Pioneer Natural Resources (PXD) 10-Q 2009 Q1 Quarterly report

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 March 31, 2009

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to ________

Commission File Number: 1-13245

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

Delaware	75-2702753
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5205 N. O'Connor Blvd., Suite 200, Irving, Texas	75039
(Address of principal executive offices)	(Zip Code)

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

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

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x         No o

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

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

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

Yes o No  x

Number of shares of Common Stock outstanding as of May 8, 2009 113,983,711

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 March 31, 2009 and December 31, 2008	5
Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008	7
Consolidated Statement of Stockholders' Equity for the three months ended March 31, 2009	8
Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and 2008	9
Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2009 and 2008	10
Notes to Consolidated Financial Statements	11
Item 2.     Management's Discussion and Analysis of Financial Condition and Results of                  Operations	39
Item 3.Quantitative and Qualitative Disclosures About Market Risk	56
Item 4.Controls and Procedures	59
PART II. OTHER INFORMATION
Item 1.Legal Proceedings	60
Item 1A.Risk Factors	60
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds	60
Item 6.Exhibits	61
Signatures	62
Exhibit Index	63

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 projects 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 "Item 1. Business — Competition, Markets and Regulations", "Item 1A. Risk Factors" and "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.

• "field fuel" means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.

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

• "IPO" means initial public offering.

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

• "LNG" means liquefied natural gas.

• "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)

				March 31, 2009		December 31, 2008 (a)
ASSETS
Current assets:
	Cash and cash equivalents			$	44,476	$	48,337
	Accounts receivable:
		Trade, net of allowance for doubtful accounts of $21,710 and $22,464 as of
			March 31, 2009 and December 31, 2008, respectively		163,679		206,794
		Due from affiliates			447		759
	Income taxes receivable				15,637		60,573
	Inventories				68,365		76,901
	Prepaid expenses				10,504		12,464
	Deferred income taxes				19,300		6,510
	Other current assets:
		Derivatives			118,299		59,622
		Other, net of allowance for doubtful accounts of $5,566 and $5,491 as of
			March 31, 2009 and December 31, 2008, respectively		8,001		14,951
			Total current assets		448,708		486,911
Property, plant and equipment, at cost:
	Oil and gas properties, using the successful efforts method of accounting:
		Proved properties			10,247,172		10,167,220
		Unproved properties			198,673		204,183
	Accumulated depletion, depreciation and amortization				(2,696,655)		(2,511,401)
			Total property, plant and equipment		7,749,190		7,860,002
Deferred income taxes					336		553
Goodwill					310,563		310,563
Other property and equipment, net					160,290		161,266
Other assets:
	Derivatives				82,041		72,594
	Other, net of allowance for doubtful accounts of $4,324 and $4,410 as of
		March 31, 2009 and December 31, 2008, respectively			300,517		269,896
				$	9,051,645	$	9,161,785

_____________

(a) Retrospectively adjusted as described in Note B.

The financial information included as of March 31, 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.

5

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)

(Unaudited)

				March 31, 2009		December 31, 2008 (a)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable:
		Trade		$	192,781	$	322,688
		Due to affiliates			5,253		34,284
	Interest payable				27,671		43,247
	Income taxes payable				12,159		3,618
	Other current liabilities:
		Derivatives			44,980		49,561
		Deferred revenue			133,669		147,905
		Other			76,878		93,694
			Total current liabilities		493,391		694,997
Long-term debt					3,075,486		2,899,241
Derivatives					15,720		20,584
Deferred income taxes					1,494,181		1,501,459
Deferred revenue					154,753		177,236
Other liabilities					188,013		187,409
Stockholders' equity:
	Common stock, $.01 par value; 500,000,000 shares authorized; 125,120,735 and
		124,566,963 shares issued at March 31, 2009 and December 31, 2008, respectively			1,251		1,246
	Additional paid-in capital				2,915,108		2,909,735
	Treasury stock, at cost: 11,193,377 and 10,020,502 shares at March 31, 2009
		and December 31, 2008, respectively			(429,668)		(411,659)
	Retained earnings				968,326		988,786
	Accumulated other comprehensive income - deferred hedge gains, net of tax				74,134		88,788
			Total stockholders' equity attributable to common stockholders		3,529,151		3,576,896
	Noncontrolling interest in consolidated subsidiaries				100,950		103,963
			Total stockholders' equity		3,630,101		3,680,859
Commitments and contingencies
				$	9,051,645	$	9,161,785

_____________

(a) Retrospectively adjusted as described in Note B.

The financial information included as of March 31, 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 March 31,
		2009		2008 (a)
Revenues and other income:
	Oil and gas	$	373,837	$	558,476
	Derivative gains, net		99,863		1,027
	Interest and other		10,660		25,024
	Gain (loss) on disposition of assets, net		(115)		678
			484,245		585,205
Costs and expenses:
	Oil and gas production		112,969		94,619
	Production and ad valorem taxes		27,758		38,028
	Depletion, depreciation and amortization		192,557		109,627
	Impairment of oil and gas properties		21,091		-
	Exploration and abandonments		31,431		38,677
	General and administrative		34,639		36,481
	Accretion of discount on asset retirement obligations		2,974		2,142
	Interest		41,138		40,278
	Hurricane activity, net		375		458
	Other		31,389		11,915
			496,321		372,225
Income (loss) from continuing operations before income taxes			(12,076)		212,980
Income tax benefit (provision)			1,263		(86,222)
Income (loss) from continuing operations			(10,813)		126,758
Income from discontinued operations, net of tax			-		1,940
Net income (loss)		$	(10,813)		128,698
	Less: Net income attributable to the noncontrolling interest		(3,793)		(738)
Net income (loss) attributable to common stockholders		$	(14,606)	$	127,960
Basic earnings per share:
	Income (loss) from continuing operations attributable to common stockholders	$	(0.13)	$	1.05
	Income from discontinued operations attributable to common stockholders		-		0.02
	Net income (loss) attributable to common stockholders	$	(0.13)	$	1.07
Diluted earnings per share:
	Income (loss) from continuing operations attributable to common stockholders	$	(0.13)	$	1.05
	Income from discontinued operations attributable to common stockholders		-		0.02
	Net income (loss) attributable to common stockholders	$	(0.13)	$	1.07
Weighted average shares outstanding:
	Basic		114,242		117,934
	Diluted		114,242		118,260
Dividends declared per share		$	0.04	$	0.14
Amounts attributable to common stockholders:
	Income (loss) from continuing operations	$	(14,606)	$	126,020
	Discontinued operations, net of tax		-		1,940
	Net income (loss)	$	(14,606)	$	127,960

_____________

(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 STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands, except dividends per share)

(Unaudited)

			Shares Outstanding	Common Stock		Additional Paid-in Capital		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Income		Noncontrolling Interest		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 ($0.04    per share)			-		-		-		-		(4,698)		-		-		(4,698)
Exercise of long-term    incentive plan stock    options			51		-		-		2,110		(1,156)		-		-		954
Purchase of treasury stock			(1,000)		-		-		(20,119)		-		-		-		(20,119)
Tax benefits related to   stock-based    compensation			-		-		(3,879)		-		-		-		-		(3,879)
Compensation costs:
	Vested compensation   awards, net		330		5		(5)		-		-		-		-		-
	Compensation costs    included in net income		-		-		9,257		-		-		-		40		9,297
Working capital    contributions			-		-		-		-		-		-		150		150
Cash distributions to    noncontrolling interest    partners			-		-		-		-		-		-		(4,990)		(4,990)
Net income (loss)			-		-		-		-		(14,606)		-		3,793		(10,813)
Other comprehensive    income (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	-		-		-		-		-		(25,131)		(5,698)		(30,829)
Balance as of March 31,    2009			113,927	$	1,251	$	2,915,108	$	(429,668)	$	968,326	$	74,134	$	100,950	$	3,630,101

_____________

(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)

						Three Months Ended March 31,
						2009		2008 (a)
Cash flows from operating activities:
	Net income (loss)				$	(10,813)	$	128,698
	Adjustments to reconcile net income (loss) to net cash provided by
		operating activities:
			Depletion, depreciation and amortization			192,557		109,627
			Impairment of oil and gas properties			21,091		-
			Exploration expenses, including dry holes			18,509		3,548
			Deferred income taxes			(11,032)		65,119
			(Gain) loss on disposition of assets, net			115		(678)
			Accretion of discount on asset retirement obligations			2,974		2,142
			Discontinued operations			-		348
			Interest expense			6,609		6,297
			Derivative related activity			(111,285)		7,665
			Amortization of stock-based compensation			9,297		8,980
			Amortization of deferred revenue			(36,720)		(39,479)
			Other noncash items			10,694		(4,640)
	Change in operating assets and liabilities
			Accounts receivable, net			42,221		(14,061)
			Income taxes receivable			44,936		(76)
			Inventories			(34,470)		(26,172)
			Prepaid expenses			1,960		937
			Other current assets			26,057		1,995
			Accounts payable			(111,450)		(33,913)
			Interest payable			(15,576)		(13,335)
			Income taxes payable			8,541		9,190
			Other current liabilities			(29,794)		(34,510)
				Net cash provided by operating activities		24,421		177,682
Cash flows from investing activities:
	Proceeds from disposition of assets, net of cash sold					200		132,133
	Additions to oil and gas properties					(164,527)		(297,267)
	Additions to other assets and other property and equipment, net					(6,736)		(12,406)
				Net cash used in investing activities		(171,063)		(177,540)
Cash flows from financing activities:
	Borrowings under long-term debt					172,000		592,000
	Principal payments on long-term debt					(1,000)		(545,777)
	Distributions to noncontrolling interest partners					(4,840)		-
	Payments of other liabilities					(335)		(5,890)
	Exercise of long-term incentive plan stock options					954		877
	Purchase of treasury stock					(20,119)		(26,950)
	Excess tax (costs) benefits from share-based payment arrangements					(3,879)		2,145
	Payment of financing fees					-		(11,346)
	Dividends paid					-		(52)
				Net cash provided by financing activities		142,781		5,007
Net increase (decrease) in cash and cash equivalents						(3,861)		5,149
Cash and cash equivalents, beginning of period						48,337		12,171
Cash and cash equivalents, end of period					$	44,476	$	17,320

_____________

(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 March 31,
				2009		2008(a)
Net income (loss)				$	(10,813)	$	128,698
Other comprehensive income (loss):
	Hedge activity, net of tax:
		Hedge fair value changes, net			10,477		(140,267)
		Net hedge (gains) losses included in continuing
			operations		(25,131)		50,431
			Other comprehensive loss		(14,654)		(89,836)
Comprehensive income (loss)				$	(25,467)	$	38,862
	Less: Comprehensive loss attributable to
		noncontrolling interest			2,006		-
Comprehensive income (loss) attributable to common
	stockholders			$	(23,461)	$	38,862

_____________

(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

March 31, 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 March 31, 2009 and for the three months ended March 31, 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 generally accepted accounting principles in the United States ("GAAP") have been condensed or omitted in this Form 10-Q 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. In April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries. During the three months ended March 31, 2008, the Company continued to realize certain revenue and costs and expense increments associated with these divestitures. In accordance with Statement of Financial Accounting Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"), the Company has reflected the revenue and costs and expense increments associated with these divestitures as discontinued operations, rather than as a component of continuing operations. See Note R for additional information regarding discontinued operations.

Allowances for doubtful accounts. As of March 31, 2009 and December 31, 2008, the Company's allowances for doubtful accounts totaled $31.6 million and $32.4 million, respectively. In accordance with SFAS No. 5, "Accounting for Contingencies," the Company establishes allowances for bad debts 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 consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.

		Three Months Ended March 31, 2009
		(in thousands)
Beginning allowance for doubtful accounts balance		$	32,365
	Amount recorded in other expense for net recoveries		(686)
	Write offs of uncollectable accounts		(79)
Ending allowance for doubtful accounts balance		$	31,600

Inventories. Inventories consisted of $194.7 million and $158.7 million of materials and supplies and $5.5 million and $8.7 million of commodities as of March 31, 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 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

11

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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 March 31, 2009 and December 31, 2008, the Company's materials and supplies inventory was net of $5.7 million and $4.7 million, respectively, of valuation reserve allowances. The Company estimates that approximately $131.7 million and $90.2 million of its March 31, 2009 and December 31, 2008 materials and supplies inventories, respectively, would not be utilized within one year due to declines in budgeted drilling activities. 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 March 31, 2009 and December 31, 2008, the Company's commodities inventories were net of $5 thousand and $159 thousand of valuation allowances, respectively.

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 under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). Therefore, the changes in the fair values of these non-hedge derivative instruments are being 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 net deferred hedge gains as of January 31, 2009 attributable to the discontinued hedges 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.

In accordance with Financial Accounting Standards Board ("FASB") Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts" ("FIN 39"), 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, whichever the case may be.

