Edgar Filing: PIONEER NATURAL RESOURCES CO

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

¨	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 ¨

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

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

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

Number of shares of Common Stock outstanding as of July 27, 2010 115,994,034

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 June 30, 2010 and December 31, 2009	5

	Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009	7

	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2010	8

	Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009	9

	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2010 and 2009	10

	Notes to Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51

Item 4.	Controls and Procedures	54

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	55

Item 1A.	Risk Factors	55

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57

Item 6.	Exhibits	58

Signatures		59

Exhibit Index		60

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, availability of equipment, services and personnel required to complete the Company’s operating activities, access to and availability of transportation, processing and refining facilities, Pioneer’s ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer’s credit facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, uncertainties about estimates of reserves and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impact of climate change, 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 effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” and “Part II, Item 1A. Risk Factors” in this Report and “Part I, Item 1. Business — Competition, Markets and Regulations,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

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

•

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

•

“Bcf” means one billion cubic feet.

•

“BOE” means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

•

“BOEPD” means BOE per day.

•

“Btu” means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

•

“CBM” means coal bed methane.

•

“DD&A” means depletion, depreciation and amortization.

•

“GAAP” means accounting principles that are generally accepted in the United States of America.

•

“LIBOR” means London Interbank Offered Rate, which is a market rate of interest.

•

“MBbl” means one thousand Bbls.

•

“MBOE” means one thousand BOEs.

•

“Mcf” means one thousand cubic feet and is a measure of 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” means the quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geosciences and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program is based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

•

“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 employed in the determination of proved reserves 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.

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)


	June 30, 2010			December 31, 2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	197,686		$	27,368
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,359 and $1,310 as of June 30, 2010 and December 31, 2009, respectively		212,014			330,711
Due from affiliates		807			1,037
Income taxes receivable		1,582			25,022
Inventories		122,393			139,177
Prepaid expenses		19,097			9,011
Deferred income taxes		—			26,857
Other current assets:
Derivatives		149,632			48,713
Other, net of allowance for doubtful accounts of $581 and $5,689 as of June 30, 2010 and December 31, 2009, respectively		9,367			8,222

Total current assets		712,578			616,118

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		10,560,753			10,276,244
Unproved properties		179,886			236,660
Accumulated depletion, depreciation and amortization		(3,168,814	)		(2,946,048	)

Total property, plant and equipment		7,571,825			7,566,856

Deferred income taxes		2,356			387
Goodwill		298,563			309,259
Other property and equipment, net		209,569			154,830
Other assets:
Derivatives		142,450			43,631
Other, net of allowance for doubtful accounts of $11,164 and $7,300 as of June 30, 2010 and December 31, 2009, respectively		174,981			176,184

	$	9,112,322		$	8,867,265

The financial information included as of June 30, 2010 has been prepared by management

without audit by independent registered public accountants.

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)


	June 30, 2010			December 31, 2009
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	316,790		$	221,359
Due to affiliates		25,466			32,224
Interest payable		54,023			47,009
Income taxes payable		12,941			17,411
Deferred income taxes		43,158			128
Other current liabilities:
Derivatives		31,211			116,015
Deferred revenue		67,436			90,215
Other		36,260			46,830

Total current liabilities		587,285			571,191

Long-term debt		2,531,431			2,761,011
Derivatives		13,968			133,645
Deferred income taxes		1,638,060			1,470,899
Deferred revenue		64,730			87,021
Other liabilities		218,715			200,467
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 126,102,932 and 125,203,502 shares issued at June 30, 2010 and December 31, 2009, respectively		1,261			1,252
Additional paid-in capital		3,004,139			2,981,450
Treasury stock, at cost: 10,951,910 and 10,828,171 at June 30, 2010 and December 31, 2009, respectively		(422,837	)		(415,211	)
Retained earnings		1,323,662			917,688
Accumulated other comprehensive income – deferred hedge gains, net of tax		29,166			51,009

Total stockholders’ equity attributable to common stockholders		3,935,391			3,536,188
Noncontrolling interests in consolidating subsidiaries		122,742			106,843

Total stockholders’ equity		4,058,133			3,643,031
Commitments and contingencies

	$	9,112,322		$	8,867,265

The financial information included as of June 30, 2010 has been prepared by management

without audit by independent registered public accountants.

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Revenues and other income:
Oil and gas	$	462,142		$	370,692		$	969,938		$	738,543
Interest and other		20,263			88,598			40,066			99,258
Derivative gains (losses), net		177,528			(170,224	)		443,004			(70,361	)
Gain (loss) on disposition of assets, net		7,645			53			24,588			(62	)
Hurricane activity, net		(5,184	)		(16,075	)		2,226			(16,450	)

		662,394			273,044			1,479,822			750,928

Costs and expenses:
Oil and gas production		97,294			84,793			187,009			195,223
Production and ad valorem taxes		25,338			23,715			52,399			51,414
Depletion, depreciation and amortization		150,314			158,673			301,082			346,817
Impairment of oil and gas properties		—			—			—			21,091
Exploration and abandonments		27,123			21,618			47,920			52,788
General and administrative		42,374			33,275			83,322			67,929
Accretion of discount on asset retirement obligations		2,632			2,753			5,592			5,505
Interest		45,368			43,475			92,891			84,613
Other		14,725			36,715			31,301			68,104

		405,168			405,017			801,516			893,484

Income (loss) from continuing operations before income taxes		257,226			(131,973	)		678,306			(142,556	)
Income tax benefit (provision)		(94,693	)		41,724			(255,167	)		42,465

Income (loss) from continuing operations		162,533			(90,249	)		423,139			(100,091	)
Income from discontinued operations, net of tax		26,156			2,731			26,156			1,761

Net income (loss)		188,689			(87,518	)		449,295			(98,330	)
Net (income) loss attributable to the noncontrolling interests		(21,113	)		522			(36,465	)		(3,271	)

Net income (loss) attributable to common stockholders	$	167,576		$	(86,996	)	$	412,830		$	(101,601	)

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	1.20		$	(0.78	)	$	3.29		$	(0.91	)
Income from discontinued operations attributable to common stockholders		0.22			0.02			0.22			0.02

Net income (loss) attributable to common stockholders	$	1.42		$	(0.76	)	$	3.51		$	(0.89	)

Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	1.19		$	(0.78	)	$	3.27		$	(0.91	)
Income from discontinued operations attributable to common stockholders		0.22			0.02			0.22			0.02

Net income (loss) attributable to common stockholders	$	1.41		$	(0.76	)	$	3.49		$	(0.89	)

Weighted average shares outstanding:
Basic		115,104			113,979			114,880			114,116

Diluted		116,006			113,979			115,735			114,116

Dividends declared per share	$	—		$	—		$	0.04		$	0.04

Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	141,420		$	(89,727	)	$	386,674		$	(103,362	)
Income from discontinued operations		26,156			2,731			26,156			1,761

Net income (loss)	$	167,576		$	(86,996	)	$	412,830		$	(101,601	)

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.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(in thousands, except dividends per share)

(Unaudited)


			Stockholders’ Equity Attributable To Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interests			Total Stockholders’ Equity
Balance as of December 31, 2009	114,375		$	1,252	$	2,981,450		$	(415,211	)	$	917,688		$	51,009		$	106,843		$	3,643,031
Dividends declared ($0.04 per share)	—			—		—			—			(4,735	)		—			—			(4,735	)
Exercise of long-term incentive plan stock options	145			—		—			5,573			(2,121	)		—			—			3,452
Treasury stock purchases	(269	)							(13,199	)								(203	)		(13,402	)
Tax benefit related to stock-based compensation	—			—		4,090			—			—			—			—			4,090
Compensation costs:
Vested compensation awards, net	900			9		(8	)		—			—			—			—			1
Compensation costs included in net income	—			—		18,607			—			—			—			645			19,252
Cash contributions from noncontrolling interests	—			—		—			—			—			—			1,151			1,151
Cash distributions to noncontrolling interests	—			—		—			—			—			—			(13,451	)		(13,451	)
Net income	—			—		—			—			412,830			—			36,465			449,295
Other comprehensive loss:
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations	—			—		—			—			—			(21,843	)		(8,708	)		(30,551	)

Balance as of June 30, 2010	115,151		$	1,261	$	3,004,139		$	(422,837	)	$	1,323,662		$	29,166		$	122,742		$	4,058,133

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.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)


