.8 million represented realized losses. During the nine months ended September 30, 2009, the Company’s commodity price derivatives increased derivative losses, net by $85.6 million, of which amount $120.9 million represented unrealized losses subject to continuing market risk, and $35.3 million represented realized gains.

Other expense. Other expense for the three and nine months ended September 30, 2009 was $21.4 million and $89.5 million, respectively, as compared to $34.0 million and $54.2 million for the same respective periods of 2008. The $12.6 million decrease in other expenses for the three months ended September 30, 2009, is primarily attributable to an $18.0 million decrease in bad debt expense, offset by a $5.5 million increase in idle well servicing operations costs. The $35.3 million increase in other expenses for the nine months ended September 30, 2009, as compared to the nine months ended September 30, 2008, is primarily attributable to (i) a $33.0 million increase in stacked and termination charges associated with drilling rig commitments, (ii) a $9.2 million increase in idle well servicing (iii) a $6.8 million increase in transportation commitment loss and (iv) a $5.9 million increase in foreign currency exchange losses, partially offset by (v) a $22.0 million decrease in bad debt expense. See Note P of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information.

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PIONEER NATURAL RESOURCES COMPANY

Income tax provision. The Company recognized income tax benefits from continuing operations of $5.2 million and $47.7 million during the three and nine months ended September 30, 2009, respectively, as compared to income tax provisions of $13.2 million and $217.6 million during the same respective periods of 2008. The income tax benefits during the three and nine months ended September 30, 2009, as compared to the income tax provisions of the respective 2008 periods, were primarily due to decreases in income from continuing operations before income taxes, reflecting the significant decline in commodity prices and noncash derivative losses associated with mark-to-market accounting. The Company’s effective tax rates on continuing operations of 21 percent and 28 percent during the three and nine months ended September 30, 2009, differ from the combined United States federal and state statutory rate of approximately 37 percent primarily due to:

• foreign tax rates,

• statutes in foreign jurisdictions that differ from those in the U.S.,

• a U.S. loss being consolidated with income in certain foreign jurisdictions with higher tax rates and

• expenses in foreign locations where the Company does not expect to receive income tax benefits, principally attributable to well costs in Tunisia.

In the reported results for the nine months ended September 30, 2009, the Company recognized an additional deferred provision of $2.9 million and a current tax benefit of $178 thousand related to the Company’s correction of the understatement of reported earnings for the three months ended June 30, 2009. See Notes B and E of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding this correction.

See Note E of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s income taxes.

Income from discontinued operations, net of tax. The Company reported income from discontinued operations, net of tax of $12.1 million and $13.9 million for the three and nine months ended September 30, 2009, respectively, as compared to $0.3 million and $14.7 million for the same respective periods of 2008. See Note R of the Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interest for the three and nine months ended September 30, 2009 was $9.0 million and $12.3 million, respectively, as compared to net income attributable to noncontrolling interest of $8.4 million and $15.4 million for the same respective periods of 2008. The $0.6 million increase and $3.1 million decrease in net income attributable to noncontrolling interest is primarily due to noncontrolling interests in the respective 2009 periods’ net income of Pioneer Southwest. See Note B of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding Pioneer Southwest and the Company’s noncontrolling interest in consolidated subsidiaries’ net income.

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 assets, payment of contractual obligations, dividends/distributions and working capital obligations. Funding for these cash needs, as well as funding for any stock or debt repurchases that the Company may undertake, may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets or external financing sources as discussed in “Capital resources” below. The Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internal operating cash flows and with its liquidity under its Credit Facility. Acquisitions may be funded with internal operating cash flows, the proceeds from debt or equity offerings or availability under the Company’s Credit Facility. Although the Company expects that internal operating cash flows will be adequate to fund capital expenditures and dividend/distribution payments, and that available borrowing capacity under the Company’s Credit Facility will 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.

The worldwide economic slowdown has negatively impacted the demand for energy and as a result, commodity prices have declined significantly since their highs in mid-2008. As a result of the significant decline in commodity prices, the Company implemented cost reduction initiatives to reduce capital spending, operating costs and general

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PIONEER NATURAL RESOURCES COMPANY

and administrative expenses to support its goal of delivering net cash flow from operating activities in excess of capital requirements in 2009 and to enhance and preserve financial flexibility. Specifically, the Company significantly reduced its 2009 rig activity and has realized significant reductions in operating expenses and well costs to better align costs with a lower commodity price environment. Rigs have been terminated or stacked in the Spraberry, Raton, Edwards Trend and Barnett Shale areas and in Tunisia.

As a result of the successes realized from the Company’s cost reduction initiatives and increases in 2009 oil prices, the Company is implementing a plan to resume oil- and liquids-gas-rich focused drilling activities during 2010 and has preliminarily targeted its 2010 capital budget to be in a range of $800 million to $900 million (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs). The Company’s 2009 annual capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) are expected to total approximately $300 million. During the first three quarters of 2009, the Company’s capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $224.2 million, as compared to $947.2 million during the first three quarters of 2008, representing a 76 percent decrease.