Goodwill. In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," 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 2008, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment. However, as a result of commodity prices and the market capitalization of the Company declining significantly since mid-2008, which the Company considered events that might indicate impairment to the carrying value of goodwill, the Company reassessed goodwill for impairment as of March 31, 2009 and December 31, 2008, and determined that there was no impairment. See Note M for additional information regarding the Company’s impairment assessments.

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.

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 $101.0 million and $104.0 million as of March 31, 2009 and December 31, 2008, respectively. Net income attributable to the noncontrolling interest totaled $3.8 million for the three months ended March 31, 2009 (principally related to Pioneer Southwest), and $738 thousand for the three months ended March 31, 2008. See "New accounting pronouncements"and "Reclassifications and retrospective adjustments" for information regarding the Company’s

12

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

adoption of SFAS No. 160, "Noncontrolling Interest in Consolidated Financial Statements, an amendment of ARB Statement No. 51" ("SFAS 160").

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 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 month periods ended March 31, 2009 and 2008, the Company recognized $9.3 million and $9.0 million of stock-based compensation costs for all plans.

In accordance with GAAP, the Company's issued and outstanding shares, as reflected in the consolidated balance sheets at March 31, 2009 and December 31, 2008, do not include 1,030,274 and 1,078,267, respectively, of unvested voting shares awarded under stock-based compensation plans.

The following table summarizes all stock-based awards, lapses and forfeitures that occurred during the three months ended March 31, 2009:

	Restricted Stock Shares	Restricted Stock Units	Performance Units	Stock Options
Awards	378,497	1,555,532	189,247	361,021
Lapsed restrictions	423,173	130,599	-	-
Exercises	-	-	-	51,367
Forfeitures	3,317	7,758	-	99,118

As of March 31, 2009, there was approximately $70.9 million of unrecognized compensation expense related to unvested share-based compensation plan awards, primarily related to restricted stock and performance unit awards. 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. In September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS No. 157, "Fair Value Measures" ("SFAS 157"). SFAS 157 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" ("FSP FAS 157-2"). FSP FAS 157-2 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 SFAS 157, for which delayed adoption was provided under FSP FAS 157-2.

In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations" ("SFAS 141(R)"). SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) 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 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 SFAS 141(R) 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. SFAS 141(R) is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008, and

13

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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 SFAS 141(R) on January 1, 2009.

In December 2007, the FASB issued SFAS 160. SFAS 160 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. SFAS 160 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, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. The Company adopted the provisions of SFAS 160 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" ("SFAS 161"). SFAS 161 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 SFAS 133 and (iii) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS 161 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)" ("FSP APB 14-1"). FSP APB 14-1 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 FSP APB 14-1 on January 1, 2009. The adoption of FSP APB 14-1 increases the annual interest expense that the Company recognizes on its $480 million of 2.875% Senior Convertible Notes from an annual yield of approximately 2.875 percent to 6.75 percent, the annual yield equivalent to a nonconvertible debt borrowing at the time of issuance. The adoption of FSP APB 14-1 also resulted in the reclassification of the estimated issuance date fair value of the 2.875% Senior Convertible 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 FSP APB 14-1.

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" ("FSP EITF 03-6-1"), 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 net income (loss) per share under the two class method prescribed under SFAS 128, "Earnings per Share". The Company adopted the provisions of FSP EITF 03-6-1 on January 1, 2009 and, in accordance with FSP EITF 03-6-1, applied its provisions retrospectively to prior-period net income per share computations. See Note K for additional information regarding the Company’s basic and diluted net income (loss) computations for the three months ended March 31, 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 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 price based upon the prior 12-month 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" ("SFAS 19") 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.

14

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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" ("FSP FAS 107-1"), which amends FASB Statement No. 107, "Disclosures about Fair Value of Financial Instruments" and Accounting Principles Board Opinion No. 28, "Interim Financial Reporting". FSP FAS 107-1 requires disclosures about the fair value of financial instruments for interim reporting purposes of publicly traded companies. FSP FAS 107-1 is effective for interim reporting periods ending after June 15, 2009 and will only impact future disclosures about the fair value of the Company's financial instruments.

In April 2009, the FASB issued FASB Staff Position No. FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly" ("FSP FAS 157-4"), which provides additional guidelines for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have decreased and guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009 and is not expected to have a material impact on the Company's fair value measurements.

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 SFAS 160. The retrospective application of SFAS 160 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 FSP APB 14-1 and FSP EITF 03-6-1 required retrospective adjustments to the Company's financial statements as of December 31, 2008 and the three months ended March 31, 2008. The retrospective adjustments related to the adoption of FSP APB 14-1 decreased the Company's net income attributable to common stockholders by $1.8 million (approximately $0.02 per diluted share) for the three months ended March 31, 2008. The retrospective application of FSP APB 14-1 also increased additional paid-in capital by $49.5 million and decreased retained earnings by $10 million as of December 31, 2008. The retrospective application of the provisions of FSP EITF 03-6-1 to the reported per-share amounts of the three months ended March 31, 2008 reduced the Company’s basic earnings by approximately $0.01 per share, exclusive of the effects from the adoption of FSP APB 14-1.

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.

The following table reflects the Company's capitalized exploratory well activity during the three months ended March 31, 2009:

			Three Months Ended March 31, 2009
			(in thousands)
Beginning capitalized exploratory well costs			$	124,014
	Additions to exploratory well costs pending the
		determination of proved reserves		14,142
	Reclassification due to determination of proved reserves			(9,390)
	Exploratory well costs charged to exploration and abandonments expense			(4,927)
Ending capitalized exploratory well costs			$	123,839

15

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

The following table provides an aging, as of March 31, 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:

		March 31, 2009		December 31, 2008
		(in thousands, except well counts)
Capitalized exploratory well costs that have been suspended:
	One year or less	$	53,139	$	54,423
	More than one year		70,700		69,591
		$	123,839	$	124,014
Number of projects with exploratory well costs that have
	been suspended for a period greater than one year		4		4

The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of March 31, 2009:

		Total		2009		2008		2007		2006
		(in thousands)
United States:
Cosmopolitan Unit		$	60,013	$	1,352	$	6,344	$	51,488	$	829
Other			2,854		14		(134)		48		2,926
Tunisia			7,833		(257)		(289)		4,434		3,945
	Total	$	70,700	$	1,109	$	5,921	$	55,970	$	7,700

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. As a result, the Company began permitting and facilities planning during 2008 to further evaluate the unit's resource potential. During 2009, the Company plans to continue with permitting, progress engineering studies and develop plans for a second well to be drilled in 2010 to further delineate the extent of the unit's resource potential.

NOTE D. Disclosures About Fair Value Measurements

The valuation framework of SFAS 157 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.

16

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following table presents the Company's assets and liabilities that are measured at fair value as of March 31, 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 March 31, 2009
			(in thousands)
Assets:
	Trading securities		$	194	$	47	$	-	$	241
	Commodity derivatives			-		180,506		19,834		200,340
	Deferred compensation plan assets			18,070		-		-		18,070
	Oil and gas properties			-		-		21,624		21,624
		Total assets	$	18,264	$	180,553	$	41,458	$	240,275
Liabilities:
	Commodity derivatives		$	-	$	49,282	$	1,697	$	50,979
	Interest rate derivatives			-		9,721		-		9,721
		Total liabilities	$	-	$	59,003	$	1,697	$	60,700

The following table presents the changes in the fair values of the Company's net commodity derivative assets measured on a recurring basis classified as Level 3 in the fair value hierarchy:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)		Three Months Ended March 31, 2009
		NGL Swap Contracts		Oil Three Way Collars		Gas Three Way Collars		Total
		(in thousands)
Beginning balance		$	18,560	$	-	$	-	$	18,560
Total gains (losses):
	Net unrealized gains (losses) included in earnings (a)		2,101		(1,697)		3,364		3,768
	Net realized gains transferred to earnings		(2,336)		-		-		(2,336)
	Net derivative losses included in other comprehensive income		(1,855)		-		-		(1,855)
Ending balance		$	16,470	$	(1,697)	$	3,364	$	18,137

_____________

(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 gains and losses are included in derivative gains, net, in the accompanying consolidated statements of operations.

17

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

The following table presents the changes in the fair values of the Company's oil and gas properties measured on a nonrecurring basis classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2009:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Oil and gas properties
	(in thousands)
Beginning balance	$	-
Transfers into Level 3		42,715
Net unrealized losses included in earnings (a)		(21,091)
Ending balance	$	21,624

_____________

(a) Net unrealized losses on the Company's oil and gas properties are included in impairment of oil and gas properties in the accompanying consolidated statements of operations See Note M for more information about the Company's impairments.

Trading securities and deferred compensation plan assets. The Company's trading securities represent equity securities that are actively traded on major exchanges and, to a lesser extent, trading securities that are not actively traded on major exchanges. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges plus unallocated contributions as of the measurement date. As of March 31, 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.

Interest rate derivatives. The Company's interest rate derivative assets 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. In accordance with FIN 39, the Company classifies derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties. The Company's derivative assets and liabilities are comprised of assets and liabilities due from derivative counterparties that are net derivative creditors or net derivative debtors of the Company as of March 31, 2009. Net derivative asset transfer 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 March 31, 2009. The net derivative asset values attributable to the Company's interest rate derivative contracts as of March 31, 2009 are based on (i) the contracted notional amounts, (ii) 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 and collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority while NGL derivative contract and oil and gas three-way 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 West Texas Intermediate ("WTI") oil prices. The asset and liability values attributable to the Company's oil derivatives as of March 31, 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 implied volatility factors provided by the derivative counterparties, adjusted for estimated volatility skews. The volatility factors are not considered significant to the fair values of the collar contracts since intrinsic and time values are the principal components of the collar values. The volatility factors are considered significant to the fair value of the Company's three-way collars. As of March 31, 2009, the fair value of oil derivative contracts was estimated from quotes provided by the counterparties to these derivative contracts.

18

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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 March 31, 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. As of March 31, 2009, the fair value of NGL derivative contracts was estimated from quotes provided by the counterparties to these derivative contracts.

Gas derivatives. The Company's gas derivatives are swap 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 March 31, 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 and (iv) the applicable credit-adjusted risk-free rate yield curve. As of March 31, 2009, the fair value of gas derivatives was estimated from quotes provided by the counterparties to these derivative contracts.

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

NOTE E. Income Taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 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 local and foreign tax jurisdictions will be utilized prior to their expiration. As of March 31, 2009 and December 31, 2008, the Company's valuation allowances (relating primarily to foreign tax jurisdictions) were $39.6 million and $37.5 million, respectively.

The Company also accounts for income taxes in accordance with FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes" ("FIN 48"), which 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 March 31, 2009, the Company had no unrecognized tax benefits (as defined in FIN 48). In connection with the adoption of FIN 48, the Company established a policy 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 2003. As of March 31, 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.

19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

Income tax (provisions) benefits. The Company's income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three months ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009		2008
			(in thousands)
Current:
	U.S. federal	$	1,070	$	(5,420)
	U.S. state and local		(676)		(911)
	Foreign		(10,163)		(14,772)
			(9,769)		(21,103)
Deferred:
	U.S. federal		3,530		(61,218)
	U.S. state and local		242		2,485
	Foreign		7,260		(6,386)
			11,032		(65,119)
		$	1,263	$	(86,222)

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 March 31, 2009, the Company had $1.1 billion 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 $370.0 million of unused borrowing capacity under the Credit Facility.

During April 2009, the Company and the lenders under the Credit Facility amended the Credit Facility, as is more fully described in Note S. The following discussion provides a summary of the significant terms of the Credit Facility as they existed on March 31, 2009 and December 31, 2008:

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans 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 or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin") that is determined by a reference grid based on the Company's debt rating (.75 percent as of March 31, 2009). Swing line loans 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 Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. The covenants also include the maintenance of 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 & Poors Ratings Group, Inc. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) are subject to

20

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

adjustment by the lenders and, therefore, 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 lenders may declare any outstanding obligations under the Credit Facility immediately due and payable upon the occurrence, and during the continuance of, an event of default, which includes a defined change in control of the Company. As of March 31, 2009, the Company was in compliance with all of its debt covenants. See Note S for information regarding the Company's amendment of the Credit Facility in April 2009.

In May 2008, Pioneer Southwest entered into a $300 million unsecured revolving credit facility with a syndicate of banks, which matures in May 2013 (the "Pioneer Southwest Credit Facility"). The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. 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 March 31, 2009, there were no 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 maximum leverage ratio of not more than 3.5 to 1.00, (ii) an interest coverage ratio (representing a ratio of 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 derivative related activity; and noncash equity-based compensation 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 contained in the agreement, borrowings under the Pioneer Southwest Credit Facility are currently limited to approximately $200 million. The variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) are subject to adjustment by the lenders. As a result, further declines in commodity prices could reduce Pioneer Southwest's borrowing capacity under the Pioneer 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.