	Six Months Ended June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	449,295		$	(98,330	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		301,082			346,817
Impairment of oil and gas properties		—			21,091
Exploration expenses, including dry holes		8,057			27,954
Hurricane activity, net		3,500			15,000
Deferred income taxes		243,052			(49,941	)
(Gain) loss on disposition of assets, net		(24,588	)		62
Accretion of discount on asset retirement obligations		5,592			5,505
Discontinued operations		11,220			5,208
Interest expense		14,920			13,529
Derivative related activity		(442,087	)		48,235
Amortization of stock-based compensation		19,049			19,223
Amortization of deferred revenue		(45,070	)		(73,695	)
Other noncash items		(3,766	)		24,840
Change in operating assets and liabilities
Accounts receivable, net		96,376			53,941
Income taxes receivable		23,440			31,796
Inventories		12,479			(57,689	)
Prepaid expenses		(10,204	)		(14,187	)
Other current assets		(7,192	)		66,920
Accounts payable		50,458			(107,388	)
Interest payable		7,014			101
Income taxes payable		(4,470	)		13,917
Other current liabilities		(14,943	)		(44,581	)

Net cash provided by operating activities		693,214			248,328

Cash flows from investing activities:
Proceeds from disposition of assets		297,312			3,742
Additions to oil and gas properties		(461,502	)		(242,150	)
Additions to other assets and other property and equipment, net		(74,183	)		(21,399	)

Net cash used in investing activities		(238,373	)		(259,807	)

Cash flows from financing activities:
Borrowings under long-term debt		182,997			172,000
Principal payments on long-term debt		(424,107	)		(103,000	)
Contributions from noncontrolling interests		1,151			150
Distributions to noncontrolling interests		(13,451	)		(10,050	)
Payments of other liabilities		(20,325	)		(699	)
Exercise of long-term incentive plan stock options		3,452			2,535
Purchases of treasury stock		(13,402	)		(20,399	)
Excess tax (costs) benefits from share-based payment arrangements		4,090			(3,918	)
Payment of financing fees		(145	)		(4,475	)
Dividends paid		(4,783	)		(4,679	)

Net cash provided by (used in) financing activities		(284,523	)		27,465

Net increase in cash and cash equivalents		170,318			15,986
Cash and cash equivalents, beginning of period		27,368			48,337

Cash and cash equivalents, end of period	$	197,686		$	64,323

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.

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net income (loss)	$	188,689		$	(87,518	)	$	449,295		$	(98,330	)

Other comprehensive loss:
Hedge fair value changes, net		—			—			—			12,974
Net hedge gains included in continuing operations		(20,697	)		(26,473	)		(41,623	)		(65,640	)
Income tax provision		6,037			23,440			11,072			32,974

Other comprehensive loss		(14,660	)		(3,033	)		(30,551	)		(19,692	)

Comprehensive income (loss)		174,029			(90,551	)		418,744			(118,022	)

Comprehensive (income) loss attributable to noncontrolling interest		(16,740	)		6,057			(27,758	)		4,270

Comprehensive income (loss) attributable to common stockholders	$	157,289		$	(84,494	)	$	390,986		$	(113,752	)

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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

NOTE A. Organization and Nature of Operations

Pioneer Natural Resources Company (“Pioneer” or the “Company”) is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with 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 June 30, 2010 and for the three and six months ended June 30, 2010 and 2009 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) have been condensed or omitted in this Report pursuant to the rules and regulations of the 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, 2009.

During the three months ended June 30, 2009, the Company inadvertently overstated its depletion, depreciation and amortization (“DD&A”) expense by $7.3 million ($4.6 million net of associated income taxes) attributable to oil and gas volumes sold during the period then ended. This overstatement primarily resulted from an exclusion of certain proved reserves from the calculation of the Company’s DD&A expense for the three months ended June 30, 2009. As of June 30, 2009, this error also overstated the Company’s accumulated depletion, depreciation and amortization and income taxes payable by $7.3 million and $178 thousand, respectively, and understated the Company’s deferred tax liabilities by $2.9 million. The Company corrected the error during the three months ended September 30, 2009. The accompanying consolidated statements of operations and comprehensive income (loss) for the three and six months ended June 30, 2009, and the accompanying consolidated statement of cash flows for the six months ended June 30, 2009, have been revised for this correction. The correction of this error decreased the Company’s diluted net loss by $0.04 per share for the three and six months ended June 30, 2009.

Discontinued operations. During the three months ended June 30, 2009, the Company sold its oil and gas properties in Mississippi and committed to a plan to sell substantially all of its shelf properties in the Gulf of Mexico, which were subsequently sold during August 2009. In accordance with GAAP, the Company classified the results of operations of the Mississippi and shelf properties in the Gulf of Mexico as discontinued in its accompanying consolidated statements of operations for the three and six months ended June 30, 2009.

During the fourth quarter of 2009, the Company recorded a $119.3 million receivable from the United States Department of Interior Minerals Management Service (the “MMS,” now the Bureau of Ocean Energy Management, Regulation, and Enforcement) for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico. The MMS paid the Company the $119.3 million receivable during the first half of 2010. Additionally, the MMS paid the Company $35.3 million of associated interest on the excess royalty payments during the three months ended June 30, 2010. The properties that were the source of these royalty and interest recoveries were sold by the Company during 2006. Accordingly, the $35.3 million of interest income recorded during the three and six months ended June 30, 2010 is a component of income from discontinued operations, net of tax in the accompanying consolidated statements of operations for the three and six months ended June 30, 2010. See Note S for additional information about discontinued operations.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

Allowances for doubtful accounts. As of June 30, 2010 and December 31, 2009, the Company’s allowances for doubtful accounts totaled $13.1 million and $14.3 million, respectively. Changes in the Company’s allowance for doubtful accounts during the three and six months ended June 30, 2010 are summarized in the following table:


	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
	(in thousands)

Beginning allowance for doubtful accounts balance	$	14,729		$	14,299
Amount recorded in other expense for bad debt recoveries		(254	)		(30	)
Other net decreases		(1,371	)		(1,165	)


Ending allowance for doubtful accounts balance	$	13,104		$	13,104

Inventories. Inventories consisted of $193.7 million and $205.6 million of materials and supplies and $3.1 million and $3.2 million of commodities as of June 30, 2010 and December 31, 2009, respectively. As of June 30, 2010 and December 31, 2009, the Company’s materials and supplies inventory was net of $1.4 million and $5.2 million, respectively, of valuation reserve allowances. As of June 30, 2010 and December 31, 2009, the Company estimated that $74.3 million and $69.6 million, respectively, of its materials and supplies inventory would not be utilized within one year. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets.

Derivatives and hedging. Changes in the fair values of derivative instruments are recognized as gains or losses in the earnings of the period in which they occur. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. 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 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 transferred to earnings during the same periods in which the hedged transactions are recognized in the Company’s earnings. Since February 1, 2009, the Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and master netting counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company’s and Pioneer Southwest Energy Partners L.P.’s (“Pioneer Southwest,” a majority-owned and consolidated subsidiary) credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on independent market-quoted credit default swap rate curves for the parties’ debt plus the United States Treasury Bill yield curve as of June 30, 2010. Pioneer Southwest’s credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate (“LIBOR”) curves plus 250 basis points, representing Pioneer Southwest’s estimated borrowing rate.

Goodwill. Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2009, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment. During the first half of 2010, the Company sold 45 percent of its interests in South Texas Eagle Ford Shale oil and gas properties and substantially all of its oil and gas properties in the Uinta/Piceance area. Associated therewith, the Company reduced its goodwill attributable to the sold properties by $10.7 million.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 61.9 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

In addition to Pioneer Southwest, the Company owns the majority interests in certain other subsidiaries with operations in the United States. Noncontrolling interest in the net assets of consolidated subsidiaries totaled $122.7 million and $106.8 million as of June 30, 2010 and December 31, 2009, respectively. The Company recorded net income attributable to the noncontrolling interests of $21.1 million and $36.5 million for the three and six months ended June 30, 2010, respectively, (principally related to Pioneer Southwest) compared to net loss attributable to the noncontrolling interests of $0.5 million and net income attributable to the noncontrolling interests of $3.3 million for the three and six months ended June 30, 2009, respectively.

Investment in unconsolidated affiliate. During the first half of 2010, the Company formed EFS Midstream LLC (“EFS Midstream”) to own and operate natural gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party for $46.4 million of cash proceeds. Associated therewith, the Company recorded a $46.3 million deferred gain that will be amortized as a reduction in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver production volumes through EFS Midstream handling and gathering facilities. The deferred gain is included in other current and noncurrent liabilities in the Company’s accompanying consolidated balance sheet as of June 30, 2010.