Investing activities. Investing activities used $313.0 million of cash during the nine months ended September 30, 2009, as compared to $884.7 million for the nine months ended September 30, 2008. The $571.7 million decrease in net cash used in investing activities is primarily due to a $676.8 million decrease in additions to oil and gas properties and a $14.0 million decrease in additions to other assets and other property and equipment, net; partially offset by a $119.1 million decrease in proceeds from the disposition of assets. During the nine months ended September 30, 2009, the Company’s expenditures for additions to oil and gas properties were funded by net cash provided by operating activities. During the nine months ended September 30, 2008, the Company’s expenditures for additions to oil and gas properties were funded by $816.5 million of net cash provided by operating activities, $143.4 million of proceeds from the disposition of assets and borrowings on the Company’s Credit Facility.

Dividends/distributions. During March 2009 and 2008, the Company’s board of directors (the “Board”) declared semiannual dividends of $0.04 per common share and $0.14 per common share, respectively. Associated therewith, the Company paid approximately $4.7 million and $16.9 million of aggregate dividends during April 2009 and 2008, respectively. During August 2009 and 2008, the Board declared semiannual dividends of $.04 per common share and $0.16 per common share, respectively. Associated therewith, the Company paid approximately $4.7 million and $19.2 million during October 2009 and 2008, respectively. 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, April, July and October 2009, the Pioneer Southwest board of directors (the “Pioneer Southwest Board”) declared quarterly distributions of $0.50 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $4.7 million in each of February, May and August 2009 and will pay $4.7 million on November 12, 2009 related to the October 2009 distribution declaration. During July and October 2008, the Pioneer Southwest Board declared $0.31 and $0.50 per limited partner unit distributions, respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $2.9 million and $4.7 million in August 2008 and November 2008, respectively. Future distributions are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the current distribution amount based on Pioneer Southwest’s liquidity and capital resources at the time.

Share repurchases. During February 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company’s common stock. During the nine months ended September 30, 2009 and 2008, the Company expended $16.3 million to acquire 1.0 million shares of treasury stock and $69.9 million to acquire 1.3 million shares of treasury stock, respectively, under share repurchase programs. As of September 30, 2009, $355.8 million of stock may be purchased in the future under the $750 million Board authorization.

Contractual obligations, including off-balance sheet obligations. The Company’s contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, other liabilities, transportation commitments and VPP obligations. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of September 30, 2009, the material off-balance sheet arrangements and transactions that the Company has entered into included (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling and transportation commitments, (iv) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future) 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. Other than the off-balance sheet arrangements described above, the Company has

56

no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. Since December 31, 2008, the material changes in the Company’s contractual obligations included a $31.9 million decrease in outstanding long-term borrowings, a $110.9 million decrease in the Company’s VPP obligations, a $142.7 million increase in the Company’s net derivative liabilities and a decrease of $52.6 million in the Company’s rig commitments. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s long-term debt and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for information regarding the interest on the Company’s long-term debt and a table of changes in the fair value of the Company’s open derivative obligations during the nine months ended September 30, 2009.

In accordance with GAAP, the Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading securities, deferred compensation plan assets, commodity derivative contracts and interest rate derivative contracts. See Note D of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding these assets and liabilities and the valuation techniques used to measure their fair values.

The Company’s commodity and interest rate derivative contracts that are periodically measured and recorded at fair value represent those derivatives that continue to be subject to market or credit risk. As of September 30, 2009, these contracts represented net liabilities of $73.6 million, including $25.4 million of terminated hedge liabilities that are no longer subject to market risk. The ultimate liquidation value of the Company’s commodity and interest rate derivatives that are subject to market risk 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, 2009. See Note G 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 do not meet the Company’s expectations, the Company may further 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 from other sources, such as asset sales.

Operating activities. Net cash provided by operating activities during the nine month period ended September 30, 2009 was $410.8 million, as compared to $816.5 million during the nine months ended September 30, 2008. The decrease in net cash provided by operating activities for the nine month period ended September 30, 2009 is primarily due to decreased oil, NGL and gas prices from continuing operations, partially offset by an increase in commodity sales volumes.

Asset divestitures. During June and August 2009, the Company sold its Mississippi assets and its shelf properties in the Gulf of Mexico, respectively, for a net gain of $17.8 million. Also during August 2009, Pioneer USA sold certain of its properties in the Spraberry Field in West Texas to Pioneer Southwest for proceeds of $171.2 million before normal closing adjustments. The transaction value also included the assignment of 2009 through 2013 commodity price derivative positions to Pioneer Southwest. Pioneer Southwest is a partially-owned and consolidated subsidiary of the Company. Consequently, the sale of the properties from Pioneer USA to Pioneer Southwest represented a transfer among entities under common control and did not reduce the Company’s oil and gas properties’ carrying values.

In November 2007, the Company sold all of the common stock of its Canadian subsidiaries for net proceeds of $525.7 million, $132.8 million of which was deposited in a Canadian escrow account pending receipt from the Canada Revenue Agency of appropriate tax certifications. The tax certifications were received in January 2008 and the escrowed funds were subsequently released to the Company. Proceeds from disposition of assets of $143.4 million for the first nine months of 2008 are primarily comprised of the receipt of the escrowed Canadian sales proceeds, net of foreign exchange differentials.

Financing activities. Net cash used in financing activities for the nine months ended September 30, 2009 was $90.6 million, as compared to $122.9 million of net cash provided by financing activities during the nine months ended September 30, 2008. The $213.5 million increase in cash used by financing activities during the nine months ended September 30, 2009, as compared to the nine months ended September 30, 2008, is primarily due to a $166.0 million decrease in Pioneer Southwest net proceeds from the issuance of limited partnership units and a $110.2 million decrease in net long-term borrowings, partially offset by a $64.4 million decrease in treasury stock purchases.