Senior convertible notes. During January 2008, the Company issued $500 million principal amount of 2.875% convertible senior notes due 2038 (the "2.875% Senior Convertible Notes"), of which $480 million remains outstanding at March 31, 2009. Effective January 1, 2009, the Company adopted the provisions of FSP APB 14-1 and, in accordance therewith, the Company applied the provisions of FSP APB 14-1 on a retrospective basis. The initial adoption of FSP APB 14-1 decreased the carrying value of the 2.875% Senior Convertible Notes by $63.5 million, increased stockholders' equity by $39.5 million and increased deferred tax liabilities by $24.0 million. For the three months ended March 31, 2009, the adoption of FSP APB 14-1 increased interest expense by $3.4 million and increased net loss by approximately $2.1 million ($0.02 per share).

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

21

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

normal sales contracts and not derivatives. Therefore, physical delivery contracts are not accounted for as derivative financial instruments in the financial statements.

All derivatives are recorded on the balance sheet at estimated fair value. Fair value is determined in accordance with SFAS 157 and 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 accounts 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 is later transferred to earnings when the hedged transaction is recognized in earnings. The ineffective portion of changes in the fair value of hedge derivatives were recorded in the earnings of the period of change. The ineffective portion is 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 March 31, 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.

Oil prices. All material physical sales contracts governing the Company's oil production have been tied directly or indirectly to the New York Mercantile Exchange ("NYMEX") prices. The following table sets forth the volumes in barrels ("Bbl") underlying the Company's outstanding oil derivative contracts and the weighted average NYMEX prices per Bbl for those contracts as of March 31, 2009.

22

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

				First		Second		Third		Fourth		Outstanding
				Quarter		Quarter		Quarter		Quarter		Average
Average daily oil production
	non-hedge derivatives (a):
		2009 – Swap Contracts
			Volume (Bbl)				25,500		25,500		12,500		21,151
			Price per Bbl			$	57.10	$	57.10	$	61.55	$	57.98
		2009 – Collar Contracts
			Volume (Bbl)				2,000		2,000		2,000		2,000
			Price per Bbl:
			Ceiling			$	70.38	$	70.38	$	70.38	$	70.38
			Floor			$	52.00	$	52.00	$	52.00	$	52.00
		2009 – Collar Contracts  with Short Puts
			Volume (Bbl)				-		-		13,000		4,349
			Price per Bbl:
			Ceiling			$	-	$	-	$	70.77	$	70.77
			Floor			$	-	$	-	$	51.38	$	51.38
			Short Put			$	-	$	-	$	41.38	$	41.38
		2010 – Swap Contracts
			Volume (Bbl)		2,000		2,000		2,000		2,000		2,000
			Price per Bbl	$	98.32	$	98.32	$	98.32	$	98.32	$	98.32
		2010 – Collar Contracts   with Short Puts
			Volume (Bbl)		5,000		5,000		5,000		5,000		5,000
			Price per Bbl:
			Ceiling	$	73.00	$	73.00	$	73.00	$	73.00	$	73.00
			Floor	$	62.00	$	62.00	$	62.00	$	62.00	$	62.00
			Short Put	$	47.00	$	47.00	$	47.00	$	47.00	$	47.00
		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)		5,000		5,000		5,000		5,000		5,000
			Price per Bbl:
			Ceiling	$	87.14	$	87.14	$	87.14	$	87.14	$	87.14
			Floor	$	70.00	$	70.00	$	70.00	$	70.00	$	70.00
			Short Put	$	55.00	$	55.00	$	55.00	$	55.00	$	55.00

_____________

(a) From April 1, 2009 through May 1, 2009, the Company (i) entered into derivative transactions to convert 8,888 Bbls per day of 2009 swap contracts with a weighted average fixed price of $52.35 per Bbl into collar contracts with short puts with a ceiling price of $62.41 per Bbl, a floor price of $51.43 per Bbl and a short put price of $44.55 per Bbl, and (ii) entered into additional oil collar contracts with short puts for approximately (a) 3,000 Bbls per day of the Company’s 2010 production with a ceiling price of $80.25 per Bbl, a floor price of $65.00 per Bbl and a short put price of $52.00 per Bbl and (b) 2,000 Bbls per day of the Company’s 2011 production with a ceiling price of $90.00 per Bbl, a floor price of $70.00 per Bbl and a short put price of $55.00 per Bbl.

23

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

The Company reports average oil prices per Bbl including the effects of oil quality adjustments, amortization of deferred volumetric production payment ("VPP") revenue and the net effect of oil hedges. The following table sets forth (i) the Company's oil prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to oil revenue from continuing operations and (iii) the net effect of settlements of oil price hedges on oil revenue from continuing operations for the three month periods ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009		2008
Average price reported per Bbl		$	52.82	$	77.41
Average price realized per Bbl		$	37.51	$	98.26
VPP increase to oil revenue (in millions)		$	24.5	$	26.0
Increase (decrease) to oil revenue from
	hedging activity (in millions)	$	22.4	$	(79.4)

NGL 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 March 31, 2009:

				First		Second		Third		Fourth		Outstanding
				Quarter		Quarter		Quarter		Quarter		Average
Average daily NGL production
	non-hedge derivatives:
		2009 – Swap Contracts
			Volume (Bbl)				3,750		3,750		3,750		3,750
			Price per Bbl			$	34.27	$	34.28	$	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

The Company reports average NGL prices per Bbl including the effects of NGL quality adjustments and the net effect of NGL derivatives. The following table sets forth (i) the Company's NGL prices from continuing operations, both reported (including hedge results) and realized (excluding hedge results) and (ii) the net effect of NGL price hedges on NGL revenue from continuing operations for the three-month periods ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009		2008
Average price reported per Bbl		$	22.97	$	53.89
Average price realized per Bbl		$	21.82	$	54.28
Increase (decrease) to NGL revenue from
	hedging activity (in millions)	$	2.3	$	(0.7)

24

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

Gas prices. The Company employs a policy of using derivatives associated with a portion of its gas production based on the index price upon which the gas is actually sold in order to mitigate the basis risk between NYMEX prices and actual index prices, or based on NYMEX prices, if NYMEX prices are highly correlated with the index price. The following table sets forth the volumes in million British thermal units ("MMBtu") under outstanding gas derivative contracts and the weighted average index prices per MMBtu for those contracts as of March 31, 2009:

				First		Second		Third		Fourth		Outstanding
				Quarter		Quarter		Quarter		Quarter		Average
Average daily gas production
	non-hedge derivatives (a):
		2009 – Swap Contracts
			Volume (MMbtu)				135,000		135,000		135,000		135,000
			Price per MMBtu			$	6.25	$	6.25	$	6.16	$	6.22
		2009 – Basis Swap Contracts
			Volume (MMbtu)				215,000		215,000		215,000		215,000
			Price per MMBtu			$	(1.04)	$	(1.04)	$	(1.04)	$	(1.04)
		2009 – Collar Contracts
			Volume (MMbtu)				20,000		20,000		20,000		20,000
			Price per MMBtu:
			Ceiling			$	5.90	$	5.90	$	5.90	$	5.90
			Floor			$	4.00	$	4.00	$	4.00	$	4.00
		2009 – Collar Contracts with Short  Puts
			Volume (MMbtu)				40,000		40,000		40,000		40,000
			Price per MMBtu:
			Ceiling			$	5.86	$	5.86	$	5.86	$	5.86
			Floor			$	4.50	$	4.50	$	4.50	$	4.50
			Short Put			$	3.50	$	3.50	$	3.50	$	3.50
		2010 – Swap Contracts
			Volume (MMbtu)		125,000		125,000		125,000		125,000		125,000
			Price per MMBtu	$	6.60	$	6.60	$	6.60	$	6.60	$	6.60
		2010 – Basis Swap Contracts
			Volume (MMbtu)		155,000		155,000		155,000		155,000		155,000
			Price per MMBtu	$	(0.88)	$	(0.88)	$	(0.88)	$	(0.88)	$	(0.88)
		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

25

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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
2011 – Basis Swap Contracts
	Volume (MMbtu)		60,000		60,000		60,000		60,000		60,000
	Price per MMBtu	$	(0.82)	$	(0.82)	$	(0.82)	$	(0.82)	$	(0.82)
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 – 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) From April 1, 2009 through May 1, 2009, the Company entered into additional basis swap contracts for approximately 30,000 MMBtu of the Company's 2010 production at an average price differential of $0.73 per MMBtu.

The Company reports average gas prices per Mcf including the effects of Btu content, gas processing, shrinkage adjustments, amortization of deferred VPP revenue and the net effect of gas hedges. The following table sets forth (i) the Company's gas prices from continuing operations, both reported (including hedge results and amortization of deferred VPP revenue) and realized (excluding hedge results and amortization of deferred VPP revenue), (ii) amortization of deferred VPP revenue to gas revenue from continuing operations and (iii) the net effect of settlements of gas price hedges on gas revenue from continuing operations for the three-month periods ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009		2008
Average price reported per Mcf		$	4.35	$	7.74
Average price realized per Mcf		$	3.59	$	7.36
VPP increase to gas revenue (in millions)		$	12.2	$	13.4
Increase (decrease) to gas revenue from
	hedging activity (in millions)	$	16.7	$	(0.5)

Interest rate. During January 2008, the Company entered into interest rate swap contracts and designated the contracts as cash flow hedges of the forecasted interest rate risk associated with a portion of the Company's Credit Facility indebtedness. The interest rate swap contracts are 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 interest rate swaps had an effective start date of February 2008, with $200 million terminating during February 2010 and $200 million during February 2011. On February 1, 2009, the Company discontinued hedge accounting on the interest rate swaps.

Hedge ineffectiveness. During the three months ended March 31, 2009 and 2008, the Company had nominal ineffectiveness associated with its derivative contracts. 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 are changes in forecasted hedged sales volumes and commodity price correlations.

26

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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. Consequently, all of the Company’s derivatives were made up of non-hedge derivatives as of March 31, 2009 and both hedge derivatives and non-hedge derivatives as of December 31, 2008. The following tables provide disclosure of the Company’s derivative instruments:

	Fair Value of Derivative Instruments as of March 31, 2009
		Asset Derivatives				Liability Derivatives
	Type		Balance Sheet Location (a)		Fair Value	Balance Sheet Location (a)		Fair Value
				(in thousands)			(in thousands)
Derivatives not designated as hedging instruments under SFAS 133
	Commodity price  derivatives (b)		Derivatives – current	$	118,299	Derivatives - current	$	10,458
	Interest rate derivatives		Derivatives - current		-	Derivatives - current		7,228
	Commodity price  derivatives (c)		Derivatives – noncurrent		82,041	Derivatives - noncurrent		340
	Interest rate derivatives		Derivatives - noncurrent		-	Derivatives - noncurrent		2,493
Total derivatives not designated as hedging     instruments under SFAS 133				$	200,340		$	20,519
Derivatives designated as hedging instruments under SFAS 133
	Commodity price  derivatives		Derivatives - current	$	-	Derivatives - current	$	27,294
	Commodity price  derivatives		Derivatives - noncurrent		-	Derivatives - noncurrent		12,887
Total derivatives designated as hedging instruments under SFAS 133				$	-		$	40,181
Total derivatives				$	200,340		$	60,700

_____________

(a)	As described in Note B, 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, whichever the case may be.
(b)	Current commodity price derivative assets are shown net of $18.3 million of current commodity price derivative liabilities.
(c)	Noncurrent commodity price derivative assets are shown net of $3.4 million of noncurrent commodity price derivative liabilities. Noncurrent commodity price derivative liabilities are shown net of $968 thousand of noncurrent price derivative assets.

27

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

	Fair Value of Derivative Instruments as of December 31, 2008
		Asset Derivatives				Liability Derivatives
	Type		Balance Sheet Location		Fair Value	Balance Sheet Location		Fair Value
				(in thousands)			(in thousands)
Derivatives not designated as hedging instruments under SFAS 133
	Commodity price  derivatives (a)		Derivatives - current	$	2,255	Derivatives - current	$	18,882
	Commodity price   derivatives		Derivatives - noncurrent		3,972	Derivatives - noncurrent		-
Total derivatives not designated as hedging    instruments under SFAS 133				$	6,227		$	18,882
Derivatives designated as hedging instruments under SFAS 133
	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 under SFAS 133				$	125,989		$	51,263
Total derivatives				$	132,216		$	70,145

_____________

(a) Current commodity price derivative assets are shown net of $1.4 million of current commodity price derivative liabilities.