The Company does not have voting control of EFS Midstream. Consequently, the Company accounts for this investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, investment in an unconsolidated affiliate is increased for investments made and the investor’s share of the investee’s net income and decreased for distributions received, the carrying value of member interests sold and the investor’s share of the investee’s net losses.

Stock-based compensation. For stock-based compensation equity 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 amount of compensation expense recognized at any date is at least equal to the portion of the grant-date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day’s closing stock price on the date of grant for the fair value of restricted stock awards, (iii) the Monte Carlo simulation method for the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for series B unit awards in the Company’s majority-owned drilling subsidiary, Sendero Drilling Company, LLC (“Sendero”).

Stock-based compensation liability awards are awards that are expected to be settled wholly or partially in cash on their vesting dates, rather than in equity shares or units. Stock-based liability awards are recorded as accounts payable – affiliates based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of liability awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to compensation expense. During February 2010, the Company issued 208,620 restricted stock awards to employees that represent liability awards. As of June 30, 2010, account payable – affiliates includes $1.3 million of liabilities attributable to the liability awards.

For the three and six months ended June 30, 2010, the Company recorded $10.5 million and $20.6 million, respectively, of stock-based compensation costs for all plans, as compared to $10.9 million and $20.1 million for the same respective periods of 2009.

In accordance with GAAP, the Company’s issued shares, as reflected in the consolidated balance sheets at June 30, 2010 and December 31, 2009, do not include 842,166 and 979,493 common shares, respectively, associated with unvested stock-based compensation awards that have voting rights.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

The following table summarizes all Pioneer equity and liability stock-based awards, lapses and forfeitures that occurred during the six months ended June 30, 2010:


	Restricted Stock Awards		Performance Units	Stock Options

Outstanding at December 31, 2009	2,999,370		347,031	596,033
Awards (a)	715,577		74,482	116,120
Lapsed restrictions	(799,163	)	—	—
Exercises	—		—	(144,845	)
Forfeitures	(59,165	)	—	(1,066	)

Outstanding at June 30, 2010	2,856,619		421,513	566,242

(a)	Restricted stock awards include 208,620 of liability awards.

Subsidiary issuances of unit-based compensation. During the six months ended June 30, 2010, Pioneer Natural Resources GP LLC (the “General Partner”), the general partner of Pioneer Southwest, awarded phantom units to certain members of management of the General Partner under Pioneer Southwest’s long-term incentive plan (the “Phantom Units”). The Phantom Units entitle the recipients to receive 35,118 common units of Pioneer Southwest after a three-year vesting period. Associated therewith, Pioneer Southwest and the Company recorded $83 thousand of compensation expense during the six months ended June 30, 2010. During the six months ended June 30, 2010, Sendero entered into Restricted Unit Agreements with two key employees, relating to series B units in Sendero. The series B unit awards vest over a five-year period and do not earn equity rights unless certain defined performance conditions are achieved by Sendero. Associated therewith, the Company recorded $510 thousand of compensation expense during the six months ended June 30, 2010.

During the three months ended June 30, 2010, the General Partner awarded 8,744 Pioneer Southwest restricted common units to directors of the General Partner and restrictions on 13,653 Pioneer Southwest common unit awards lapsed. There were no forfeitures of Pioneer Southwest restricted common units during the six months ended June 30, 2010.

As of June 30, 2010, there was $65.6 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $10.6 million attributable to liability 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. During February 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-09, “Subsequent Events (Topic 855).” ASU No. 2010-09 amends Accounting Standards Codification (“ASC”) Topic 855 to include the definition of “SEC filer” and alleviate the obligation of SEC filers to disclose the date through which subsequent events have been evaluated. ASU No. 2010-09 became effective during February 2010. See Note T for the Company’s disclosures of subsequent events.

Effective December 31, 2009, the Company adopted the SEC’s final rule on “Modernization of Oil and Gas Reporting” (the “Reserve Ruling”) and the FASB’s ASU 2010-03, which conforms ASC 932 to the Reserve Ruling. Among the items, the Reserve Ruling and ASU 2010-03 require companies to report oil and gas reserves using an average price based upon the prior 12-month period rather than a period-end price.

During January 2010, the FASB issued ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820).” ASU No. 2010-06 amends ASC Topic 820 to (i) require separate disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, (ii) require separate disclosure of purchases, sales, issuances and settlements in the reconciliation for fair value measurements using significant unobservable inputs (Level 3), (iii) clarify the level of disaggregation for fair value measurements of assets and liabilities and (iv) clarify disclosures about inputs and valuation techniques used to measure fair values for both recurring and nonrecurring fair value measurements. ASU No. 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. The Company adopted the provisions of ASU No. 2010-06 on January 1, 2010. See Note D for the Company’s disclosures about fair value measurements.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

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 and six months ended June 30, 2010:


	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
	(in thousands)

Beginning capitalized exploratory well costs	$	137,581		$	127,574
Additions to exploratory well costs pending the determination of proved reserves		75,873			114,125
Reclassification due to determination of proved reserves		(46,497	)		(74,742	)
Disposition of wells sold		(15,526	)		(15,526	)


Ending capitalized exploratory well costs	$	151,431		$	151,431

The following table provides an aging, as of June 30, 2010 and December 31, 2009 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:


	June 30, 2010		December 31, 2009
	(in thousands, except well counts)

Capitalized exploratory well costs that have been suspended:
One year or less	$	39,953	$	21,634
More than one year		111,478		105,940


	$	151,431	$	127,574


Number of projects with exploratory well costs that have been suspended for a period greater than one year		5		8

The following table provides an aging of capitalized costs of exploration projects that have been suspended for more than one year as of June 30, 2010:


	Total		2010		2009		2008		2007			2006
	(in thousands)

U.S. – Cosmopolitan Unit	$	77,745	$	10,831	$	8,253	$	6,344	$	51,488		$	829
Tunisia		33,733		331		466		29,006		(15	)		3,945

Total	$	111,478	$	11,162	$	8,719	$	35,350	$	51,473		$	4,774

Cosmopolitan Unit. The Company owns a 100 percent working interest in, and is the operator of, the Cosmopolitan Unit in the Cook Inlet of Alaska. The Company drilled a lateral sidetrack during 2007 from an existing wellbore on an onshore site to further appraise the resource potential of the unit. The initial un-stimulated production test results were encouraging. The Company performed casing repair workover operations on the well during the fourth quarter of 2009, fracture-stimulated the well during the first quarter of 2010 and plans to perform extended flow testing and analysis of the well during the remainder of 2010. The Company will continue to conduct permitting activities and facilities planning and may drill another appraisal well during 2011.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

Tunisia – Cherouq. The Company has $17.8 million of suspended well costs recorded for the Hayatt #1 well in the Company’s Cherouq production concession area, which is operated by the Company. The Hayatt #1 well began drilling in April 2008 to test several targeted formations. Mechanical failures were encountered during the testing of the well that did not allow completion of the formation assessments. The Company has project personnel at appropriate levels committed to and actively participating in analyzing seismic and other data to determine the optimal plan forward for completing the well, which may utilize the existing wellbore or a new wellbore adjacent to the existing well. The Company expects to finalize its Hayatt #1 plans during 2010 or early 2011 and execute well completion plans during 2011.

Tunisia – Borj El Khadra. The Company has $7.8 million of suspended well costs attributable to the Nahkil #1 and Abir #1 wells in the Borj El Khadra exploration permit area, which is operated by a third-party. The Nahkil #1 well encountered oil-bearing sands and the Abir #1 well encountered gas-bearing sands. The Company does not record proved reserves associated with discoveries in exploration permit areas until a production concession is granted. The third-party operator and the Company have project personnel at appropriate levels committed to and actively participating in infrastructure planning and assessment of the permit area. During the first half of 2010, a $13.8 million 3-D seismic program was initiated and future plans include the drilling of an additional exploration well in the permit area during 2010. Additionally, project personnel are evaluating the feasibility of using production handling facilities on a nearby production concession to transport Abir #1 production to sales markets.