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PIONEER NATURAL RESOURCES COMPANY

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, 2009, the Company had $730 million of outstanding borrowings under the Credit Facility. Including $46 million of undrawn and outstanding letters of credit under the Credit Facility, the Company had approximately $724 million of unused borrowing capacity as of September 30, 2009. If internal cash flows do not meet the Company’s expectations, the Company may further 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 from other sources, such as asset sales. 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 cash flows will be adequate to fund capital expenditures and dividend payments, and that available borrowing capacity under the Company’s Credit Facility will provide adequate liquidity, no assurances can be given that such funding sources will be adequate to meet the Company’s future needs. For instance, the amount that the Company may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.

The Company’s Credit Facility is subject to certain covenants, including the maintenance of a PV Ratio. Effective April 29, 2009, the Company and its lenders amended the Credit Facility to provide the Company additional financial flexibility if longer-term commodity prices were to significantly deteriorate from current levels. The amendment reduced the required PV Ratio from 1.75 to 1.0 to 1.5 to 1.0 through the period ending March 31, 2011, after which time the ratio reverts to 1.75 to 1.0, and provides that the Company may include in the PV Ratio calculation 75 percent of the market value of its ownership of limited partner units of Pioneer Southwest.

Debt ratings. The Company receives debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s, which are subject to regular reviews. S&P’s rating for the Company is BB+ with a negative outlook. Moody’s rating for the Company is Ba1 with a negative outlook. The Company believes that S&P and Moody’s consider many factors in determining the Company’s ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in the Company’s debt ratings could negatively impact the Company’s ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. As of September 30, 2009, the Company was in compliance with all of its debt covenants.

Book capitalization and current ratio. The Company’s net book capitalization at September 30, 2009 was $6.4 billion, consisting of $55.6 million of cash and cash equivalents, debt of $2.9 billion and stockholders’ equity of $3.5 billion. The Company’s net debt to net book capitalization was 45 percent and 44 percent at September 30, 2009 and December 31, 2008, respectively. The Company’s ratio of current assets to current liabilities was 0.82 to 1.00 at September 30, 2009 as compared to 0.70 to 1.00 at December 31, 2008.

New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008. 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, 2008.

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, foreign exchange rates 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. All of the Company’s market risk sensitive instruments are entered into for purposes other than speculative.

Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments, and from that date forward has accounted for derivative instruments using the mark-to-market accounting method. Therefore, the Company will recognize all future changes in the fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

The following table reconciles the changes that occurred in the fair values of the Company’s open derivative contracts during the nine months ending 2009:

	Derivative Contract Net Assets (Liabilities)
	Commodities (a)			Interest Rate (a)			Commodity Unwinds			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2008	$	112,286		$	(9,903	)	$	(40,312	)	$	62,071
Changes in contract fair value (b)		(82,463	)		(3,120	)		—			(85,583	)
Contract maturities		(89,629	)		6,072			15,621			(67,936	)
Accretion of discount		—			—			(707	)		(707	)
Contract terminations		11,576			—			—			11,576
Fair value of contracts outstanding as of September 30, 2009	$	(48,230	)	$	(6,951	)	$	(25,398	)	$	(80,579	)

(a) Represents the fair values of open derivative contracts subject to market risk.

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

Interest rate sensitivity. See Note F 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.

The following table provides information about financial instruments to which the Company was a party as of September 30, 2009 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, 2009. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on November 2, 2009.

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	Three Months Ending December 31, 2009																				Liability Fair Value at September 30, 2009
				Year Ending December 31,
				2010			2011			2012			2013			Thereafter			Total
				($ in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	—		$	6,110		$	480,000		$	1,639,985		$	2,126,095	$	1,990,684
Weighted average interest rate		5.74	%		5.74	%		5.74	%		5.73	%		5.74	%		6.83	%
Variable rate principal maturities:
Pioneer Natural Resources Credit Facility	$	—		$	—		$	—		$	730,000		$	—		$	—		$	730,000	$	723,653
Weighted average interest rate		2.32	%		3.00	%		4.42	%		5.44	%
Pioneer Southwest Credit Facility	$	—		$	—		$	—		$	—		$	135,000		$	—		$	135,000	$	132,562
Weighted average interest rate		1.20	%		1.88	%		3.29	%		4.31	%		4.79	%
Interest Rate Swaps (b):
Credit Facility:
Notional debt amount (c)	$	450,000		$	277,222		$	75,000		$	50,000		$	50,000		$	50,000				$	6,951
Fixed rate payable (%)		2.87	%		2.97	%		3.00	%		—			—			—
Variable rate receivable (%)		0.32	%		1.00	%		2.42	%		—			—			—
Fixed rate receivable (%)		3.09	%		3.09	%		3.09	%		3.09	%		3.09	%		3.09	%
Variable rate payable (%)		0.32	%		1.00	%		2.42	%		3.44	%		3.92	%		4.13	%

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

(b) Subsequent to September 30, 2009, the Company terminated $50 million notional amount of fixed-for-variable rate swap contracts and $111 million notional amount of variable-for-fixed rate swap contracts.

(c) Represents weighted average notional contract amounts of interest rate derivatives.