	Amount of Gain/(Loss) Recognized in OCI on Effective Portion
Derivatives in SFAS 133 Cash Flow Hedging Relationships
		March 31, 2009		March 31, 2008
	(in thousands)
Interest rate derivatives	$	(433)	$	(3,319)
Commodity price derivatives		4,968		(223,872)
Total	$	4,535	$	(227,191)

	Location of Gain/(Loss) Reclassified from AOCI into Income	Amount of Gain/(Loss) Reclassified from AOCI into Income
Derivatives in SFAS 133 Cash Flow Hedging Relationships
		March 31, 2009		March 31, 2008
Interest rate derivatives	Interest expense	$	(2,202)	$	82
Commodity price derivatives	Oil and gas revenue		15,260		(71,968)
Total		$	13,058	$	(71,886)

	Location of Gain/(Loss) Recognized in Income on Ineffective Portion	Amount of Gain/(Loss) Recognized in Income on Ineffective Portion
Derivatives in SFAS 133 Cash Flow Hedging Relationships
		March 31, 2009		March 31, 2008
		(in thousands)
Commodity price derivatives	Derivative gains, net		(1)		1,027

28

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

Derivatives Not Designated as Hedging Instruments under SFAS 133	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
		March 31, 2009		March 31, 2008
		(in thousands)
Interest rate derivatives	Interest expense	$	(932)	$	-
Commodity price derivatives	Derivative gains, net		100,795		-
Total		$	99,863	$	-

AOCI - Hedging. The fair value of the effective portion of the derivative contracts on January 31, 2009 is reflected 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 fair values of its derivative contracts as gains or losses in the earnings of the period in which they occur.

As of March 31, 2009 and December 31, 2008, AOCI - Hedging represented net deferred gains of $74.1 million and $88.8 million, respectively. The AOCI - Hedging balance as of March 31, 2009 was comprised of $68.4 million of net deferred gains on the effective portions of open cash flow hedges, $74.6 million of net deferred gains on terminated cash flow hedges (including $2.5 million of net deferred losses on terminated cash flow interest rate hedges) and $68.9 million of associated net deferred tax provisions. The decrease in net deferred hedge gains comprising AOCI - Hedging during the three months ended March 31, 2009 was primarily attributable to decreases in future oil, NGL and gas prices relative to the commodity prices stipulated in the hedge contracts and the reclassification of net deferred hedge gains to net income as derivatives matured. Decreases in forward interest rate yield curves also increased the fair value obligation associated with the Company's interest rate swap contracts.

During the year ending March 31, 2010, the Company expects to reclassify approximately $44.9 million of net deferred gains to oil and gas revenues and $6.2 million of net deferred losses to interest expense from AOCI - Hedging. The Company also expects to reclassify approximately $11.5 million of net deferred income tax provisions associated with hedge derivatives during the year ending March 31, 2010 from AOCI - Hedging to income tax expense.

Terminated commodity hedges. At times, the Company terminates open commodity hedge positions when the underlying commodity prices reach a point that the Company believes will be the high or low price of the commodity prior to the scheduled settlement of the open commodity position. This allows the Company to lock-in gains or minimize losses associated with the open hedge positions. At the time of termination of the hedges, 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 March 31, 2009, the scheduled amortization of net deferred (gains) and losses on terminated commodity hedges that will be recognized as (increases) or decreases to the Company's future oil and gas revenues:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Total
	(in thousands)
2009 net deferred hedge gains			$	(11,449)	$	(11,642)	$	(11,111)	$	(34,202)
2010 net deferred hedge gains	$	(12,081)	$	(12,301)	$	(12,517)	$	(12,581)	$	(49,480)
2011 net deferred hedge losses	$	873	$	889	$	903	$	906	$	3,571
2012 net deferred hedge losses	$	810	$	791	$	784	$	772	$	3,157

29

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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 months ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009		2008
		(in thousands)
Beginning asset retirement obligations		$	172,433	$	208,184
	New wells placed on production and changes in estimates (a)		39		(8,422)
	Liabilities settled		(1,930)		(1,533)
	Accretion of discount		2,974		2,142
Ending asset retirement obligations		$	173,516	$	200,371

_____________

(a) During the three months ended March 31, 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.

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the consolidated balance sheets. As of March 31, 2009 and December 31, 2008, the current portions of the Company's asset retirement obligations were $29.4 million and $29.9 million, respectively.

NOTE I. Postretirement Benefit Obligations

As of March 31, 2009 and December 31, 2008, the Company had $9.5 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 March 31, 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 months ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009		2008
		(in thousands)
Beginning accumulated postretirement benefit obligations		$	9,612	$	10,494
	Net benefit payments		(329)		(298)
	Service costs		57		48
	Accretion of interest		164		157
Ending accumulated postretirement benefit obligations		$	9,504	$	10,401

30

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

NOTE J.Commitments and Contingencies

Legal actions. The Company is party to the legal actions that are described below. The Company is also party to other proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. 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 is before the Judicial District Court of Harris County, Texas (334th Judicial District).

On April 27, 2009, the Company and all parties in the lawsuit reached an agreement to settle the lawsuit. Under the terms of the 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 Company will also contribute to the Trust 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 sold in conjunction with the Trust’s sale of its assets.

The settlement agreement is subject to customary conditions, including court approval and the dismissal of the case with prejudice.

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.

SemGroup accounts receivable. The Company is a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries (collectively, "SemGroup"), which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22, 2008 in the U.S. Bankruptcy Court for the District of Delaware. As of March 31, 2009, the Company had approximately $29.6 million of delinquent receivables from SemGroup, representing claims for condensate sold pre-petition to SemGroup.

The Company determined that it was probable that the collection of the pre-petition claims would not occur for a protracted period of time and that some of its claims may have been uncollectible. Consequently, the Company recorded a bad debt expense of approximately $19.6 million during the third quarter 2008, which reduced the carrying value of the claims to approximately $10.0 million.

In April 2009, the Company sold all of its pre-petition claims against SemGroup to a third party for approximately $10.1 million, pursuant to a purchase agreement that contains customary representations, warranties and other provisions. If a portion of the claims become impaired due to circumstances arising from a breach of such representations and warranties, then the Company may be required to repurchase such impaired portion of the claims.

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.

31

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

NOTE K. Income Per Share From Continuing Operations

Basic income per share from continuing operations is computed by dividing income from continuing operations by the weighted average number of common shares outstanding for the period. The computation of diluted income 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, 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 following table is a reconciliation of basic income (loss) from continuing operations to diluted income (loss) from continuing operations for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
		2009		2008
		(in thousands)
Basic net income (loss) attributable to common stockholders	$	(14,606)	$	127,960
Participating share-based earnings (a)		(121)		(1,674)
Diluted net income (loss) attributable to common stockholders	$	(14,727)	$	126,286

_____________

(a) In accordance with FSP EITF 03-6-1, unvested restricted stock share awards and restricted stock unit awards represent participating securities because they participate in undistributed earnings with the Company’s common stock. Participating share-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities.

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three-month periods ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009	2008
		(in thousands)
Weighted average common shares outstanding (a):
	Basic	114,242	117,934
	Dilutive common stock options (b) (c)	-	326
	Diluted	114,242	118,260

_____________

(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 March 31, 2009. During the three months ended March 31, 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 under the two-class method for the three months ended March 31, 2008. Under the two-class method, the following common stock equivalents were excluded from the calculation: 305,277 of performance units for which shares are contingently issuable and options to purchase 621,469 common shares.
(c)	Due to the loss from continuing operations during the three months ended March 31, 2009, the potential dilutive effects of 2,366,606 of restricted stock awards, 484,690 of performance units for which shares are contingently issuable and stock options to purchase 317,886 common shares would be anti-dilutive.

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.

32

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

The following tables provide the Company's geographic operating segment data for the three months ended March 31, 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.

				United States		South Africa		Tunisia		Headquarters		Consolidated Total
Three Months Ended March 31, 2009:					(in thousands)
	Revenues and other income:
		Oil and gas		$	333,770	$	11,806	$	28,261	$	-	$	373,837
		Derivative gains, net			-		-		-		99,863		99,863
		Interest and other			-		-		-		10,660		10,660
		Gain on disposition of assets, net			-		-		-		(115)		(115)
					333,770		11,806		28,261		110,408		484,245
	Costs and expenses:
		Oil and gas production			100,647		3,497		8,825		-		112,969
		Production and ad valorem taxes			27,758		-		-		-		27,758
		Depletion, depreciation and  amortization			164,383		16,554		4,317		7,303		192,557
		Impairment of oil and gas properties			21,091		-		-		-		21,091
		Exploration and abandonments			23,651		94		7,304		382		31,431
		General and administrative			-		-		-		34,639		34,639
		Accretion of discount on asset
			retirement obligations		-		-		-		2,974		2,974
		Interest			-		-		-		41,138		41,138
		Hurricane activity, net			-		-		-		375		375
		Other			20,286		-		-		11,103		31,389
					357,816		20,145		20,446		97,914		496,321
	Income (loss) from continuing
		operations before income taxes			(24,046)		(8,339)		7,815		12,494		(12,076)
	Income tax benefit (provision)				8,897		2,418		(5,046)		(5,006)		1,263
	Income (loss) from continuing   operations			$	(15,149)	$	(5,921)	$	2,769	$	7,488	$	(10,813)

33

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

				United States		South Africa		Tunisia		Headquarters		Consolidated Total
Three Months Ended March 31, 2008:				(in thousands)
	Revenues and other income:
		Oil and gas		$	492,037	$	29,580	$	36,859	$	-	$	558,476
		Derivative gains, net			-		-		-		1,027		1,027
		Interest and other			-		-		-		25,024		25,024
		Gain on disposition of assets, net			(3)		-		-		681		678
					492,034		29,580		36,859		26,732		585,205
	Costs and expenses:
		Oil and gas production			81,402		9,980		3,237		-		94,619
		Production and ad valorem taxes			38,028		-		-		-		38,028
		Depletion, depreciation and amortization			96,204		4,392		1,721		7,310		109,627
		Exploration and abandonments			25,824		48		10,114		2,691		38,677
		General and administrative			-		-		-		36,481		36,481
		Accretion of discount on asset
			retirement obligations		-		-		-		2,142		2,142
		Interest			-		-		-		40,278		40,278
		Hurricane activity, net			458		-		-		-		458
		Other			7,861		-		-		4,054		11,915
					249,777		14,420		15,072		92,956		372,225
	Income (loss) from continuing
		operations before income taxes			242,257		15,160		21,787		(66,224)		212,980
	Income tax benefit (provision)				(89,635)		(4,396)		(14,100)		21,909		(86,222)
	Income (loss) from continuing operations			$	152,622	$	10,764	$	7,687	$	(44,315)	$	126,758

NOTE M. Impairments

Oil and gas properties assessments. During the three months ended March 31, 2009, 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 the Company's Uinta/Piceance 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 a $21.1 million noncash charge during the first quarter of 2009 to reduce the carrying value of the Uinta/Piceance area oil and gas properties. The impairment charge reduced the oil and gas properties' carrying values to their estimated fair values, represented by the estimated discounted future cash flows attributable to the assets.

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.

Goodwill assessments. In accordance with SFAS 142, the Company assesses its goodwill for impairment annually on July 1, and on July 1, 2008, the Company's assessment of goodwill 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 and continuing into the first quarter of 2009, the Company reassessed whether the fair value of its net assets supported the carrying value of the Company's goodwill at its United States reporting unit. The Company's reassessment indicated that its goodwill was not impaired as of March 31, 2009 and December 31, 2008.

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 entailed estimating the fair values of the reporting unit's assets and liabilities. The primary component of those assets and liabilities is comprised of the

34

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

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 Company's weighted average cost of capital and (iv) future income tax expense attributable to the net cash flows.

Due to the significant decline in the Company's market capitalization, 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 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. Those assessments indicated that the United States goodwill was not impaired as of March 31, 2009 and December 31, 2008. The Company will continue to assess its goodwill for impairment 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.

Under SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies," a VPP is considered a sale of proved reserves. As a result, 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.

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		(12,189)		(24,530)		(36,719)
Deferred revenue at March 31, 2009	$	37,246	$	251,176	$	288,422

35

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

         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	$	111,187
2010		90,215
2011		44,951
2012		42,069
	$	288,422

NOTE O. Interest and Other Income

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

	Three Months Ended March 31,
	2009		2008
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	7,478	$	11,163
Foreign currency remeasurement and exchange gains (b)		1,351		3,514
Deferred compensation plan income		787		1,371
Other income		607		1,069
Interest income		437		484
Change in asset retirement estimate		-		4,391
Legal settlements		-		2,497
California emission credits		-		535
Total interest and other income	$	10,660	$	25,024

_____________

(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.

36

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

NOTE P.Other Expense

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

	Three Months Ended March 31
	2009		2008
	(in thousands)
Idle rig related costs (a)	$	20,286	$	7,861
Contingency and environmental accrual adjustments (see Note J)		5,598		444
Well servicing operations (b)		2,991		743
Inventory impairment (c)		1,170		-
Foreign currency remeasurement and exchange losses		1,325		373
Other charges		705		525
Bad debt (recoveries) expense		(686)		1,969
Total other expense	$	31,389	$	11,915

_____________

(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)	Represents idle well servicing costs.
(c)	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. The Company currently estimates that it will cost approximately $185 million to reclaim and abandon the East Cameron facility. The operations to reclaim and abandon the East Cameron facilities began in January 2007. The estimate to reclaim and abandon the East Cameron facility is based upon an analysis prepared by a third party engineering firm for a majority of the work, an estimate by the Company for the remaining work that was not covered by the third-party analysis and actual abandonment activity to date.