Tunisia – Anaguid. The Company has $8.2 million of suspended well costs attributable to the Durra #1 well on the Anaguid exploration permit. Project personnel at appropriate levels are committed to and actively participating in the assessment of the Durra #1 well and the Anaguid exploration permit area. During April 2010, the Company and other project participants formally submitted a plan of development for the conversion of the Durra #1 discovery into a concession agreement. Engineering and design work is being progressed, which will allow construction activities to commence once the plan of development is formally approved. During July 2010, government approval was received; however, final approval is subject to publication in the Tunisian Gazette prior to the concession being formally awarded.

NOTE D. Disclosures About Fair Value Measurements

In accordance with GAAP, fair value measurements are 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(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 on a recurring basis as of June 30, 2010, for each of the fair value hierarchy levels:


	Fair Value Measurements at Reporting Date Using						Fair Value at June 30, 2010
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2010
	(in thousands)

Assets:
Trading securities	$	296	$	101	$	—	$	397
Commodity derivatives		—		265,863		6,311		272,174
Interest rate derivatives		—		19,908		—		19,908
Deferred compensation plan assets		29,103		—		—		29,103

Total assets	$	29,399	$	285,872	$	6,311	$	321,582


Liabilities:
Commodity derivatives	$	—	$	40,922	$	1,672	$	42,594
Interest rate derivatives		—		2,585		—		2,585
Pioneer Southwest credit facility		—		67,990		—		67,990
5.875% senior notes due 2016		465,631		—		—		465,631
6.65% senior notes due 2017		489,223		—		—		489,223
6.875% senior notes due 2018		449,500		—		—		449,500
7.50% senior notes due 2020		463,500		—		—		463,500
7.20% senior notes due 2028		246,918		—		—		246,918
2.875% senior convertible notes due 2038 (a)		562,800		—		—		562,800

Total liabilities	$	2,677,572	$	111,497	$	1,672	$	2,790,741

(a)	The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege. At the issuance date, the conversion privilege was valued at $81.1 million.

The following tables present the changes in the fair values of the Company’s notes receivable and natural gas liquid (“NGL”) derivative liabilities classified as Level 3 in the fair value hierarchy:


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months Ended June 30, 2010
	NGL Swap Contracts			Notes Receivable			Total
	(in thousands)

Beginning asset (liability) balance	$	(1,323	)	$	1,529		$	206
Total gains (losses):
Net unrealized gains included in earnings (a)		7,782			—			7,782
Net realized losses transferred to earnings (a)		(772	)		—			(772	)
Notes receivable valuation allowance recoveries included in earnings (b)		—			307			307
Settlements		(1,048	)		(1,836	)		(2,884	)

Ending asset balance	$	4,639		$	—		$	4,639

(a)

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

(b)	The valuation allowance recoveries associated with the Company’s notes receivable is included in other expense in the accompanying consolidated statements of operations.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Six Months Ended June 30, 2010
	NGL Swap Contracts			Notes Receivable			Total
	(in thousands)

Beginning asset (liability) balance	$	(12,904	)	$	4,727		$	(8,177	)
Total gains (losses):
Net unrealized gains included in earnings (a)		21,203			—			21,203
Net realized losses transferred to earnings (a)		(3,852	)		—			(3,852	)
Notes receivable valuation allowance recoveries included in earnings (b)		—			187			187
Settlements (c)		192			(4,914	)		(4,722	)

Ending asset balance	$	4,639		$	—		$	4,639

(a)

(b)	The valuation allowance recoveries associated with the Company’s notes receivable is included in other expense in the accompanying consolidated statements of operations.

(c)	During the first quarter of 2010, the Company took possession of a drilling rig that represented $3.0 million of collateral value associated with its notes receivable.

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of June 30, 2010 and December 31, 2009:


	June 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(in thousands)

Assets:
Commodity price derivatives	$	272,174	$	272,174	$	84,080	$	84,080
Interest rate derivatives	$	19,908	$	19,908	$	8,264	$	8,264
Trading securities	$	397	$	397	$	335	$	335
Deferred compensation plan assets	$	29,103	$	29,103	$	27,890	$	27,890
Notes receivable	$	—	$	—	$	4,727	$	4,727
Liabilities:
Commodity price derivatives	$	42,594	$	42,594	$	223,555	$	223,555
Interest rate derivatives	$	2,585	$	2,585	$	26,105	$	26,105
Pioneer credit facility	$	—	$	—	$	240,000	$	259,461
Pioneer Southwest credit facility	$	72,000	$	67,990	$	67,000	$	61,718
5.875% senior notes due 2012	$	—	$	—	$	6,168	$	6,154
5.875% senior notes due 2016	$	392,906	$	465,631	$	389,109	$	437,170
6.65% senior notes due 2017	$	483,978	$	489,223	$	483,914	$	472,546
6.875% senior notes due 2018	$	449,176	$	449,500	$	449,161	$	438,402
7.50% senior notes due 2020	$	446,300	$	463,500	$	446,172	$	449,566
7.20% senior notes due 2028	$	249,924	$	246,918	$	249,924	$	230,868
2.875% senior convertible notes due 2038 (a)	$	437,145	$	562,800	$	429,563	$	508,320

(a)	The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege. At the issuance date, the conversion privilege was valued at $81.1 million.

Trading securities and deferred compensation plan assets. The Company’s trading securities represent securities that are both actively traded and not actively traded on major exchanges. The Company’s deferred

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

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 June 30, 2010, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs except inputs for certain 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 and liabilities as of June 30, 2010 represent (i) swap contracts for $189 million notional amount of debt, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate and (ii) swap contracts for $470 million notional amount of debt, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. The net derivative asset values attributable to the Company’s interest rate derivative contracts as of June 30, 2010 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company’s commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company’s oil and gas swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority while NGL derivative contract asset and liability measurements represent Level 3 inputs in the hierarchy priority.

Oil derivatives. The Company’s oil derivatives are swap, collar and three-way collar contracts for notional barrels (“Bbls”) of oil at fixed (in the case of swap contracts) or interval (in the case of collar and three-way collar contracts) New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The asset and liability values attributable to the Company’s oil derivatives as of June 30, 2010 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) independent active market-quoted futures Brent price quotes, (iv) the applicable estimated credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling oil options and were corroborated by market-quoted volatility factors.

NGL derivatives. The Company’s NGL derivatives include swap and collar contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs or NGL component prices per Bbl. The asset and liability values attributable to the Company’s NGL derivatives as of June 30, 2010 are based on (i) the contracted notional volumes, (ii) independent active market-quoted NGL component prices and (iii) the applicable credit-adjusted risk-free rate yield curve. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling NGL options and were corroborated by market-quoted volatility factors. Prior to June 30, 2010, the Company’s NGL component price inputs were obtained from independent brokers active in buying and selling NGL derivative contracts.

Gas derivatives. The Company’s gas derivatives are swap, collar and three-way collar contracts for notional MMBtus of gas contracted at various posted price indexes, including NYMEX Henry Hub (“HH”) swap contracts coupled with basis swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company’s gas derivative contracts as of June 30, 2010 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices, (iv) the applicable credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts and three-way collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling gas options and were corroborated by market-quoted volatility factors.

Credit facilities. The fair value of Pioneer Southwest’s credit facility is based on (i) contractual interest, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. Since there are no outstanding borrowings on Pioneer’s credit facility, the fair value is nil at June 30, 2010.

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

NOTE E. Income Taxes

The Company accounts for income taxes in accordance with the provisions of ASC Topic 740, which 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., state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of June 30, 2010 and December 31, 2009, the Company’s valuation allowances (relating primarily to foreign tax jurisdictions) were $45.4 million and $44.2 million, respectively.

ASC 740 also clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of June 30, 2010, the Company had no significant unrecognized tax benefits. The Company’s policy is to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2004. As of June 30, 2010, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company’s liquidity, future results of operations or financial position.

Income tax (provisions) benefits. The Company’s income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)

Current:
U.S. federal	$	(2,198	)	$	(669	)	$	(3,299	)	$	401
U.S. state		(1,800	)		(6,259	)		(3,124	)		(6,935	)
Foreign		(6,098	)		9,220			(5,692	)		(942	)

		(10,096	)		2,292			(12,115	)		(7,476	)


Deferred:
U.S. federal		(71,738	)		50,514			(202,796	)		53,521
U.S. state		(7,040	)		5,521			(16,500	)		5,764
Foreign		(5,819	)		(16,603	)		(23,756	)		(9,344	)

		(84,597	)		39,432			(243,052	)		49,941

Income tax (provision) benefit	$	(94,693	)	$	41,724		$	(255,167	)	$	42,465

NOTE F. Long-term Debt

Senior notes redemption. On March 15, 2010, the Company redeemed for cash all of its outstanding 5.875% senior notes due 2012 for $6.3 million, which represented the outstanding principal plus accrued and unpaid interest.