Commodity price sensitivity. The following tables provide 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, 2009. Although mitigated by the Company’s derivative activities, declines in commodity prices will reduce Pioneer’s revenues and internal cash flows. Recent uncertainties in worldwide financial markets and recently proposed legislation restricting derivative activities may have the effect of reducing liquidity in the financial derivatives market, impeding the Company’s ability to enter into derivative contracts under acceptable terms.

Commodity derivative instruments. The Company manages commodity price risk with derivative contracts, such as swap and collar contracts. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum (“floor”) and maximum (“ceiling”) prices for the Company 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. With collar contracts, if the relevant market price is above the ceiling price, the Company pays the derivative counterparty the difference between the market price and the ceiling price; if the relevant market price is between the ceiling price and the floor price, the derivative has no cash settlement value; and, if the relevant market price is below the floor price, the Company receives the difference between the floor price and the market price from the counterparty. Collar contracts with short puts are similar to collar contracts, except that if the relevant market price is below the short put price, the Company receives the difference between the floor price and short put price from the counterparty.

See Note G 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.

60

PIONEER NATURAL RESOURCES COMPANY

	Three Months Ending December 31,			Year Ending December 31,												Asset (Liability) Fair Value at
	2009			2010			2011			2012			2013			September 30, 2009
																(in thousands)
Oil Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts		11,250			2,500			750			3,000			3,000		$	9,356
Weighted average fixed price per Bbl	$	63.41		$	93.34		$	77.25		$	79.32		$	81.02
Collar contracts		2,000			—			2,000			—			—		$	27,758
Weighted average ceiling price per Bbl	$	70.38		$	—		$	170.00		$	—		$	—
Weighted average floor price per Bbl	$	52.00		$	—		$	115.00		$	—		$	—
Collar contracts with short puts		15,000			25,000			25,000			1,000			1,250		$	(54,116	)
Weighted average ceiling price per Bbl	$	69.72		$	83.63		$	94.60		$	103.50		$	111.50
Weighted average floor price per Bbl	$	51.47		$	66.24		$	72.80		$	80.00		$	83.00
Weighted average short put price per Bbl	$	41.47		$	53.48		$	58.52		$	65.00		$	68.00
Average forward NYMEX oil prices (b)	$	78.71		$	82.12		$	85.36		$	87.27		$	88.96
NGL Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts		3,750			1,250			750			750			—		$	1,407
Weighted average fixed price per Bbl	$	34.28		$	47.38		$	34.65		$	35.03		$	—
Average forward Mont Belvieu NGL prices (c)	$	41.41		$	40.89		$	41.36		$	42.16		$	—
Gas Derivatives (a):
Average daily notional MMBtu volumes (b):
Swap contracts		137,500			152,295			2,500			2,500			2,500		$	30,800
Weighted average fixed price per MMBtu	$	6.13		$	6.42		$	6.65		$	6.77		$	6.89
Collar contracts		20,000			30,000			—			—			—		$	2,997
Weighted average ceiling price per MMBtu	$	5.90		$	7.52		$	—		$	—		$	—
Weighted average floor price per MMBtu	$	4.00		$	6.00		$	—		$	—		$	—
Collar contracts with short puts		150,000			95,000			175,000			50,000			—		$	(5,374	)
Weighted average ceiling price per MMBtu	$	5.35		$	7.94		$	8.69		$	8.81		$	—
Weighted average floor price per MMBtu	$	4.18		$	6.00		$	6.36		$	6.25		$	—
Weighted average short put price per MMBtu	$	3.18		$	5.00		$	4.93		$	4.50		$	—
Basis swap contracts		285,000			215,000			100,000			20,000			10,000		$	(61,058	)
Weighted average fixed price per MMBtu	$	(0.96	)	$	(0.77	)	$	(0.71	)	$	(0.78	)	$	(0.71	)
Average forward NYMEX gas prices (b)	$	4.82		$	5.54		$	6.48		$	6.80		$	7.01

(a) Subsequent to September 30, 2009, the Company entered into additional oil collar contracts with short puts for (i) 2,000 Bbls per day of the Company’s 2010 production with a ceiling price of $86.50 per Bbl, a floor price of $75.00 per Bbl and a short put price of $60.00 per Bbl, (ii) 9,000 Bbls per day of the Company’s 2011 production with a ceiling price of $107.37 per Bbl, a floor price of $75.00 per Bbl and a short put price of $60.00 per Bbl and (iii) 4,000 Bbls per day of the Company’s 2012 production with a ceiling price of $107.50 per Bbl, a floor price of $80.00 per Bbl and a short put price of $65.00 per Bbl. Subsequent to September 30, 2009, the Company unwound gas swap contracts for 24,795 MMBtu per day of the Company’s 2010 production at an average price of $5.56 per MMBtu.

(b) The average forward NYMEX oil and gas prices are based on November 2, 2009 market quotes.

(c) Forward Mont Belvieu NGL prices are not available as formal market quotes. These forward prices represent estimates as of October 30, 2009 provided by third parties who actively trade in the derivatives.

61

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 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 design and operation of the Company’s disclosure controls and procedures are effective at a reasonable assurance level 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 and 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 Company’s last fiscal quarter that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is party to the legal proceedings that are described under “Legal actions” in Note J of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.” The Company is also party to other proceedings and claims incidental to its business. While many of these other matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations.

Item 1A. Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Company’s Annual Report on Form 10-K under the headings “Item 1. Business – Competition, Markets and Regulations,” “Item 1A. Risk Factors” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” as updated by the discussions in Part II of the Company’s Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009, which risks could materially affect the Company’s business, financial condition or future results. There has been no material change in the Company’s risk factors from those described in the Annual Report on Form 10-K, as updated by those Quarterly Reports on Form 10-Q.