The $185 million estimate to reclaim and abandon the East Cameron facilities contains a number of assumptions that could cause the ultimate cost to be higher or lower as there are many uncertainties when working offshore and underwater with damaged equipment and wellbores. The Company currently believes costs could range from $185 million to $200 million. Currently, no better estimate within the range can be determined. Thus the Company has recorded the estimated provision of $185 million, of which approximately $161.4 million has been expended through March 31, 2009. The Company expects to incur the remaining $23.6 million in 2009.

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.

In the first quarter of 2007, the Company received $5 million from one of its insurance providers related to debris removal. At the present, 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 continues to expect that a substantial portion of the loss will be recoverable from insurance. During the first quarter of 2009, the Company received $10.2 million of insurance recoveries associated with East Cameron facilities that reduced the amount recorded as a receivable from insurance carriers during 2006.

37

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(Unaudited)

NOTE R. Discontinued Operations

In April 2006 and November 2007, the Company completed the sale of its Argentine assets and Canadian subsidiaries, respectively. Pursuant to SFAS 144, the Company has reflected the results of operations of these transactions as discontinued operations, rather than as a component of continuing operations. The Company did not have any discontinued operations activity during the three months ended March 31, 2009. The following table represents the components of the Company's discontinued operations for the three month periods ended 2008:

		Three Months Ended March 31, 2008
		(in thousands)
Revenues and other income:
	Interest and other	$	1,903
	Gain on disposition of assets, net (a)		66
			1,969
Costs and expenses:
	General and administrative		257
	Other		45
			302
Income from discontinued operations before income taxes			1,667
Income tax benefit (provision):
	Current		(519)
	Deferred (a)		792
Income (loss) from discontinued operations		$	1,940

_____________

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

NOTE S. Subsequent Events

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 & Poors 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% of the market value of its ownership of common units of Pioneer Southwest. 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. 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.

As of the date of the amendment, the Company was in compliance with all of its debt covenants under the Credit Facility, including the original covenant to maintain a ratio of the net present value of oil and gas properties to total debt of at least 1.75 to 1.0.

After taking into account the amendment, revolving loans 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 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).

38

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 first quarter of 2009 included the following highlights:

• Earnings attributable to common stockholders declined to a loss of $14.6 million ($(0.13) per share), as compared to net income attributable to common stockholders of $128.0 million ($1.07 per diluted share) for the first quarter of 2008. The decrease in earnings attributable to common stockholders was primarily due to commodity price declines, associated negative reserve price revisions, which increased depreciation, depletion and amortization expense, and additional impairment of the Company’s Uinta/Piceance oil and gas assets, partially offset by increases in commodity derivative hedge and non-hedge gains.

• Daily sales volumes increased on a per-BOE basis by 15 percent to 127,005 BOEPD during the first quarter of 2009, as compared to 110,298 BOEPD during the first quarter of 2008. The increase in daily sales volumes included approximately 2,502 BOEPD of NGL sales of inventory that was held in storage as of December 31, 2008 due to hurricane damage to third-party downstream processing facilities in September 2008.

• Oil and gas sales decreased by 33 percent to $373.8 million for the first quarter of 2009, as compared to $558.5 million for the first quarter of 2008. The decrease in oil and gas sales was primarily due to declines in commodity prices and the Company’s change from derivative hedge accounting to the mark-to-market method of accounting for derivatives as of February 1, 2009, partially offset by the 15 percent increase in sales volumes and a $122.0 million increase in commodity hedge results.

• Net cash provided by operating activities decreased by $153.3 million to $24.4 million for the first quarter of 2009, as compared to $177.7 million in the comparable quarter of 2008. The decrease in net cash provided by operating activities was primarily due to the decrease in oil and gas revenue.

• Derivative gains, net increased by $98.8 million to $99.9 million for the first quarter of 2009, as compared to $1.0 million for the first quarter of 2008. Derivative gains, net represent realized and unrealized non-hedge derivative gains. The derivative gains primarily resulted from declines in future commodity prices relative to the commodity prices contained in the Company’s non-hedge derivative contracts.

• The purchase of 1.0 million shares of the Company's common stock at an aggregate cost of $16.3 million under the Company's share repurchase program.

Recent Events

Financial markets. During the second half of 2008, worldwide financial markets experienced significant turmoil as concerns regarding a worldwide economic slowdown increased and the availability of liquidity provided by the financial markets declined. These concerns have continued into 2009. In response to these circumstances, governments worldwide have announced economic stimulus programs and taken steps to enhance confidence in and support the financial markets. The success of these actions and the duration of the uncertainty in financial markets cannot be predicted. The Company is closely monitoring the economic environment, the effects of which are mitigated, in part, by the Company’s derivative price risk management activities. As a result, the Company does not expect that current market conditions will significantly impact its liquidity, results of operations or financial position in the near term. 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. Longer-term, depending on the severity and duration of the worldwide economic decline, these market conditions could negatively impact the Company’s liquidity, financial position and future results of operations.

As of March 31, 2009, the Company had $44.5 million of cash on hand and $370.0 million of liquidity under its Credit Facility that matures in 2012. As of March 31, 2009, the Company was also a party to derivative financial instruments, of which approximately $200.3 million represent assets. Management is closely monitoring the credit standings of its counterparties, including its banks, derivative counterparties and purchasers of the commodities the Company produces and sells.

The Company’s Credit Facility is subject to certain covenants, including the maintenance of a ratio of the net present value of the Company’s oil and gas properties to total debt (the "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

39

PIONEER NATURAL RESOURCES COMPANY

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 common units of Pioneer Southwest. As of March 31, 2009, the Company was in compliance with all of its debt covenants.

Commodity prices. The reduced liquidity provided by the worldwide financial markets and other factors have resulted in an economic slowdown in the United States and other industrialized countries, which has further resulted in significant reductions in worldwide energy demand. At the same time, North American gas supply has increased as a result of the rise in domestic gas production. The combination of lower demand due to the economic slowdown and higher North American gas supply has resulted in significant declines in oil, NGL and gas prices from their highs in mid-2008. Although the Company has entered into derivative contracts on portions 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 duration and magnitude of the commodity price declines cannot be predicted. A sustained decline in commodity prices could result in a shortfall in expected cash flows.

Cost reduction initiatives. During the first quarter of 2009, 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 financial flexibility. This plan includes minimizing drilling activities until margins improve as a result of (i) commodity prices increasing, (ii) gas price differentials in the areas where the Company produces gas narrowing relative to NYMEX quoted prices and/or (iii) well cost reductions. As a result, the Company has significantly reduced its rig activity and continues to pursue reductions in operating expenses and well costs to align costs with the lower commodity price environment that currently exists. Rigs have been terminated or stacked in the Spraberry, Raton, Edwards Trend and Barnett Shale areas and in Tunisia. During the first quarter of 2009, the Company has also achieved lease operating expense reductions and anticipates additional operating cost savings in future periods. Since the third quarter of 2008, when drilling and completion costs peaked, the Company has achieved an average reduction of approximately 25 percent in the cost of drilling and completing a well and is targeting an additional five to ten percent reduction. The Company’s asset teams are also implementing initiatives to reduce 2009 lease operating expense by at least 15 percent compared to 2008. The Company is targeting cost reductions in electricity, water disposal and compression rental costs while expanding its use of integrated services.

The Company’s 2009 capital budget is limited to approximately $300 million (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs), representing a 76 percent decrease from actual 2008 annual capital costs. During the first quarter of 2009, the Company’s capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $108.1 million, as compared to $305.9 million during the first quarter of 2008, representing a 65 percent decrease. The first quarter 2009 capital expenditures were front-end loaded as the Company completed wells in progress at year end 2008, finished previously scheduled drilling in Tunisia and further curtailed drilling activity in response to declining commodity prices during the quarter.

SemGroup receivables. The Company was a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries (collectively, "SemGroup"), which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 22, 2008 in the U.S. Bankruptcy Court for the District of Delaware. SemGroup purchased condensate from the Company and, at the time of the bankruptcy filings, was indebted to the Company for $29.6 million. The Company believed that it was probable that the collection of the pre-petition claims would not occur for a protracted period of time and that some of its claims may become uncollectible. Consequently, the Company recorded a bad debt expense of $19.6 million during the second half of 2008, which reduced the carrying value of the claims to $10.0 million.

In April 2009, the Company sold all of its pre-petition claims against SemGroup to a third party for approximately $10.1 million, pursuant to a purchase agreement that contains customary representations, warranties and other provisions. If a portion of the claims become impaired due to circumstances arising from a breach of such representations and warranties, then the Company may be required to repurchase such impaired portion of the claims.

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PIONEER NATURAL RESOURCES COMPANY

Second Quarter 2009 Outlook

Based on current estimates, the Company expects that second quarter 2009 production will average 117,000 to 122,000 BOEPD. The range reflects the typical variability in the timing of oil cargo shipments in Tunisia.

Second quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $12.00 to $13.00 per BOE based on NYMEX strip prices for oil, NGLs and gas at the time of the estimate. Depletion, depreciation and amortization ("DD&A") expense is expected to average $16.00 to $17.00 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $15 million to $25 million, primarily related to exploration wells in progress, including related acreage costs, and seismic and personnel costs. General and administrative expense is expected to be $33 million to $37 million. Interest expense is expected to be $42 million to $45 million, reflecting the higher borrowing costs associated with the Company’s April 2009 amendment to the Credit Facility. 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 $4 million to $7 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company also expects to recognize $15 million to $20 million of charges in other expense associated with certain drilling rigs being stacked as a result of the Company's low price environment initiatives.

The Company's second quarter effective income tax rate is expected to range from 40 percent to 50 percent based on current capital spending plans and higher tax rates in certain foreign jurisdictions. Cash income taxes are expected to range from $5 million to $10 million, principally related to Tunisian income taxes.

Second quarter 2009 amortization of deferred gains on terminated oil and gas hedges is expected to be $12 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 three month period ended March 31, 2009, the Company’s capital expenditures, excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, were approximately $108.1 million. If internal cash flows do not meet the Company's expectations, the Company may further reduce its level of capital expenditures, further 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.

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PIONEER NATURAL RESOURCES COMPANY

         The following table summarizes by geographic area the Company's finding and development costs incurred during the three month period ended March 31, 2009:

										Asset
		Acquisition Costs				Exploration		Development			Retirement
		Proved		Unproved		Costs		Costs		Obligations		Total
		(in thousands)
United States:
	Permian Basin	$	1,385	$	1,682	$	2,241	$	46,663	$	-	$	51,971
	Mid-Continent		-		-		209		150		-	��	359
	Rocky Mountains		29		50		4,789		14,667		-		19,535
	Barnett Shale		85		(449)		2,934		(40)		-		2,530
	Gulf of Mexico		-		-		95		(23)		-		72
	Onshore Gulf Coast		1,447		4,419		9,930		732		-		16,528
	Alaska		-		(335)		1,159		22,916		38		23,778
			2,946		5,367		21,357		85,065		38		114,773
South Africa			-		-		94		911		-		1,005
Tunisia			-		-		7,936		4,968		-		12,904
Other			-		-		382		-		-		382
			-		-		8,412		5,879		-		14,291
Total Worldwide		$	2,946	$	5,367	$	29,769	$	90,944	$	38	$	129,064

The following table summarizes the Company's development and exploration/extension drilling activities for the three months ended March 31, 2009:

	Development Drilling
	Beginning Wells	Wells	Successful	Unsuccessful	Ending Wells
	in Progress	Spud	Wells	Wells	in Progress
United States	7	16	18	-	5

	Exploration/Extension Drilling
	Beginning Wells	Wells	Successful	Unsuccessful	Ending Wells
	in Progress	Spud	Wells	Wells	in Progress
United States	10	1	1	-	10
Tunisia	5	-	-	2	3
Total Worldwide	15	1	1	2	13

Permian Basin area. In the Spraberry field, first quarter 2009 daily production was up 23 percent compared to first quarter 2008 reflecting the success of the 2008 drilling program. First quarter 2009 production totaled 37 MBOEPD, of which approximately 2,500 Bbls per day was related to the sales of inventoried NGLs that were not able to be fractionated and sold in the fourth quarter as a result of hurricane damage to third-party fractionation facilities. The Company drilled 17 wells in the Spraberry field during the three months ended March 31, 2009. As a result of the Company’s cost reduction initiatives, the Company does not currently have any rigs drilling in the field. Under a reduced drilling program for 2009, the Company expects to drill a total of 27 wells primarily to protect leasehold rights. The majority of these Spraberry wells are being drilled deeper to add the Wolfcamp formation, which provides incremental production and proved reserves. New oil price derivatives and forward market prices for oil exceeding $60 per Bbl for 2010 and 2011 are supportive of the Company's plan to recommence drilling in early 2010.

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

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PIONEER NATURAL RESOURCES COMPANY

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 19 wells on production, the results are encouraging.