Credit facility repayment. During the six months ended June 30, 2010, the Company repaid its outstanding borrowings under the credit facility.

As of June 30, 2010, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

NOTE G. Derivative Financial Instruments

The Company uses financial derivative contracts to manage exposures to commodity price, interest rate and foreign currency exchange rate 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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

effectively provide commodity price protection. Because these contracts are not expected to be net cash settled, they are considered to be normal sales contracts and not derivatives. Therefore, physical delivery contracts are not accounted for as derivative financial instruments in the financial statements.

All derivatives are recorded on the balance sheet at estimated fair value. Fair value is generally determined based on the credit-adjusted present value difference between the fixed contract price and the underlying market price at the determination date. The Company accounts for derivative instruments under the mark-to-market accounting rules, which require that all changes in the fair values of the Company’s derivative contracts be recognized as gains or losses in the earnings of the period in which they occur.

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

Fair value derivatives. The Company monitors the debt capital markets and interest rate trends to identify opportunities to enter into and terminate interest rate derivative contracts, with the objective of reducing the Company’s costs of capital. As of June 30, 2010 and December 31, 2009, the Company was not a party to any fair value hedges.

Cash flow derivatives. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (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 rate 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 NYMEX oil prices. The following table sets forth, as of June 30, 2010 the volumes in Bbls underlying the Company’s outstanding oil derivative contracts and the weighted average NYMEX prices per Bbl for those contracts:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production derivatives (a):
2010 – Swap contracts
Volume (Bbl)						2,500		2,500		2,500
Price per Bbl					$	93.34	$	93.34	$	93.34

2010 – Collar contracts with short puts
Volume (Bbl)						30,000		30,250		30,125
Price per Bbl:
Ceiling					$	84.99	$	85.09	$	85.04
Floor					$	68.37	$	68.38	$	68.37
Short put					$	55.23	$	55.23	$	55.23

2011 – Swap contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	77.25	$	77.25	$	77.25	$	77.25	$	77.25

2011 – Collar contracts
Volume (Bbl)		2,000		2,000		2,000		2,000		2,000
Price per Bbl:
Ceiling	$	170.00	$	170.00	$	170.00	$	170.00	$	170.00
Floor	$	115.00	$	115.00	$	115.00	$	115.00	$	115.00

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


2011 – Collar contracts with short puts
Volume (Bbl)		37,000		37,000		37,000		37,000		37,000
Price per Bbl:
Ceiling	$	99.22	$	99.22	$	99.22	$	99.22	$	99.22
Floor	$	73.92	$	73.92	$	73.92	$	73.92	$	73.92
Short put	$	59.41	$	59.41	$	59.41	$	59.41	$	59.41

2012 – Swap contracts
Volume (Bbl)		3,000		3,000		3,000		3,000		3,000
Price per Bbl	$	79.32	$	79.32	$	79.32	$	79.32	$	79.32

2012 – Collar contracts with short puts
Volume (Bbl)		28,000		28,000		28,000		28,000		28,000
Price per Bbl:
Ceiling	$	120.59	$	120.59	$	120.59	$	120.59	$	120.59
Floor	$	80.54	$	80.54	$	80.54	$	80.54	$	80.54
Short put	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00

2013 – Swap contracts
Volume (Bbl)		3,000		3,000		3,000		3,000		3,000
Price per Bbl	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02

2013 – Collar contracts with short puts
Volume (Bbl)		1,250		1,250		1,250		1,250		1,250
Price per Bbl:
Ceiling	$	111.50	$	111.50	$	111.50	$	111.50	$	111.50
Floor	$	83.00	$	83.00	$	83.00	$	83.00	$	83.00
Short put	$	68.00	$	68.00	$	68.00	$	68.00	$	68.00

(a)

Subsequent to June 30, 2010, the Company (i) entered into additional collar contracts with short puts for 5,000 Bbls per day of the Company’s 2013 production with a ceiling price of $116.30 per Bbl, a floor price of $80.00 per Bbl and a short put price of $65.00 per Bbl and (ii) unwound collar contracts with short puts for 2,750 Bbls per day of the Company’s 2010 production with a ceiling price of $98.54 per Bbl, a floor price of $75.00 per Bbl and a short put price of $60.00 per Bbl.

Natural gas liquids prices. All material physical sales contracts governing the Company’s NGL production have been tied directly or indirectly to Mont Belvieu or NGL product component prices. The following table sets forth, as of June 30, 2010 the volumes in Bbls under outstanding NGL derivative contracts and the weighted average NGL prices per Bbl for those contracts:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production derivatives:
2010 – Swap contracts
Volume (Bbl)						1,250		1,250		1,250
Price per Bbl					$	47.38	$	47.38	$	47.38

2010 – Collar contracts
Volume (Bbl)						2,000		2,000		2,000
Price per Bbl:
Ceiling					$	49.98	$	49.98	$	49.98
Floor					$	41.58	$	41.58	$	41.58

2010 – Collar contracts with short puts
Volume (Bbl)						2,000		2,000		2,000
Price per Bbl:
Ceiling					$	58.92	$	58.92	$	58.92
Floor					$	47.64	$	47.64	$	47.64
Short put					$	38.71	$	38.71	$	38.71

2011 – Swap contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	34.65	$	34.65	$	34.65	$	34.65	$	34.65

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)



2011 – Collar contracts
Volume (Bbl)		1,000		1,000		1,000		1,000		1,000
Price per Bbl:
Ceiling	$	50.93	$	50.93	$	50.93	$	50.93	$	50.93
Floor	$	42.21	$	42.21	$	42.21	$	42.21	$	42.21

2012 – Swap contracts
Volume (Bbl)		750		750		750		750		750
Price per Bbl	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03

Gas prices. All material physical sales contracts governing the Company’s gas production have been tied directly or indirectly to regional index prices where the gas is produced. The Company uses derivative contracts to mitigate gas price volatility and reduce basis risk between NYMEX Henry Hub prices and actual index prices upon which the gas is sold. The following table sets forth as of June 30, 2010 the volumes in millions of British thermal units (“MMBtus”) under outstanding gas derivative contracts and the weighted average index prices per MMBtu for those contracts:


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production derivatives (a):
2010 – Swap contracts
Volume (MMBtu)								167,500			167,500			167,500
Price per MMBtu							$	6.26		$	6.26		$	6.26

2010 – Collar contracts
Volume (MMBtu)								40,000			40,000			40,000
Price per MMBtu:
Ceiling							$	7.19		$	7.19		$	7.19
Floor							$	5.75		$	5.75		$	5.75

2010 – Collar contracts with short puts
Volume (MMBtu)								95,000			95,000			95,000
Price per MMBtu:
Ceiling							$	7.94		$	7.94		$	7.94
Floor							$	6.00		$	6.00		$	6.00
Short put							$	5.00		$	5.00		$	5.00

2010 – Basis swap contracts
Volume (MMBtu)								265,000			238,478			251,739
Price per MMBtu							$	(0.64	)	$	(0.71	)	$	(0.67	)

2011 – Swap contracts
Volume (MMBtu)		97,500			97,500			97,500			97,500			97,500
Price per MMBtu	$	6.32		$	6.32		$	6.32		$	6.32		$	6.32

2011 – Collar contracts with short puts
Volume (MMBtu)		200,000			200,000			200,000			200,000			200,000
Price per MMBtu:
Ceiling	$	8.55		$	8.55		$	8.55		$	8.55		$	8.55
Floor	$	6.32		$	6.32		$	6.32		$	6.32		$	6.32
Short put	$	4.88		$	4.88		$	4.88		$	4.88		$	4.88

2011 – Basis swap contracts
Volume (MMBtu)		120,000			120,000			120,000			120,000			120,000
Price per MMBtu	$	(0.62	)	$	(0.62	)	$	(0.62	)	$	(0.62	)	$	(0.62	)

2012 – Swap contracts
Volume (MMBtu)		70,000			70,000			70,000			70,000			70,000
Price per MMBtu	$	5.97		$	5.97		$	5.97		$	5.97		$	5.97

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


2012 – Collar contracts
Volume (MMBtu)		40,000			40,000			40,000			40,000			40,000
Price per MMBtu:
Ceiling	$	6.96		$	6.96		$	6.96		$	6.96		$	6.96
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00