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 materially adversely affect the Company’s business, financial condition or future results.

62

PIONEER NATURAL RESOURCES COMPANY

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company’s purchases of treasury stock during the three months ended September 30, 2009:

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 (b)
July 2009	20,398	$	28.56	—
August 2009	27,616	$	29.75	—
September 2009	351	$	28.96	—
Total	48,365	$	29.24	—	$	355,789,018

(a) Consists of shares withheld to satisfy tax withholding on employees’ share-based awards.

(b) During 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company’s common stock.

63

PIONEER NATURAL RESOURCES COMPANY

Item 6. Exhibits

Exhibits

Exhibit Number		Description
10.1	—	Indemnification Agreement between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers and non-employee directors identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 27, 2009).
10.2	—	Limited Waiver Regarding Credit Agreement, entered into as of March 26, 2009, among Pioneer Southwest Energy Partners L.P., a Delaware limited partnership (the “Partnership”), as the Borrower, Bank of America, N.A., as Administrative Agent, and the other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, File No. 001-34032, filed with the SEC on March 31, 2009).
10.3(a)	—	Amendment No. 2 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2009.
10.4(a)	—	Amendment No. 3 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed October 28, 2009 effective as of the dates specified therein.
12.1 (a)	—	Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends
31.1 (a)	—	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
31.2 (a)	—	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
32.1 (b)	—	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
32.2 (b)	—	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
101.INS (b)	—	XBRL Instance Document.
101.SCH (b)	—	XBRL Taxonomy Extension Schema.
101.CAL (b)	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF (b)	—	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB (b)	—	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE (b)	—	XBRL Taxonomy Extension Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

64

PIONEER NATURAL RESOURCES COMPANY

SIGNATURES

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

	PIONEER NATURAL RESOURCES COMPANY
Date: November 6, 2009	By:	/s/ Richard P. Dealy
		Richard P. Dealy
		Executive Vice President and Chief Financial Officer
Date: November 6, 2009	By:	/s/ Frank W. Hall
		Frank W. Hall
		Vice President and Chief Accounting Officer

65

PIONEER NATURAL RESOURCES COMPANY

Exhibit Index

Exhibit Number		Description
10.1	—	Indemnification Agreement between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers and non-employee directors identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 27, 2009).
10.2	—	Limited Waiver Regarding Credit Agreement, entered into as of March 26, 2009, among Pioneer Southwest Energy Partners L.P., a Delaware limited partnership (the “Partnership”), as the Borrower, Bank of America, N.A., as Administrative Agent, and the other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, File No. 001-34032, filed with the SEC on March 31, 2009).
10.3 (a)	—	Amendment No. 2 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, effective January 1, 2009.
10.4 (a)	—	Amendment No. 3 to the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan, executed October 28, 2009 effective as of the dates specified therein.
12.1 (a)	—	Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends
31.1 (a)	—	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
31.2 (a)	—	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
32.1 (b)	—	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
32.2 (b)	—	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
101.INS (b)	—	XBRL Instance Document.
101.SCH (b)	—	XBRL Taxonomy Extension Schema.
101.CAL (b)	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF (b)	—	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB (b)	—	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE (b)	—	XBRL Taxonomy Extension Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

66

EX-10.3

EXHIBIT 10.3

AMENDMENT NO. 2 TO THE

PIONEER NATURAL RESOURCES USA, INC.

401(k) AND MATCHING PLAN

(Amended and Restated Effective as of January 1, 2008)

THIS AMENDMENT NO. 2 is made and entered into by Pioneer Natural Resources USA, Inc. (the “Company”):

WITNESSETH:

WHEREAS, the Company maintains the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan (the “Plan”); and

WHEREAS, pursuant to Section 8.3 of the Plan, the Benefit Plan Design Committee of the Company (the “Committee”) maintains the authority to amend the Plan at any time; and

WHEREAS, the Committee desires to amend the Plan to allow Participants to defer distribution of their Vested Interest under the Plan until such time as they elect their Vested Interest to be distributed and to allow for early distribution of all or a portion of a Participant’s Vested Interest.

NOW THEREFORE, the Plan is hereby amended effective January 1, 2009 as follows:

1. Section 6.1(a) of the Plan is hereby amended and restated in its entirety as follows:

(a) Unless a Participant elects otherwise, distribution to the Participant or a beneficiary under this Article shall be made or commence being made no later than 60 days after the close of the Plan Year in which the latest of the following occurs: (i) the Participant’s Normal Retirement Date, (ii) the tenth anniversary of the year in which the Participant commenced participation in the Plan, or (iii) the Participant’s separation from the employment of an Employer for any reason other than his or her transfer to the employment of another Employer or Affiliated Company. Notwithstanding the foregoing, the failure of a Participant to consent to a distribution hereunder shall be deemed to be an affirmative election to defer commencement of such distribution.