The Company's Spraberry field waterflood project includes plans to convert a select number of wells to water injection wells and potentially drill additional injection wells in 2010, subject to improved commodity prices. The Company continues evaluating non-traditional shale/silt intervals in ten wells previously completed and added two additional wells in the first quarter of 2009.

The 20-acre well spacing and other initiatives described above are being performed to enhance the Spraberry field recovery percentage in those areas of the 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. The Company continues to maintain field production 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. Additional gathering system analysis and improvements are planned to begin in late-2009.

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 the successful lateral well cleanout program.

Rocky Mountains area. The Company’s Raton Basin production volumes totaled 17.5 BCF during the first quarter of 2009, compared to 17.9 BCF during the same period in 2008, although no drilling or completion work was conducted in the first quarter of 2009. The Company was able to maintain relatively stable production through initiatives such as compressor upgrades and modifications made at the Company’s compressor stations that occurred during the first quarter of 2009 and during 2008. In support of the Company’s cost reduction initiatives, efforts are underway in the Rocky Mountains area to reduce operating costs, including improving operational methods. The detailed basin-wide evaluation of data obtained from 2008 Pierre Shale drilling operations continues in conjunction with further 2009 production and formation testing in preparation for future drilling operations once gas prices recover or drilling costs decline. State and federal permitting efforts continue on CBM and Pierre Shale locations.

Onshore Gulf Coast area. In South Texas, the Company’s first quarter 2009 daily production rose 28 percent versus the prior year quarter as a result of a strong drilling program in 2008. The Company drilled its first horizontal well in the expanding Eagle Ford Shale play, where it holds a substantial acreage position within the targeted gas play. Current plans are to fracture stimulate the well during May 2009. A second well to test the Eagle Ford Shale is planned during the third quarter of 2009. The Eagle Ford Shale play is prospective over much of the 310,000 acres that the Company currently holds.

In the Edwards Trend, the Company logged over 200 feet of productive Edwards-formation gas-bearing sands in its Amberjack discovery well in DeWitt County during the first quarter of 2009. The discovery well is currently waiting for a lateral interval to be drilled. Additional Edwards-formation drilling plans designed to further exploit the Moray, Sawfish, Skipjack and Amberjack discoveries found from 2007 to 2009 have been temporarily suspended in support of the Company’s cost reduction initiatives.

In order to accommodate its Edwards Trend growth, the Company has completed construction of, and is currently utilizing, additional gas gathering and processing infrastructure. The expansion includes over 28 miles of gathering system pipeline, three additional operated gas treatment plants and two additional non-operated gas treatment plants. The acquisition of 3-D seismic data has significantly enhanced field development in all areas of the Edwards Trend, allowing the Company to more accurately locate and orient the horizontal wells for optimal results. During 2008, the Company expanded its 3-D data coverage by adding 900 square miles of new data, including coverage of new discoveries and additional prospects. The Company continues to both renew and expand its leasehold position in South Texas.

Barnett Shale. During the first quarter of 2009, the Company focused its efforts on improving operational performance. Included in this effort were multiple successful well workovers and compressor maintenance projects. The Company may also acquire additional Barnett Shale area 3-D seismic for evaluation.

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PIONEER NATURAL RESOURCES COMPANY

Alaska area. During the first quarter of 2009, the Company continued drilling activities at Oooguruk. Net production from the project averaged 3,889 BOEPD during the first quarter of 2009. First quarter production was restricted due to a lack of injection water supply from a third party facility for waterflood operations. The Company anticipates that this problem will be resolved in the second quarter of 2009. The Company’s Oooguruk development drilling program will continue throughout 2009. The Company plans to drill and fracture stimulate two Nuiqsut production wells this summer and forecasts 2009 net production to average 5,000 BPD, despite the current water injection constraints. As development drilling continues, net production is currently forecast to gradually increase to 10,000 Bbls of oil per day to 14,000 Bbls of oil per day in 2011. Well performance and the results of this summer’s activities will be evaluated later this year to determine potential upside to the production forecast.

On the Cosmopolitan project, 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 unstimulated production test results were encouraging. The Company will conduct permitting activities and facilities planning throughout 2009 and plans to drill another appraisal well in 2010.

South Africa. In South Africa, first quarter 2009 production was up 43 percent compared to the same quarter in 2008 reflecting the commencement of production from the most prolific well in Pioneer’s South Coast Gas Project during fourth quarter 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. First quarter 2009 production was curtailed slightly as a result of ongoing repairs to the operator’s onshore condensate handling unit.

Tunisia. First quarter 2009 daily production in Tunisia was up 60 percent compared to the first quarter of 2008. In the Cherouq Concession, first sales occurred during the first quarter of 2008 and gross cumulative production exceeded 3.4 million barrels by the end of the first quarter 2009. During 2009, the Company plans to complete the processing of the 295 square kilometers of 3-D seismic data acquired in 2008. The geosciences work program will include 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. Additionally, the Company plans to upgrade its existing production facilities to install permanent equipment and enhance well performance.

During 2009, the Company plans to continue its exploratory and appraisal activities on the Adam Concession by drilling up to three wells and begin a 3-D seismic acquisition program on the Borj El Khadra Permit.

In the Anaguid permit during 2008, the Company acquired an additional 900 square kilometers of 3-D seismic data and drilled one successful exploration well. The Company plans to complete the processing and interpretation of the seismic data and drill an additional exploration well during 2010.

The El Hamra exploration permit covers approximately 4,000 square kilometers, of which the Company is operator with a 50 percent working interest during the exploration period. In 2008, the Company completed processing of 310 kilometers of seismic data and drilled one unsuccessful exploration well. The Company plans on further interpretation of the seismic data during 2009.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $373.8 million for the three months ended March 31, 2009, as compared to $558.5 million for the first quarter of 2008.

The decrease in oil and gas revenues during the three months ended March 31, 2009, as compared to the first quarter 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 oil, NGL and gas prices, partially offset by sales volume increases resulting from successful 2008 drilling activity, sales of approximately 2,500 BOEPD of NGLs that were in storage as of December 31, 2008 and reductions in scheduled VPP deliveries. Revenues in Tunisia decreased due to decreases in average reported oil and gas prices, partially offset by oil and gas sales volume increases due to successful drilling programs. Revenues in South Africa decreased due to the completion of the planned shutdown of the Sable field oil production and initiation of gas production from the Sable field and decreases in average reported oil and gas prices, partially offset by a gas sales volume increase from the South Coast Gas project.

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PIONEER NATURAL RESOURCES COMPANY

         The following table provides average daily sales volumes, by geographic area and in total, for the three months ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009	2008
Oil (Bbls):
	United States	27,456	21,419
	South Africa	245	2,823
	Tunisia	6,349	3,903
	Worldwide	34,050	28,145
NGLs (Bbls):
	United States	22,699	19,408
Gas (Mcf):
	United States	388,901	369,819
	South Africa	30,283	5,073
	Tunisia	2,346	1,578
	Worldwide	421,530	376,470
Total (BOE):
	United States	114,973	102,463
	South Africa	5,292	3,669
	Tunisia	6,740	4,166
	Worldwide	127,005	110,298

On a quarter-to-quarter BOE comparison, average daily sales volumes increased by 12 percent in the United States, by 44 percent in South Africa and by 62 percent in Tunisia.

During the three-month period ended March 31, 2009, as compared to the three-month period ended March 31, 2008, oil volumes delivered under the Company's VPPs decreased by 42 MBbl (6 percent), while gas volumes delivered under the Company's VPPs decreased by 255 MMcf (9 percent).

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 and AOCI – Hedging gains for hedges that were discontinued on January 31, 2009.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides average reported prices (including the results of hedging activities and the amortization of deferred VPP revenue) and average realized prices (excluding the results of hedging activities and the amortization of deferred VPP revenue) by geographic area and in total, for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009		2008
Average reported prices:
Oil (per Bbl):
United States	$	54.15	$	70.23
South Africa	$	47.00	$	101.48
Tunisia	$	47.25	$	99.36
Worldwide	$	52.82	$	77.41
NGL (per Bbl):
United States	$	22.97	$	53.89
Gas (per Mcf):
United States	$	4.37	$	7.73
South Africa	$	3.95	$	7.61
Tunisia	$	5.96	$	10.90
Worldwide	$	4.35	$	7.74
Average realized prices:
Oil (per Bbl):
United States	$	35.18	$	97.64
South Africa	$	47.00	$	101.48
Tunisia	$	47.25	$	99.36
Worldwide	$	37.51	$	98.26
NGL (per Bbl):
United States	$	21.82	$	54.28
Gas (per Mcf):
United States	$	3.55	$	7.34
South Africa	$	3.95	$	7.61
Tunisia	$	5.96	$	10.90
Worldwide	$	3.59	$	7.36

Derivative activities. The Company utilizes commodity swap and 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. Under hedge accounting, the effective portions of changes in the fair values of the Company's commodity price hedges are 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 matured or was terminated. During the first quarter of 2009, the Company’s commodity derivative hedges increased oil, NGL and gas revenues by $41.4 million, as compared to having reduced oil, NGL and gas revenues by $80.6 million during the first quarter of 2008.

Effective February 1, 2009, the Company discontinued hedge accounting on all existing derivative instruments and from that date forward accounted for derivative instruments using the mark-to-market accounting method.

Subsequent to March 31, 2009, the Company has continued to increase its 2010 and 2011 oil and gas derivatives positions to support the resumption of oil drilling in those years. Specifically, the Company has aggregate derivative positions covering approximately 30 percent and 70 percent of its 2010 forecasted oil and gas production, respectively, and approximately 25 percent of its forecasted 2011 oil production. See "Derivative gains, net" for additional information regarding the Company’s commodity derivative activities.

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PIONEER NATURAL RESOURCES COMPANY

Deferred revenue. During the three-month periods ended March 31, 2009 and 2008, the Company’s amortization of deferred VPP revenue increased oil and gas revenues by $36.7 million and $39.5 million, respectively. 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.

Derivative gains, 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 period in which they occur. During the three months ended March 31, 2009, the Company's commodity price derivatives increased derivative gains, net by $99.9 million, of which amount $74.5 million represented unrealized gains subject to continuing market risk, and $25.4 million represented realized gains.

Interest and other income. Interest and other income from continuing operations for the three-month periods ended March 31, 2009 and 2008 was $10.7 million and $25.0 million, respectively. The $14.3 million decrease in interest and other income from continuing operations during the three months ended March 31, 2009, as compared to the same period in 2008, was primarily due to (i) $4.4 million of income associated with a decrease in asset retirement obligations in the first quarter of 2008, (ii) a $3.7 million decrease in Alaskan petroleum production taxes, (iii) $2.5 million of legal settlement gains recognized during the first quarter of 2008 and (iv) a $2.2 million decrease in foreign exchange gains. 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 $113.0 million and $94.6 million during the three-month periods ended March 31, 2009 and 2008, respectively. 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 are related to volumes produced. Net natural gas plant/gathering charges represent the net costs to gather and field process the Company’s natural gas, reduced by net revenues earned from gathering and field processing third party gas in Company-owned facilities.

Total oil and gas production costs per BOE increased by five percent during the three-month period ended March 31, 2009, as compared to the same period in 2008, primarily due to general inflation of field service costs, electricity charges and water hauling fees.

During 2008, the Company’s oil and gas production costs increased throughout 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, Pioneer has realized significant production cost reductions during the first quarter of 2009 as compared to similar costs in the fourth quarter of 2008 and anticipates additional cost savings in future periods. 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 that has significantly lower production costs. The increase in Tunisia production costs is associated with the start-up of Cherouq production using rental facilities. Once permanent facilities are installed in 2009, the Tunisia production costs should decline.

The following tables provide the components of the Company's oil and gas production costs per BOE and total production costs per BOE by geographic area for the three-month periods ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009		2008
Lease operating expenses	$	7.87	$	7.56
Third-party transportation charges		0.93		0.99
Net natural gas plant/gathering charges		0.47		0.21
Workover costs		0.61		0.67
Total production costs	$	9.88	$	9.43

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PIONEER NATURAL RESOURCES COMPANY

	Three Months Ended March 31,
	2009		2008
United States	$	9.72	$	8.72
South Africa	$	7.34	$	29.90
Tunisia	$	14.55	$	8.54
Worldwide	$	9.88	$	9.43

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $27.8 million and $38.0 million during the three-month periods ended March 31, 2009 and 2008, respectively. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, ad valorem taxes are established in Texas based upon prior year commodity prices whereas production taxes are based upon current year commodity prices.

Total production and ad valorem taxes per BOE decreased by 36 percent during the three-month period ended March 31, 2009, as compared to the same period in 2008, primarily due to commodity price decreases.