2012 – Collar contracts with short puts
Volume (MMBtu)		190,000			190,000			190,000			190,000			190,000
Price per MMBtu:
Ceiling	$	7.96		$	7.96		$	7.96		$	7.96		$	7.96
Floor	$	6.12		$	6.12		$	6.12		$	6.12		$	6.12
Short put	$	4.55		$	4.55		$	4.55		$	4.55		$	4.55
2012 – Basis swap contracts
Volume (MMBtu)		42,500			42,500			42,500			42,500			42,500
Price per MMBtu	$	(0.46	)	$	(0.46	)	$	(0.46	)	$	(0.46	)	$	(0.46	)

2013 – Swap contracts
Volume (MMBtu)		67,500			67,500			67,500			67,500			67,500
Price per MMBtu	$	6.11		$	6.11		$	6.11		$	6.11		$	6.11

2013 – Collar contracts with short puts
Volume (MMBtu)		45,000			45,000			45,000			45,000			45,000
Price per MMBtu:
Ceiling	$	7.49		$	7.49		$	7.49		$	7.49		$	7.49
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50

2013 – Basis swap contracts
Volume (MMBtu)		12,500			12,500			12,500			12,500			12,500
Price per MMBtu	$	(0.63	)	$	(0.63	)	$	(0.63	)	$	(0.63	)	$	(0.63	)

2014 – Swap contracts
Volume (MMBtu)		30,000			30,000			30,000			30,000			30,000
Price per MMBtu	$	6.07		$	6.07		$	6.07		$	6.07		$	6.07

2014 – Collar contracts with short puts
Volume (MMBtu)		50,000			50,000			50,000			50,000			50,000
Price per MMBtu:
Ceiling	$	8.08		$	8.08		$	8.08		$	8.08		$	8.08
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50

(a)	Subsequent to June 30, 2010, the Company entered into additional swap contracts for 20,000 MMBtu, 30,000 MMBtu and 20,000 MMBtu, respectively, of the Company’s 2011, 2012 and 2014 production at an average price of $5.20 per MMBtu, $5.53 per MMBtu and $6.03 per MMBtu, respectively.

Interest rates. The following table sets forth as of June 30, 2010 the notional amount of the Company’s debt under outstanding variable-for-fixed and fixed-for-variable interest rate swap contracts, the weighted average fixed annual interest rate and termination date for those contracts:


Type	Notional Amount		Weighted Average Fixed Interest Rate	Termination Date
	(in thousands)
Variable-for-fixed	$	189,000	3.0 percent	February 2011
Fixed-for-variable	$	400,000	2.87 percent	July 2016
Fixed-for-variable	$	70,000	3.23 percent	March 2017

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

Tabular disclosure of derivative financial instruments. Effective February 1, 2009, the Company discontinued hedge accounting on all existing commodity derivative instruments, and since that date has accounted for derivative instruments under the mark-to-market accounting rules. Consequently, all of the Company’s derivatives were non-hedge derivatives as of June 30, 2010 and December 31, 2009, except for $9.0 million and $17.9 million of net obligations on terminated hedges, respectively. The following tables provide disclosure of the Company’s derivative instruments:


Fair Value of Derivative Instruments as of June 30, 2010
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)

Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	159,562	Derivatives - current	$	40,254
Interest rate derivatives	Derivatives - current		11,366	Derivatives - current		3,255
Commodity price derivatives	Derivatives - noncurrent		146,217	Derivatives - noncurrent		26,947
Interest rate derivatives	Derivatives - noncurrent		16,178	Derivatives - noncurrent		6,966

Total derivatives not designated as hedging instruments			333,323			77,422

Derivatives designated as hedging instruments (b)
Commodity price derivatives	Derivatives - current		288	Derivatives - current		9,286

Total derivatives designated as hedging instruments			288			9,286

Total derivatives		$	333,611		$	86,708


Fair Value of Derivative Instruments as of December 31, 2009
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)

Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	66,442	Derivatives - current	$	120,112
Interest rate derivatives	Derivatives - current		9,450	Derivatives - current		5,169
Commodity price derivatives	Derivatives - noncurrent		48,341	Derivatives - noncurrent		116,233
Interest rate derivatives	Derivatives - noncurrent		2,192	Derivatives - noncurrent		24,314

Total derivatives not designated as hedging instruments			126,425			265,828

Derivatives designated as hedging instruments (b)
Commodity price derivatives	Derivatives - current		—	Derivatives - current		17,913

Total derivatives designated as hedging instruments			—			17,913

Total derivatives		$	126,425		$	283,741

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

(b)	Represent derivative obligations under terminated hedge arrangements.


Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI on Effective Portion
	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(in thousands)

Interest rate derivatives	$	—	$	—	$	—	$	(433	)
Commodity price derivatives		—		—		—		13,407

Total	$	—	$	—	$	—	$	12,974

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Three Months Ended June 30,						Six Months Ended June 30,
		2010			2009			2010			2009
		(in thousands)

Interest rate derivatives	Interest expense	$	(312	)	$	(2,017	)	$	(1,370	)	$	(4,272	)
Interest rate derivatives	Derivative gains, net		(1,523	)		—			(2,665	)		—
Commodity price derivatives	Oil and gas revenue		22,532			28,490			45,658			69,912

Total		$	20,697		$	26,473		$	41,623		$	65,640


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives	Amount of Gain (Loss) Recognized in Earnings on Derivatives
		Three Months Ended June 30,					Six Months Ended June 30,
		2010		2009			2010		2009
		(in thousands)

Interest rate derivatives	Derivative gains (losses), net	$	26,517	$	(2,319	)	$	37,916	$	(3,251	)
Commodity price derivatives	Derivative gains (losses), net		152,534		(167,905	)		407,753		(67,110	)

Total		$	179,051	$	(170,224	)	$	445,669	$	(70,361	)

AOCI – Hedging. As of June 30, 2010 and December 31, 2009, AOCI – Hedging represented net deferred gains of $29.2 million and $51.0 million, respectively. The AOCI – Hedging balance as of June 30, 2010 was comprised of $73.2 million of net deferred gains on the effective portions of discontinued commodity hedges, $2.1 million of net deferred losses on the effective portions of discontinued interest rate hedges and $19.3 million of associated net deferred tax provisions, reduced by $22.6 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.

The Company’s $189 million notional amount of variable-for-fixed interest rate derivatives were, prior to February 1, 2009, hedges of the Company’s LIBOR-based borrowings under its credit facility. During the six months ended June 30, 2010, the Company repaid its LIBOR-based borrowings under its credit facility, rendering ineffective the remaining balance of the associated hedge losses deferred in AOCI – Hedging. Accordingly, the Company transferred $1.5 million and $2.7 million, respectively, of deferred hedge losses from AOCI – Hedging as a reduction to derivative gains, net during the three and six months ended June 30, 2010.

During the twelve months ending June 30, 2011, the Company expects to reclassify $59.7 million of AOCI – Hedging net deferred gains to oil and gas revenues (including $15.8 million related to noncontrolling interests) and $267 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $16.4 million of net deferred income tax provisions associated with hedge derivatives during the twelve months ending June 30, 2011 from AOCI – Hedging to income tax expense. For the remaining six months of 2010 and the year ending December 31, 2011, the Company expects to reclassify deferred gains on discontinued commodity hedges of $43.4 million and $32.9 million, respectively, to oil and gas revenues. During 2012, the Company expects to reclassify deferred losses on discontinued commodity hedges of $3.2 million to oil and gas revenues. The $2.1 million of net deferred hedge losses on the effective portion of interest rate hedges will be transferred from AOCI-Hedging to interest expense ratably through April 2018.

NOTE H. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. 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 activity during the three and six months ended June 30, 2010 and 2009:

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)

Beginning asset retirement obligations	$	142,270		$	173,516		$	166,434		$	172,433
Liabilities assumed in acquisitions		6			—			6			—
New wells placed on production and changes in estimates		4,365			15,327			4,644			15,366
Liabilities reclassified to discontinued operations held for sale		—			(14,353	)		—			(14,353	)
Disposition of wells		(3,291	)		(246	)		(29,540	)		(246	)
Liabilities settled		(8,801	)		(23,046	)		(9,955	)		(24,976	)
Accretion of discount from continuing operations		2,632			2,753			5,592			5,505
Accretion of discount from discontinued operations		—			220			—			442


Ending asset retirement obligations	$	137,181		$	154,171		$	137,181		$	154,171

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of June 30, 2010 and December 31, 2009, the current portions of the Company’s asset retirement obligations were $8.8 million and $13.9 million, respectively.