2. Section 6.1(b) of the Plan is hereby amended and restated in its entirety as follows:

(b) Any provision of this Plan to the contrary notwithstanding, a Participant’s entire interest shall be distributed, or begin to be

distributed, to the Participant no later than the Participant’s Required Beginning Date. For a Participant who is a 5% owner (as defined in Code Section 416(i)), the “Required Beginning Date” is April 1 of the calendar year following the calendar year such Participant attains age 70 ¹/2. For a Participant who is not a 5% owner (as defined in Code Section 416(i)), the “Required Beginning Date” is April 1 of the calendar year following the later of the calendar year in which the Participant attains age 70 ¹/2 or retires. Distributions that commence being made pursuant to this Section 6.1(b) shall be made pursuant to Section 6.2 (excluding Section 6.2(c)) in accordance with the minimum distribution requirements of Code Section 401(a)(9) and such regulations thereunder as may be applicable from time to time; provided, however, that if the Participant elects to waive the normal form of payment in accordance with Section 6.2(b) with respect to such Participant’s Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account or Prior Plan Pre-Tax Account, the alternative form of distribution shall be the minimum amounts required to be distributed pursuant to Code Section 401(a)(9) and such regulations thereunder as may be applicable from time to time, with any amount remaining upon the death of the Participant to be paid in accordance with Section 6.3. Any Participant who attained age 70 ¹/2 prior to January 1, 1999, and who elected to continue to receive distributions prior to such Participant’s termination of employment shall be entitled receive an annual distribution in accordance with the preceding sentence (or may elect a larger or smaller amount for such annual distribution) unless and until such Participant revokes such election.

3. Section 6.2(a) of the Plan is hereby amended and restated in its entirety as follows:

(a) Except as otherwise provided in this Section, upon the Retirement or termination of employment on account of Permanent Disability of a Participant, the Vested Interest of such Participant shall be distributed to such Participant by the Trustee at the direction of the Committee in a lump sum distribution; provided, however, that if such Participant’s Vested Interest exceeds $5,000, he or she may elect to receive his or her Vested Interest in monthly, quarterly or annual installment distributions over a period of two or more years with the first such installment to be payable within 90 days after the end of the Plan Year in which the Participant’s employment terminates. Such installment payments may be made over a period of years not to exceed one or a combination of the following periods: (i) the life of the Participant, (ii) the lives of the Participant and his or her designated beneficiary, (iii) a period certain not extending beyond the life expectancy of the Participant, and (iv) a period certain not extending beyond the joint life and last survivor expectancy of the Participant and his or her designated beneficiary. Any provision of Section 6.3 to the contrary notwithstanding, if a Participant

2

who elected installment payments dies prior to the distribution of the entire amount of his or her Vested Interest, the remaining portion thereof shall be distributed to his or her beneficiary or beneficiaries, as determined in accordance with Section 6.3(a), in a single distribution within 90 days after the end of the Plan Year during which the Participant died. For purposes of determining whether the value of a Participant’s Vested Interest exceeds or does not exceed $5,000, the value of a Participant’s Vested Interest shall be determined without regard to the value of the Participant’s Rollover Account or Roth Rollover Account.

4. The Plan is hereby amended by the addition of the following as Section 6.2(c):

(c) Notwithstanding the foregoing provisions of this Section 6.2, if upon a Participant’s Retirement or termination of employment on account of Permanent Disability the Participant’s Vested Interest exceeds $5,000, no distribution shall be made with respect to such Participant’s Vested Interest unless and until the Participant elects to receive such distribution. An election made by a Participant under this Section 6.2(c) to receive a distribution may be made with respect to all or a portion of such Participant’s Vested Interest. A Participant who elects to receive a distribution of less than his or her entire Vested Interest may elect subsequent distributions with respect to his or her remaining Vested Interest. For purposes of determining whether the value of a Participant’s Vested Interest exceeds or does not exceed $5,000, the value of a Participant’s Vested Interest shall be determined without regard to the value of the Participant’s Rollover Account or Roth Rollover Account.

5. Section 6.4 of the Plan is hereby amended and restated in its entirety as follows:

Section 6.4 Distribution of Separation from Employment Benefit.

(a) Except as otherwise provided in this Section, if a Participant separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company, the Accounts of such Participant shall be retained in trust and shall continue to be credited with applicable earnings as provided in Section 4.3, and the Vested Interest of such Participant shall be distributed to him or her by the Trustee at the direction of the Committee in accordance with Section 6.2(a) as soon as practicable after his or her Normal Retirement Date (or, if the Participant dies prior to such date, the Vested Interest of such Participant shall be distributed upon his or her death in accordance with Section 6.3); provided, however, that (i) each such Participant shall have the right to elect, in the manner prescribed by the Committee, to receive an early distribution of all or a portion of his or

3

her Vested Interest as soon as practicable following such election and (ii) the Committee shall require an early distribution of any such Participant’s Vested Interest which does not exceed $5,000 in the form of a single distribution. The Vested Interest or portion thereof of a Participant who elects to receive an early distribution shall be distributed to him or her in the same manner as provided in Section 6.2(a) for a distribution upon Retirement or Permanent Disability. A Participant who elects to receive an early distribution of less than his or her entire Vested Interest may elect subsequent early distributions with respect to his or her remaining Vested Interest in accordance with this subsection. Any provision of this Plan to the contrary notwithstanding, for purposes of this Article a Participant shall not be treated as having separated from the employment of an Employer or Affiliated Company prior to such time that a distribution can be made to such Participant in accordance with Code Section 401(k) and the regulations thereunder. For purposes of determining whether the value of a Participant’s Vested Interest exceeds $5,000, the value of a Participant’s Vested Interest shall be determined without regard to the value of the Participant’s Rollover Account or Roth Rollover Account.