The following table provides the Company's production and ad valorem taxes per BOE and total production and ad valorem taxes per BOE for the three-month periods ended March 31, 2009 and 2008:

		Three Months Ended March 31,
		2009		2008
Taxes:
	Ad valorem	$	1.41	$	1.30
	Production		1.02		2.49
Total ad valorem and production taxes		$	2.43	$	3.79

Depletion, depreciation and amortization expense. The Company's total DD&A expense was $192.6 million ($16.85 per BOE) and $109.6 million ($10.92 per BOE) for the three-month periods ended March 31, 2009 and 2008, respectively. The increase of $83.0 million during the three-month period ended March 31, 2009, as compared to the first quarter of 2008, is primarily comprised of an increase in depletion of oil and gas properties of $82.9 million.

Depletion expense was $16.21 per BOE during the three months ended March 31, 2009, as compared to $10.19 per BOE during the first quarter of 2008. The 59 percent increase in per BOE depletion expense is primarily due to (i) incremental Raton area depletion as a result of a substantial portion of the Raton area's proved undeveloped reserves being uneconomical at quarter-end gas prices, (ii) losing end-of-life reserves that became uneconomic as a result of lower commodity prices, (iii) a generally increasing trend 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 (iv) the relatively higher depletion rate per BOE associated with production from the Oooguruk development, which began first production in June 2008, and South African South Coast Gas project, which became fully operational in October 2008.

Since the second half of 2008, the Company's proved reserves have been negatively impacted by commodity price declines. See "Recent Events" for additional information regarding commodity price declines.

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PIONEER NATURAL RESOURCES COMPANY

         The following table provides depletion expense per BOE by geographic area for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009		2008
United States	$	15.89	$	10.32
South Africa	$	34.76	$	13.16
Tunisia	$	7.12	$	4.54
Worldwide	$	16.21	$	10.19

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. During the three months ended March 31, 2009, the Company recognized impairment charges of $21.1 million to reduce the carrying value of the Company's oil and gas properties in the Uinta/Piceance areas. The continued declines in gas prices and downward adjustments to the economically recoverable resource potential during the first quarter of 2009 led to the impairment charge.

Commodity price declines 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 and March 31, 2009 and concluded that it was not 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 months ended March 31, 2009 and 2008:

	United		South
	States		Africa		Tunisia		Other		Total
Three Months Ended March 31, 2009:
Geological and geophysical	$	9,978	$	94	$	2,290	$	382	$	12,744
Exploratory dry holes		(87)		-		5,014		-		4,927
Leasehold abandonments and other		13,760		-		-		-		13,760
	$	23,651	$	94	$	7,304	$	382	$	31,431
Three Months Ended March 31, 2008:
Geological and geophysical	$	22,641	$	48	$	8,835	$	2,395	$	33,919
Exploratory dry holes		1,290		-		1,279		296		2,865
Leasehold abandonments and other		1,893		-		-		-		1,893
	$	25,824	$	48	$	10,114	$	2,691	$	38,677

          The Company's exploration and abandonments expense during the three months ended March 31, 2009 is primarily attributable to continued seismic activity in the Company's Permian Basin, South Texas and Tunisian areas and dry hole expense and unproved property abandonments. During the three months ended March 31, 2009, the Company's exploration and abandonments expense included dry hole and leasehold abandonment and other exploration expenses of $18.7 million, which is primarily comprised of $13.6 million of U.S. unproved property abandonments and $5.0 million of dry hole provisions in Tunisia.

During the three months ended March 31, 2009, the Company drilled and evaluated three exploration/extension wells, one of which was successfully completed as a discovery. During the same period in 2008, the Company drilled

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PIONEER NATURAL RESOURCES COMPANY

and evaluated 16 exploration/extension wells, 15 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 its cost reduction initiatives.

General and administrative expense. General and administrative expense from continuing operations for the three-month periods ended March 31, 2009 and 2008 were $34.6 million and $36.5 million, respectively. The decrease in general and administrative expense from continuing operations was primarily due to a decline in accrued compensation costs, coupled with general cost savings associated with the Company’s costs reduction initiatives. Partially offsetting the Company’s cost reduction initiatives are increases in Pioneer Southwest administrative costs subsequent to its initial public offering on May 6, 2008.

Accretion of discount on asset retirement obligations.Accretion of discount on asset retirement obligations was $3.0 million and $2.1 million for the three-month periods ended March 31, 2009 and 2008, respectively. The increase in accretion of discount on asset retirement obligations during 2009 is primarily due to the accretion of larger asset retirement obligations due to proved reserve reductions associated with the decline in commodity prices as well as new wells placed on production since March 31, 2008. See Note H of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $41.1 million and $40.3 million for the three-month periods ended March 31, 2009 and 2008, respectively. The weighted average interest rate on the Company's indebtedness for the three months ended March 31, 2009, including the effects of interest rate derivatives and capitalized interest, was 5.3 percent as compared to 5.6 percent for the first quarter of 2008. The $860 thousand increase in interest expense from continuing operations during the three months ended March 31, 2009, as compared to the same period of 2008, was primarily due to (i) a $3.3 million decrease in capitalized interest primarily related to declining capitalized interest on the Oooguruk project as development wells are placed on production, partially offset by (ii) a $2.8 million decrease in cash interest expense on long-term borrowings.

Effective January 1, 2009, the Company adopted the provisions of FSP APB 14-1. The provisions of FSP APB 14-1 resulted in a retrospective adjustment to increase the Company’s first quarter 2008 interest expense by $2.8 million and increased the Company’s first quarter 2009 interest expense by $3.5 million. 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 FSP APB 14-1.

Hurricane activity, net. The Company recorded net hurricane related activity expenses of $375 thousand and $458 thousand during the three-month periods ended March 31, 2009 and 2008, respectively. 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 cost approximately $23.6 million to complete operations to reclaim and abandon the East Cameron platform facilities. Since January 2007, the Company has expended approximately $161.4 million on operations to reclaim and abandon the East Cameron platform facilities. The Company's estimates to reclaim and abandon the East Cameron facilities are based upon an analysis prepared by a third party engineering firm for a majority of the work and an estimate by the Company for the remaining work that was not covered by the third-party analysis. 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 by insurance. During the first quarter of 2009, the Company received $10.2 million of insurance recoveries associated with East Cameron facilities that reduced amounts recorded as a receivable from the insurance carriers during 2006. 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.

Other expense. Other expense from continuing operations for the three months ended March 31, 2009 was $31.4 million as compared to $11.9 million for the first quarter of 2008. The $19.5 million increase in other expenses during the first quarter of March 31, 2009, is primarily attributable to (i) a $12.4 million increase in the cost of idle drilling equipment, (ii) a $5.2 million increase in contingency and environmental accrual adjustments (iii) a $2.2 million increase in idle well servicing operations and (iv) a $1.2 million increase in impairment of excess lease and well equipment and supplies inventory, partially offset by (v) a $2.7 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 an income tax benefit from continuing operations of $1.3 million during the three months ended March 31, 2009, as compared to an income tax provision of $86.2 million during the first quarter of 2008. The $87.5 million decrease in income tax provisions for the three months ended March 31, 2009, as compared to the same period of 2008, is primarily due to a $225.1 million decrease in income from continuing operations before income taxes. The Company's effective tax rate on continuing operations of 10 percent for the three months ended March 31, 2009, differs 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 high tax foreign jurisdictions and

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

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

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interest for the three-month period ended March 31, 2009 was $3.8 million as compared to $738 thousand for the first quarter of 2008. The $3.1 million increase in net income attributable to noncontrolling interest is primarily due to noncontrolling interests in the first quarter 2009 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 (loss).

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 has implemented cost reduction initiatives to reduce capital spending, operating costs and general and administrative expenses to enhance and preserve financial flexibility. Specifically, the Company implemented plans to minimize drilling activities until margins improve as a result of (i) commodity prices increasing, (ii) gas price differentials in the areas where the Company produces gas narrowing relative to NYMEX quoted gas prices and/or (iii) well cost reductions. As a result, the Company has significantly reduced its rig activity and continues to pursue further reductions in well costs and lease operating expenses to better align costs with the lower commodity price environment that currently exists. Rigs have been terminated or stacked in the Spraberry, Raton, Edwards Trend and Barnett Shale areas and in Tunisia. The Company has reduced its drilling rig activity from 29 rigs in the third quarter of 2008 to one rig operating in Alaska during May 2009.

The Company’s 2009 capital budget is limited to approximately $300 million (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs), representing a 76 percent decrease from actual 2008 annual capital costs. During the first quarter of 2009, the Company’s capital costs (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $108.1 million, as compared to $305.9 million during the first quarter of 2008, representing a 65 percent decrease. The first quarter 2009 capital expenditures were front-end loaded as the Company completed wells in progress at year end 2008, finished previously scheduled drilling in Tunisia and further curtailed drilling activity in response to declining commodity prices during the quarter.

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PIONEER NATURAL RESOURCES COMPANY

Oil and gas properties. The Company's cash expenditures for additions to oil and gas properties during the three-month periods ended March 31, 2009 and 2008, totaled $164.5 million and $297.3 million, respectively. During the three months ended March 31, 2009, the Company's expenditures for additions to oil and gas properties were funded by $24.4 million of net cash provided by operating activities, cash on hand and borrowings under the Company's Credit Facility. During the three months ended March 31, 2008, the Company's expenditures for additions to oil and gas properties were funded by $177.7 million of net cash provided by operating activities, borrowings on the Company's Credit Facility and $130.8 million of the remaining proceeds received in January 2008 from the sale of the Company’s Canadian assets in November 2007.

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 March 31, 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 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 $176.2 million increase in outstanding long-term borrowings, a $36.7 million decrease in the Company's VPP obligations, a $9.4 million decrease in the Company's net derivative liabilities and a decrease of approximately $20.3 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 three months ended March 31, 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 March 31, 2009, these contracts represented net assets of $139.6 million, including approximately $40.2 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 March 31, 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 financing activities and proceeds from sales of nonstrategic assets. Although the Company expects that these resources will be sufficient to fund its capital commitments during the foreseeable future, the recent turmoil in worldwide financial markets has resulted in the availability of external sources of short-term and long-term capital funding being less certain. For 2009, the Company currently expects that cash flow from operations and cash on hand will be sufficient to fund the Company's capital budget.

Asset divestitures. 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 $132.1 million for the first quarter of 2008 are primarily comprised of the receipt of the escrowed Canadian sales proceeds, net of foreign exchange differentials.

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PIONEER NATURAL RESOURCES COMPANY

Operating activities. Net cash provided by operating activities during the three-month periods ended March 31, 2009 and 2008 was $24.4 million and $177.7 million, respectively. The $153.3 million decrease in net cash provided by operating activities is primarily due to decreased oil, NGL and gas prices, partially offset by an increase in commodity sales volumes.

Investing activities. Investing activities used $171.1 million and $177.5 million of cash during the three months ended March 31, 2009 and 2008, respectively. The $6.4 million decrease in net cash used in investing activities is primarily due to a $132.7 million decrease in additions to oil and gas properties and a $5.7 million decrease in additions to other assets and other property and equipment, net, partially offset by a $137.8 million decrease in proceeds from the disposition of assets, net of cash sold.

Financing activities. Net cash provided by financing activities during the three-month periods ended March 31, 2009 and 2008 was $142.8 million and $5.0 million, respectively. The $142.6 million increase in net cash provided by financing activities is primarily due to a $124.8 million net increase in borrowings of long-term debt.

During March 2009, the Company’s board of directors (the "Board") declared a semiannual dividend of $0.04 per common share payable to shareholders of record on March 31, 2009. Associated therewith, the Company paid approximately $4.7 million of aggregate dividends during April 2009. 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 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 three months ended March 31, 2009 and 2008, the Company expended $16.3 million to acquire 1.0 million shares of treasury stock and $12.8 million to acquire 293 thousand shares of treasury stock, respectively, under share repurchase programs. As of March 31, 2009, approximately $355.8 million of stock may be purchased in the future under the $750 million Board authorization.

See Notes B and F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the formation of Pioneer Southwest and the Pioneer Southwest Credit Facility, respectively.

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. There were $1.1 billion of outstanding borrowings under the Credit Facility as of March 31, 2009. Including $46.0 million of undrawn and outstanding letters of credit under the Credit Facility, the Company had approximately $370.0 million of unused borrowing capacity as of March 31, 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 common units of Pioneer Southwest.

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PIONEER NATURAL RESOURCES COMPANY

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 and asset 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 March 31, 2009, the Company was in compliance with all of its debt covenants.

Book capitalization and current ratio. The Company's net book capitalization at March 31, 2009 was $6.7 billion, consisting of $44.5 million of cash and cash equivalents, debt of $3.1 billion and stockholders' equity of $3.6 billion. The Company's net debt to net book capitalization was 46 percent and 44 percent at March 31, 2009 and December 31, 2008, respectively. The Company's ratio of current assets to current liabilities was 0.91 to 1.00 at March 31, 2009 as compared to 0.70 to 1.00 at December 31, 2008.

New accounting pronouncements. In September 2006, the FASB issued SFAS 157. SFAS 157 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 FSP FAS 157-2. FSP FAS 157-2 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 SFAS 157, for which delayed adoption was provided by FSP FAS 157-2. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's adoption of FSP FAS 157-2.