NOTE I. Postretirement Benefit Obligations

As of June 30, 2010 and December 31, 2009, the Company had $9.0 million and $9.1 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. These obligations are comprised of five plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of June 30, 2010 or December 31, 2009. Other than participants in the Company’s retirement plan, the participants of these plans are not current employees of the Company.

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the three and six months ended June 30, 2010 and June 30, 2009:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)

Beginning accumulated postretirement benefit obligations	$	8,951		$	9,504		$	9,075		$	9,612
Net benefit payments		(272	)		(362	)		(584	)		(691	)
Service costs		81			57			161			114
Net actuarial losses		100			—			100			—
Accretion of interest		108			165			216			329


Ending accumulated postretirement benefit obligations	$	8,968		$	9,364		$	8,968		$	9,364

NOTE J. Commitments and Contingencies

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

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 “Division”). The Notice alleges violations of stormwater discharge permits in the Company’s Raton Basin and former 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 is in advanced discussions with the Division to resolve this matter and does not believe that the outcome of this proceeding will materially impact the Company’s liquidity, financial position or future results of operations.

Investigation by the Alaska Oil and Gas Conservation Commission (the “AOGCC”). During the second quarter of 2010, the AOGCC commenced an investigation into allegations by a former Pioneer employee regarding the Company’s Oooguruk facility on the North Slope of Alaska. Among the allegations are claims that the Company did not have authorization to inject certain non-hazardous substances into its enhanced oil recovery well, that the Company mishandled disposal of waste products and that the Company’s operating practices are harmful to the project’s oil reservoirs. Upon initially becoming aware of the allegations, the Company informed the AOGCC and other relevant federal, state and local agencies and commenced its own investigation, which confirmed injections of non-hazardous fluids into the Oooguruk enhanced oil recovery well without prior authorizations to do so. The results of the investigation have been reported to the agencies, and the Company is cooperating with the AOGCC’s investigation. Although the investigation into the allegations is ongoing, based on the facts as known to date, the Company believes that the outcome of this investigation will not materially and negatively affect the Company’s liquidity, financial position or future results of operations.

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

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

NOTE K. Net Income (Loss) Per Share Attributable To Common Stockholders

The Company’s basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to loss per share and conversion into common stock is assumed not to occur.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

The following table is a reconciliation of the Company’s net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2010:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)

Net income (loss) attributable to common stockholders	$	167,576		$	(86,996	)	$	412,830		$	(101,601	)
Participating basic distributed earnings (a)		(121	)		(121	)		(108	)		(95	)
Participating basic undistributed earnings (a)		(3,962	)		—			(9,283	)		—

Basic net income (loss) attributable to common stockholders		163,493			(87,117	)		403,439			(101,696	)
Diluted adjustments to share- and unit-based earnings (a)		72			—			110			—


Diluted net income (loss) attributable to common stockholders	$	163,565		$	(87,117	)	$	403,549		$	(101,696	)

(a)

In accordance with ASC 260, unvested restricted stock awards and Pioneer Southwest phantom unit awards represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- and unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009
	(in thousands)

Weighted average common shares outstanding (a):
Basic	115,104	113,979	114,880	114,116
Dilutive common stock options (b)	262	—	243	—
Contingently issuable – performance shares (b)	640	—	612	—


Diluted	116,006	113,979	115,735	114,116

(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 June 30, 2010. During the first half of 2010, the Company did not purchase any common stock pursuant to the program. During the first half of 2009, the Company purchased $16.3 million of common stock pursuant to the program.

(b)

Diluted earnings per share were calculated using the two-class method for the three and six months ended June 30, 2010 and 2009. The following common stock equivalents were excluded from the diluted loss per share calculations for the three and six months ended June 30, 2009 because they would have been anti-dilutive to the calculations: 174,438 and 87,219 of performance units, respectively, for which shares are contingently issuable and stock options to purchase 124,057 and 142,358 common shares, respectively.

NOTE L. Geographic Operating Segment Information

The Company has reportable operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable continuing operations in the United States, South Africa and Tunisia.

The following tables provide the Company’s geographic operating segment data for the three and six months ended June 30, 2010 and 2009. Geographic operating segment income tax (provisions) benefits have been determined

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

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.


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)

Three Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	401,545		$	20,502		$	40,095		$	—		$	462,142
Interest and other		—			—			—			20,263			20,263
Derivative gains, net		—			—			—			177,528			177,528
Gain on disposition of assets, net		7,560			—			—			85			7,645
Hurricane activity, net		(5,184	)		—			—			—			(5,184	)

		403,921			20,502			40,095			197,876			662,394

Costs and expenses:
Oil and gas production		93,120			896			3,278			—			97,294
Production and ad valorem taxes		25,338			—			—			—			25,338
Depletion, depreciation and amortization		117,859			18,442			5,842			8,171			150,314
Exploration and abandonments		22,689			54			4,074			306			27,123
General and administrative		—			—			—			42,374			42,374
Accretion of discount on asset retirement obligations		—			—			—			2,632			2,632
Interest		—			—			—			45,368			45,368
Other		10,270			—			—			4,455			14,725

		269,276			19,392			13,194			103,306			405,168

Income from continuing operations before income taxes		134,645			1,110			26,901			94,570			257,226
Income tax provision		(49,819	)		(311	)		(14,053	)		(30,510	)		(94,693	)

Income from continuing operations	$	84,826		$	799		$	12,848		$	64,060		$	162,533

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)

Three Months Ended June 30, 2009
Revenues and other income:
Oil and gas	$	314,031		$	18,160		$	38,501		$	—		$	370,692
Interest and other		—			—			—			88,598			88,598
Derivative losses, net		—			—			—			(170,224	)		(170,224	)
Gain on disposition of assets, net		7			—			—			46			53
Hurricane activity, net		(16,075	)		—			—			—			(16,075	)

		297,963			18,160			38,501			(81,580	)		273,044

Costs and expenses:
Oil and gas production		75,389			445			8,959			—			84,793
Production and ad valorem taxes		23,715			—			—			—			23,715
Depletion, depreciation and amortization		125,212			20,446			5,750			7,265			158,673
Exploration and abandonments		17,978			195			3,244			201			21,618
General and administrative		—			—			—			33,275			33,275
Accretion of discount on asset retirement obligations		—			—			—			2,753			2,753
Interest		—			—			—			43,475			43,475
Other		18,864			—			3,768			14,083			36,715

		261,158			21,086			21,721			101,052			405,017

Income (loss) from continuing operations before income taxes		36,805			(2,926	)		16,780			(182,632	)		(131,973	)
Income tax benefit (provision)		(13,618	)		849			(9,638	)		64,131			41,724

Income (loss) from continuing operations	$	23,187		$	(2,077	)	$	7,142		$	(118,501	)	$	(90,249	)

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)

Six Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	848,207		$	45,883		$	75,848		$	—		$	969,938
Interest and other		—			—			—			40,066			40,066
Derivative gains, net		—			—			—			443,004			443,004
Gain (loss) on disposition of assets, net		24,979			—			—			(391	)		24,588
Hurricane activity, net		2,226			—			—			—			2,226

		875,412			45,883			75,848			482,679			1,479,822

Costs and expenses:
Oil and gas production		178,443			1,672			6,894			—			187,009
Production and ad valorem taxes		52,399			—			—			—			52,399
Depletion, depreciation and amortization		233,364			40,339			12,017			15,362			301,082
Exploration and abandonments		39,465			126			8,000			329			47,920
General and administrative		—			—			—			83,322			83,322
Accretion of discount on asset retirement obligations		—			—			—			5,592			5,592
Interest		—			—			—			92,891			92,891
Other		20,551			—			—			10,750			31,301

		524,222			42,137			26,911			208,246			801,516

Income from continuing operations before income taxes		351,190			3,746			48,937			274,433			678,306
Income tax provision		(129,940	)		(1,049	)		(25,654	)		(98,524	)		(255,167	)

Income from continuing operations	$	221,250		$	2,697		$	23,283		$	175,909		$	423,139

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)