(b) Any provision of subsection (a) of this Section to the contrary notwithstanding, except as otherwise provided in this subsection (b), if a Participant whose Vested Interest exceeds $5,000 separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company, such Participant’s Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account shall be distributed to such Participant by the Trustee at the direction of the Committee upon such Participant’s Normal Retirement Date by payment of the entire amount in the form of a Qualified Joint and Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment as soon as practicable thereafter (or, if the Participant dies prior to his or her Normal Retirement Date, the Vested Interest of such Participant under the Plan shall be distributed upon his or her death in accordance with Section 6.3); provided, however, that each such Participant shall have the right to elect, in the manner prescribed by the Committee, to receive an early distribution of all or a portion of the amount credited to his or her Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account as soon as practicable after such election. If a participant elects under this subsection (b) to receive an early distribution, such distribution shall be made in the form of (i) a Qualified Joint and Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment as soon as practicable following such election or (ii) upon satisfaction of the notice and waiver requirements of Section 6.2(b) in accordance with subsection (a) of this Section. A Participant

4

who elects to receive an early distribution of less than the entire balance in his or her Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account may elect subsequent early distributions with respect to such Accounts in accordance with this subsection. For purposes of determining whether the value of a Participant’s Vested Interest exceeds $5,000, the value of a Participant’s Vested Interest shall be determined without regard to the value of the Participant’s Rollover Account or Roth Rollover Account.

(c) Notwithstanding the foregoing provisions of this Section 6.4, no distribution shall be made upon a Participant’s attainment of his or her Normal Retirement Date unless and until such Participant elects to receive such distribution. An election made by a Participant under this Section 6.4(c) to receive a distribution may be made with respect to all or a portion of such Participant’s Vested Interest. A Participant who elects to receive a distribution of less than his or her entire Vested Interest may elect subsequent distributions with respect to his or her remaining Vested Interest.

NOW THEREFORE, be it further provided that except as provided above, the Plan shall continue in its current state.

* * * * * * * *

IN WITNESS WHEREOF, the Company has executed this Amendment No. 2 this 28th day of October, 2009 to be effective as of the date specified above.

PIONEER NATURAL RESOURCES USA, INC.
By:	/s/ Larry N. Paulsen
	Larry N. Paulsen
	Vice President, Administration and Risk  Management

5

EX-10.4

EXHIBIT 10.4

AMENDMENT NO. 3 TO THE

PIONEER NATURAL RESOURCES USA, INC.

401(k) AND MATCHING PLAN

(Amended and Restated Effective as of January 1, 2008)

THIS AMENDMENT NO. 3 is made and entered into by Pioneer Natural Resources USA, Inc. (the “Company”):

WITNESSETH:

WHEREAS, the Company maintains the Pioneer Natural Resources USA, Inc. 401(k) and Matching Plan (the “Plan”);

WHEREAS, pursuant to Section 8.3 of the Plan, the Benefit Plan Design Committee of the Company maintains the authority to amend the Plan at any time; and

WHEREAS, the Committee desires to amend the Plan to conform with the previous operation of the Plan with respect to distributions upon retirement and separation from employment.

NOW THEREFORE, the Plan is hereby amended as follows:

1. Effective from June 1, 2007 through December 31, 2008, Section 6.4 of the Plan is hereby amended and restated in its entirety as follows:

Section 6.4 Distribution of Separation from Employment Benefit.

(a) Except as otherwise provided in this Section, if a Participant separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company, the Accounts of such Participant shall be retained in trust and shall continue to be credited with applicable earnings as provided in Section 4.3, and the Vested Interest of such Participant shall be distributed to him or her by the Trustee at the direction of the Committee in accordance with Section 6.2(a) as soon as practicable after his or her Normal Retirement Date (or, if the Participant dies prior to such date, the Vested Interest of such Participant shall be distributed upon his or her death in accordance with Section 6.3); provided, however, that (i) each such Participant shall have the right to elect, in the manner prescribed by the Committee, to receive an early distribution of all or a portion of his or her Vested Interest as soon as practicable and (ii) the Committee shall require an early distribution of any such Participant’s Vested Interest which does not exceed $5,000 in the form of a single distribution. The Vested Interest or portion thereof of a Participant who elects to receive an

early distribution shall be distributed to him or her in the same manner as provided in Section 6.2(a) for a distribution upon Retirement or Permanent Disability. A Participant who elects to receive an early distribution of less than his or her entire Vested Interest may elect subsequent early distributions with respect to his or her remaining Vested Interest. Any provision of this Plan to the contrary notwithstanding, for purposes of this Article a Participant shall not be treated as having separated from the employment of an Employer or Affiliated Company prior to such time that a distribution can be made to such Participant in accordance with Code Section 401(k) and the regulations thereunder. For purposes of determining whether the value of a Participant’s Vested Interest exceeds $5,000, the value of a Participant’s Vested Interest shall be determined without regard to the value of the Participant’s Rollover Account or Roth Rollover Account.