In December 2007, the FASB issued SFAS 141(R). SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) 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 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 SFAS 141(R) 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. SFAS 141(R) 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 SFAS 141(R) on January 1, 2009.

In December 2007, the FASB issued SFAS 160. SFAS 160 amends 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. SFAS 160 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, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. The Company adopted the provisions of SFAS 160 on January 1, 2009.

In March 2008, the FASB issued SFAS 161. SFAS 161 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 SFAS 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS 161 was adopted by the Company on January 1, 2009. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for disclosures about the Company's derivative instruments and hedging activities.

In May 2008, the FASB issued FSP APB 14-1. FSP APB 14-1 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 FSP APB 14-1 on January 1, 2009. The adoption of FSP APB 14-1 increases the annual interest expense that the Company recognizes on its $480 million of 2.875% Senior Convertible Notes from an annual yield of approximately

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PIONEER NATURAL RESOURCES COMPANY

2.875 percent to 6.75 percent, the annual yield equivalent to a nonconvertible debt borrowing on the date of issuance. The adoption of FSP APB 14-1 also resulted in the reclassification of the estimated issuance date fair value of the 2.875% Senior Convertible Notes conversion privilege from long-term debt to shareholders' equity in the accompanying consolidated balance sheets. See Note F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's adoption of FSP APB 14-1.

In June 2008, the FASB issued FSP EITF 03-6-1, 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 net income (loss) per share under the two class method prescribed under SFAS 128, "Earnings per Share". The Company adopted the provisions of FSP EITF 03-6-1 on January 1, 2009 and, in accordance with FSP EITF 03-6-1, applied its provisions retrospectively to prior-period net income per share computations. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company’s basic and diluted net income (loss) computations for the three months ended March 31, 2009 and 2008.

In December 2008, the SEC released 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 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 price based upon the prior 12-month 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 19 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 FSP FAS 107-1, which amends FASB Statement No. 107, "Disclosures about Fair Value of Financial Instruments" and Accounting Principles Board Opinion No. 28, "Interim Financial Reporting". FSP FAS 107-1 requires disclosures about the fair value of financial instruments for interim reporting purposes of publicly traded companies. FSP FAS 107-1 is effective for interim reporting periods ending after June 15, 2009 and will only impact future disclosures about the fair value of the Company's financial instruments.

In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidelines for estimating fair value in accordance with SFAS 157 when the volume and level of activity for the asset or liability have decreased and guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009 and is not expected to have a material impact on the Company's fair value measurements.

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PIONEER NATURAL RESOURCES COMPANY

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 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 first quarter of 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)			114,237		(2,132)		-		112,105
Contract maturities			(33,236)		2,314		401		(30,521)
Accretion of discount			-		-		(270)		(270)
Contract terminations			(3,745)		-		-		(3,745)
Fair value of contracts
	outstanding as of March 31,2009	$	189,542	$	(9,721)	$	(40,181)	$	139,640

_____________

(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.

Foreign exchange rate sensitivity. During November 2007, the Company invested $131.7 million Canadian dollars ("CND"), representing $132.8 million U.S. dollars, in a CND-denominated escrow account associated with the sale of the Company's Canadian assets. During December 2007, the Company entered into foreign exchange rate derivatives to swap $131.7 million CND for $131.0 million U.S. dollars ("USD") to be delivered during May 2008. The foreign exchange rate swaps were economic hedges of the CND-denominated escrow account balance; however, uncertainty regarding the matching of cash flow timing between the foreign exchange rate swaps and the liquidation of the CND-denominated escrow account caused the Company not to designate the foreign exchange rate swaps as hedges. The CND-denominated escrow account was liquidated during January 2008 for $129.0 million USD, at which time the foreign exchange rate swaps were terminated at a gain of $1.8 million. Subsequent to these transactions, the Company has no remaining material foreign exchange rate risk associated with financial instruments.

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.

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PIONEER NATURAL RESOURCES COMPANY

         The following table provides information about financial instruments to which the Company was a party as of March 31, 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 March 31, 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 April 27, 2009.

		Nine Months Ending December 31,		Year Ending December 31,												Asset / (Liability) Fair Value at
		2009		2010		2011		2012		2013		Thereafter		Total		March 31, 2009
		($ in thousands)
Total Debt:
	Fixed rate    principal
	maturities    (a)	$	-	$	-	$	-	$	6,110	$	480,000	$	1,639,985	$	2,126,095	$	1,527,518
	Weighted    average
	interest    rate		5.74%		5.74%		5.74%		5.73%		5.74%		6.83%
	Variable    rate    principal
	maturities	$	-	$	-	$	-	$	1,084,000	$	-	$	-	$	1,084,000	$	982,952
	Weighted    average
	interest    rate		1.89%		2.29%		3.02%		3.62%
Interest Rate Swaps:
	Credit   Facility:
	Notional debt   amount (b)	$	400,000	$	227,222	$	25,000	$								$	9,721
	Fixed rate  payable (%)		2.87%		2.97%		3.00%
	Variable rate   receivable   (%)		1.14%		1.54%		2.27%

_____________

(a)	Represents maturities of principal amounts excluding (i) debt issuance discounts and premiums and (ii) net deferred fair value hedge losses.
(b)	Represents weighted average notional contract amounts of interest rate derivatives.

Commodity price sensitivity. The following tables provide information about the Company's oil and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of March 31, 2009. Although mitigated by the Company's derivative activities, declines in commodity prices will reduce the Pioneer's revenues and internal cash flows. Recent uncertainties in worldwide financial markets 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.

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PIONEER NATURAL RESOURCES COMPANY

				Nine Months Ending December 31,
														Asset (Liability) Fair Value at
						Year Ending December 31,
				2009		2010		2011		2012		2013		March 31, 2009
														(in thousands)
Oil Non-Hedge Derivatives:
	Average daily notional Bbl   volumes (a):
		Swap contracts			21,151		2,000		-		-		-	$	47,720
			Weighted average fixed price   per Bbl	$	57.98	$	98.32	$	-	$	-	$	-
		Collar contracts			2,000		-		2,000		-		-	$	33,605
			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			4,349		5,000		5,000		-		-	$	(1,697)
			Weighted average ceiling   price per Bbl	$	70.77	$	73.00	$	87.14	$	-	$	-
			Weighted average floor price   per Bbl	$	51.38	$	62.00	$	70.00	$	-	$	-
			Weighted average short put   price per Bbl	$	41.38	$	47.00	$	55.00	$	-	$	-
	Average forward NYMEX        oil prices (b)			$	55.14	$	62.49	$	67.08	$	-	$	-
NGL Non-Hedge Derivatives (a):
	Average daily notional Bbl   volumes:
		Swap contracts			3,750		1,250		-		-		-	$	16,470
			Weighted average fixed price   per Bbl	$	34.28	$	47.38	$	-	$	-	$	-
	Average forward Mont Belvieu   NGL prices (b)			$	26.51	$	28.76	$	-	$	-	$	-
Gas Non-Hedge Derivatives (a):
	Average daily notional MMBtu   volumes (b):
		Swap contracts			135,000		125,000		-		-		-	$	101,683
			Weighted average fixed price   per MMbtu	$	6.22	$	6.60	$	-	$	-	$	-
		Basis swap contracts			215,000		155,000		60,000		20,000		10,000	$	(18,244)
			Weighted average fixed price   per MMbtu	$	(1.04)	$	(0.88)	$	(0.82)	$	(0.78)	$	(0.71)
		Collar contracts			20,000		30,000		-		-		-	$	6,641
			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			40,000		95,000		-		-		-	$	3,364
			Weighted average ceiling price   per Bbl	$	5.86	$	7.94	$	-	$	-	$	-
			Weighted average floor price   per Bbl	$	4.50	$	6.00	$	-	$	-	$	-
			Weighted average short put   price per Bbl	$	3.50	$	5.00	$	-	$	-	$	-
	Average forward NYMEX    gas prices (b)			$	3.98	$	5.77	$	6.68	$	7.01	$	7.13

_____________

(a)	From April 1, 2009 through May 1, 2009, the Company (i) entered into derivative transactions to convert 8,888 Bbls per day of 2009 swap contracts with a weighted average fixed price of $52.35 per Bbl into collar contracts with short puts with a ceiling price of $62.41 per Bbl, a floor price of $51.43 per Bbl and a short put price of $44.55 per Bbl, and (ii) entered into additional oil collar contracts with short puts for approximately (a) 3,000 Bbls per day of the Company’s 2010 production with a ceiling price of $80.25 per Bbl, a floor price of $65.00 per Bbl and a short put price of $52.00 per Bbl and (b) 2,000 Bbls per day of the Company’s 2011 production with a ceiling price of $90.00 per Bbl, a floor price of $70.00 per Bbl and a short put price of $55.00 per Bbl. From April 1, 2009 through May 1, 2009, the Company entered into additional gas basis swap contracts for approximately 30,000 MMBtu of the Company's 2010 production at an average price differential of $0.73 per MMBtu.
(b)	The average forward NYMEX oil and gas prices are based on April 30, 2009 market quotes.
(c)	Forward Mont Belvieu NGL prices are not available as formal market quotes. These forward prices represent estimates as of April 30, 2009 provided by third parties who actively trade in the derivatives.

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PIONEER NATURAL RESOURCES COMPANY

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 ("the Exchange Act"), the 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 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.

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PIONEER NATURAL RESOURCES COMPANY

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", which risks could materially affect the Company's business, financial condition or future results. Except as stated below, there has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

The Company is subject to regulations that may cause it to incur substantial costs and affect its ability to grow.

As previously disclosed in the Company's Annual Report on Form 10-K, including in "Item 1. Business — Competition, Markets and Regulations," the Company's business is regulated by a variety of federal, state, local and foreign laws and regulations. For example, the Company’s properties located in Colorado are subject to the authority of the Colorado Oil & Gas Conservation Commission (the "COGCC"). The COGCC recently passed certain rules that will increase the length of time needed to obtain certain permits and will increase the Company's costs of permitting and environmental compliance. In addition, in connection with the Company's CBM operations in the Raton Basin in Colorado, the Colorado Supreme Court recently affirmed the ruling of a state water court, which held that the use of water tributary to surface flows in CBM operations should be subject to water-use regulation under an additional agency as is the case with other uses of water in the state, including the need for the obtaining of permits, possible competition with other claimants for the use of the water and the possibility of providing augmentation water supplies for water rights owners with more senior rights. There can be no assurance that present or future regulations will not adversely affect the Company's business and operations. See "Item 1. Business — Competition, Markets and Regulations" in the Annual Report on Form 10-K for additional discussion regarding government regulation.

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 March 31, 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)
January 2009	47,459	$	20.08	-
February 2009	1,176,528	$	16.29	1,000,000
March 2009	255	$	18.45	-
Total	1,224,242	$	16.43	1,000,000	$	355,789,018

_____________

(a)	Amounts include 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.

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PIONEER NATURAL RESOURCES COMPANY

Item 6. Exhibits

Exhibits

Exhibit Number		Description
10.1	—	Third Amendment to Amended and Restated Credit Agreement dated as of April 29, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (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 May 5, 2009).
10.2	—	Letter Agreement dated March 18, 2009 between the Company and Southeastern Asset Management, Inc. (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 March 19, 2009).
10.3 (a)	—	Form of Performance Unit Award Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement.
10.4 (a)	—	Form of Nonstatutory Stock Option Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement.
10.5 (a)	—	Form of Restricted Stock Unit Award Agreement, dated February 18, 2009, between the Company and Frank W. Hall and other officers of the Company, with respect to awards made under the Company's 2006 Long Term Incentive Plan.
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.

_____________

(a) Filed herewith.

(b) Furnished herewith.

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PIONEER NATURAL RESOURCES COMPANY

SIGNATURES

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

PIONEER NATURAL RESOURCES COMPANY

Date:    May 11, 2009	By:	/s/ Richard P. Dealy
		Richard P. Dealy
		Executive Vice President and Chief
		Financial Officer
Date:    May 11, 2009	By:	/s/ Frank W. Hall
		Frank W. Hall
		Vice President and Chief
		Accounting Officer

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PIONEER NATURAL RESOURCES COMPANY

Exhibit Index

Exhibit Number		Description
10.1	—	Third Amendment to Amended and Restated Credit Agreement dated as of April 29, 2009 among the Company, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and certain other lenders (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 May 5, 2009).
10.2	—	Letter Agreement dated March 18, 2009 between the Company and Southeastern Asset Management, Inc. (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 March 19, 2009).
10.3 (a)	—	Form of Performance Unit Award Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement.
10.4 (a)	—	Form of Nonstatutory Stock Option Agreement, dated February 18, 2009, between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement.
10.5 (a)	—	Form of Restricted Stock Unit Award Agreement, dated February 18, 2009, between the Company and Frank W. Hall and other officers of the Company, with respect to awards made under the Company's 2006 Long Term Incentive Plan.
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.

_____________

(a) Filed herewith.

(b) Furnished herewith.

63