(b) Any provision of subsection (a) of this Section to the contrary notwithstanding, except as otherwise provided in this subsection (b), if a Participant’s whose Vested Interest exceeds $5,000 separates from the employment of an Employer or Affiliated Company for any reason other than his or her Retirement, Permanent Disability, death or transfer to the employment of another Employer or Affiliated Company, such Participant’s Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account shall be distributed to such Participant by the Trustee at the direction of the Committee upon such Participant’s Normal Retirement Date by payment of the entire amount in the form of a Qualified Joint and Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment as soon as practicable thereafter (or, if the Participant dies prior to his or her Normal Retirement Date, the Vested Interest of such Participant under the Plan shall be distributed upon his or her death in accordance with Section 6.3); provided, however, that each such Participant shall have the right to elect, in the manner prescribed by the Committee, to receive an early distribution of all or a portion the amount credited to his or her Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account as soon as practicable after such election. If a participant elects under this subsection (b) to receive an early distribution, such distribution shall be made in the form of (i) a Qualified Joint and Survivor Annuity contract to be purchased from a company selected by the Committee and commencing in payment as soon as practicable following such election or (ii) upon satisfaction of the notice and waiver requirements of Section 6.2(b) in accordance with subsection (a) of this Section. A Participant who elects to receive an early distribution of less than the entire balance in his or her Matching Plan Account, Mesa Premium Account, Prior Plan Employer Account and/or Prior Plan Pre-Tax Account may elect subsequent early distributions with respect to such Accounts. For

2

purposes of determining whether the value of a Participant’s Vested Interest exceeds $5,000, the value of a Participant’s Vested Interest shall be determined without regard to the value of the Participant’s Rollover Account or Roth Rollover Account.

2. Effective from October 1, 1997 through December 31, 2008, the Plan is hereby amended by the addition of the following as Section 6.13:

Section 6.13 Distribution on Normal Retirement Date and Retirement. Notwithstanding the provisions of Sections 6.1(a), 6.2(a), 6.2(b), 6.4(a) and 6.4(b) of the Plan (and the corresponding sections of the Plan in effect prior to January 1, 2008), a Participant shall not be required to receive a distribution of his or her Vested Interest under the Plan upon reaching his or her Normal Retirement Date or as a result of his or her Retirement prior to attaining age 70 ¹/2 if such Participant’s Vested Interest exceeds $5,000. Rather, the Participant’s Vested Interest will be retained in trust and shall not commence being distributed until the earlier of the April 1 of the calendar year following the calendar year in which the Participant reaches age 70 ¹/2 or such time as the Participant elects for his or her Vested Interest to be distributed. The distribution of a Participant’s Vested Interest in accordance with this Section 6.13 shall be made to him or her in the same manner as provided in Section 6.2(a) or 6.2(b), as applicable. Notwithstanding any provision of this Section 6.13 to the contrary, the distribution of a Participant’s Vested Interest must be made in a manner that satisfies the requirements of Code Section 401(a)(9).

NOW THEREFORE, be it further provided that except as provided above, the Plan shall continue in its current state.

* * * * * * * *

IN WITNESS WHEREOF, the Company has executed this Amendment No. 3 this 28th day of October, 2009 to be effective as of the dates specified above.

PIONEER NATURAL RESOURCES USA, INC.
By:	/s/ Larry N. Paulsen
	Larry N. Paulsen
	Vice President, Administration and Risk  Management

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EX-12.1

EXHIBIT 12.1

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

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

	Nine months ended September 30,	Year ended December 31,
	2009	2008	2007	2006	2005	2004
Ratio of earnings to fixed charges (a)	(b)	3.10	2.77	3.01	3.40	2.93
Ratio of earnings to fixed charges and preferred stockdividends (c)	(b)	3.10	2.77	3.01	3.40	2.93

(a) The ratio has been computed by dividing earnings by fixed charges. For purposes of computing the ratio:

- earnings consist of income from continuing operations before income taxes, cumulative effect of change in accounting principle, adjustments for net income (loss) attributable to the noncontrolling interest and adjustment for capitalized interest, plus fixed charges; and

- fixed charges consist of interest expense, capitalized interest and the portion of rental expense deemed to be representative of the of the interest component of rental expense.

(b) The ratio indicates a less than one-to-one coverage because the earnings are inadequate to cover the fixed charges during the nine months ended September 30, 2009 by $177.2 million.

(c) The ratio has been computed by dividing earnings by fixed charges and preferred stock dividends. For purposes of computing the ratio:

- earnings consist of income from continuing operations before income taxes, cumulative effect of change in accounting principle, adjustments for net income (loss) attributable to the noncontrolling interest and adjustment for capitalized interest, plus fixed charges and preferred stock dividends, net of preferred stock dividends of a consolidated subsidiary; and

- fixed charges and preferred stock dividends consist of interest expense, capitalized interest and the portion of rental expense deemed to be representative of the interest component of rental expense, preferred stock dividends of a consolidated subsidiary and preferred stock dividends.

EX-31.1

EXHIBIT 31.1

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Scott D. Sheffield, certify that:

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

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

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

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

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

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

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

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

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

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

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

November 6, 2009
	/s/ Scott D. Sheffield
	Scott D. Sheffield, Chairman and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CHIEF FINANCIAL OFFICER CERTIFICATION

I, Richard P. Dealy, certify that:

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

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

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

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

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

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

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

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

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

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

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

November 6, 2009
	/s/ Richard P. Dealy
	Richard P. Dealy, Executive Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Scott D. Sheffield, Chairman and Chief Executive Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

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

	/s/ Scott D. Sheffield
Name:	Scott D. Sheffield, Chairman and Chief Executive Officer
Date:	November 6, 2009

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

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

	/s/ Richard P. Dealy
Name:	Richard P. Dealy, Executive Vice President and Chief Financial Officer
Date:	November 6, 2009