	United States			South Africa			Tunisia			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2009
Revenues and other income:
Oil and gas	$	641,815		$	29,965		$	66,763		$	—		$	738,543
Interest and other		—			—			—			99,258			99,258
Derivative losses, net		—			—			—			(70,361	)		(70,361	)
Gain (loss) on disposition of assets, net		7			—			—			(69	)		(62	)
Hurricane activity, net		(16,450	)		—			—			—			(16,450	)

		625,372			29,965			66,763			28,828			750,928

Costs and expenses:
Oil and gas production		173,498			3,941			17,784			—			195,223
Production and ad valorem taxes		51,414			—			—			—			51,414
Depletion, depreciation and amortization		285,181			37,000			10,066			14,570			346,817
Impairment of oil and gas properties		21,091			—			—			—			21,091
Exploration and abandonments		41,369			289			10,549			581			52,788
General and administrative		—			—			—			67,929			67,929
Accretion of discount on asset retirement obligations		—			—			—			5,505			5,505
Interest		—			—			—			84,613			84,613
Other		39,150			—			3,768			25,186			68,104

		611,703			41,230			42,167			198,384			893,484

Income (loss) from continuing operations before income taxes		13,669			(11,265	)		24,596			(169,556	)		(142,556	)
Income tax benefit (provision)		(5,058	)		3,267			(14,684	)		58,940			42,465

Income (loss) from continuing operations	$	8,611		$	(7,998	)	$	9,912		$	(110,616	)	$	(100,091	)

NOTE M. Impairment of Oil and Gas Properties

During the first half of 2009, the Company recognized a noncash impairment charge of $21.1 million to reduce the carrying value of its Uinta/Piceance area oil and gas properties. The impairment charge resulted from declines in commodity prices and well performance which reduced the Company’s assessment of economically recoverable resource potential. The impairment charge reduced the Company’s Uinta/Piceance area oil and gas property carrying values to their estimated fair value on that date based on the estimated discounted future cash flows attributable to the assets, which were derived from Level 3 fair value inputs.

The Company’s primary assumptions of the estimated future cash flows attributable to oil and gas properties were based on (i) proved reserves and risk-adjusted probable and possible reserves and (ii) management’s commodity price outlook, which is based in part on forward market quotes.

NOTE N. Volumetric Production Payments

The Company’s VPPs represent limited-term overriding royalty interests in oil 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.

At the inception of the VPP agreements, 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 revenues over the remaining 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

The following table provides information about changes in the deferred revenue carrying values of the Company’s VPPs for the six months ended June 30, 2010 (in thousands):


Deferred revenue at December 31, 2009	$	177,236
Less: 2010 amortization		(45,070	)

Deferred revenue at June 30, 2010	$	132,166

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


Remaining 2010	$	45,146
2011		44,951
2012		42,069

	$	132,166

NOTE O. Gain (Loss) on Disposition of Assets, Net

For the three and six months ended June 30, 2010, the Company recorded $7.6 million and $24.6 million of net gains on disposition of assets, respectively, as compared to $53 thousand of net gains and $62 thousand of net losses for the three and six months ended June 30, 2009, respectively.

The net gains on disposition of assets during the three months ended June 30, 2010 were primarily attributable to the Company’s Eagle Ford Shale joint venture transaction that was completed during June 2010. During June 2010, the Company entered into a purchase and sale agreement whereby it sold (i) 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $225.6 million of cash proceeds, including normal closing adjustments and (ii) sold a 49.9 percent interest in EFS Midstream for $46.4 million of cash proceeds (see Note B for additional information regarding EFS Midstream). The terms of the Eagle Ford Shale transaction also provide that the purchaser will pay 75 percent (up to $886.8 million, including $8.1 million attributable to recently leased acreage that was sold at closing) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension. Associated with these transactions, the Company recorded a net gain on disposition of assets of $5.7 million during the three and six months ended June 30, 2010, and a deferred gain of $46.3 million that will be amortized to earnings over a 20 year period. During the first half of 2010, the Company also sold certain proved and unproved oil and gas properties in the Uinta/Piceance area for net proceeds of $12.1 million, resulting in net gains of $1.9 million and $17.4 million, respectively, for the three and six months ended June 30, 2010.

The Company’s 2009 asset dispositions primarily comprised sales of excess equipment and inventory.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

NOTE P. Interest and Other Income

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2010		2009			2010		2009
	(in thousands)

Alaskan Petroleum Production Tax credits (a)	$	13,613	$	87,511		$	27,861	$	94,989
Foreign currency remeasurement and exchange gains (b)		4,098		(735	)		5,978		617
Insurance claim recovery		—		—			1,665		—
Sales and other tax refunds		944		—			984		—
Contract drilling margin		998		—			1,507		—
Deferred compensation plan income		174		74			684		861
Interest income		92		749			480		1,379
Other income		344		999			907		1,412

Total interest and other income	$	20,263	$	88,598		$	40,066	$	99,258

(a)	The Company earns Alaskan Petroleum Production Tax (“PPT”) credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or sales.

(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.

NOTE Q. Other Expense

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)

Excess and terminated rig related costs (a)	$	10,270		$	22,632		$	20,551		$	42,918
Well servicing operations (b)		1,579			2,391			4,660			5,382
Other		2,552			866			3,128			1,345
Inventory impairment (c)		13			433			1,570			1,603
Foreign currency remeasurement and exchange losses (d)		471			3,408			1,175			4,733
Contingency and environmental accrual adjustments		94			262			247			6,086
Bad debt recoveries		(254	)		(58	)		(30	)		(744	)
Transportation commitment charge		—			6,781			—			6,781

Total other expense	$	14,725		$	36,715		$	31,301		$	68,104

(a)	Represents above market drilling rig costs, idle rig costs 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.

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

NOTE R. Insurance Claims

As a result of Hurricane Rita in September 2005, the Company’s East Cameron facility, located in the Gulf of Mexico shelf, was destroyed. As of June 30, 2010, the Company estimates that it will cost an additional $3.1 million to complete the reclamation and abandonment of the East Cameron facility.

The operations to reclaim and abandon the East Cameron facilities began in January 2007. The remaining estimated cost to reclaim and abandon the East Cameron facilities contains a number of assumptions that could cause the ultimate cost to be higher or lower than the estimate, as there are many uncertainties when working offshore and underwater with low visibility. The Company has expended $205.2 million on the reclamation and abandonment of the East Cameron facility through June 30, 2010.

During the six months ended June 30, 2010, the Company received $7.7 million from its insurance providers related to debris removal, which was credited to Hurricane activity, net in the accompanying consolidated statement of operations. Since operations began to reclaim and abandon the East Cameron facility, the Company has recovered $53.9 million from its insurance providers related to reclamation and abandonment costs. In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues, primarily related to debris removal, certain costs associated with plugging and abandonment, and the well restoration and safety coverages. The Company believes that a substantial portion of the unrecovered costs incurred on the reclamation and abandonment of the East Cameron facility will be recoverable from insurance in the future.

NOTE S. Discontinued Operations

The Company sold substantially all of its Mississippi assets and shelf properties in the Gulf of Mexico during June and August 2009, respectively. The Company has reflected the results of operations of these properties as discontinued operations, rather than as a component of continuing operations, in the accompanying consolidated statements of operations.

During the fourth quarter of 2009, the Company recorded a $119.3 million receivable from the MMS for the recovery of excess royalties paid by the Company on qualifying deepwater leases in the Gulf of Mexico. The MMS paid the Company the $119.3 million receivable during the first half of 2010. Additionally, the MMS paid the Company $35.3 million of associated interest on the excess royalty payments during the three months ended June 30, 2010. The properties that were the source of these royalty and interest recoveries were sold by the Company during 2006. Accordingly, the $35.3 million of interest income recorded during the three and six months ended June 30, 2010 is a component of income from discontinued operations, net of tax in the accompanying consolidated statements of operations for the three and six months ended June 30, 2010.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2010

(Unaudited)

The following table represents the components of the Company’s discontinued operations for the three and six months ended June 30, 2010 and June 30, 2009:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)

Revenues and other income:
Oil and gas	$	—		$	5,736		$	—		$	11,722
Interest and other (a)		39,308			—			39,308			—
Gain on disposition of assets, net (b)		—			306			—			306

		39,308			6,042			39,308			12,028

Costs and expenses:
Oil and gas production		—			2,109			—			4,649
Production and ad valorem taxes		—			60			—			118
Depletion, depreciation and amortization (b)		—			(551	)		—			3,862
Exploration and abandonments (b)		—			22			—			283
General and administrative		—			(21	)		—			(36	)
Accretion of discount on asset retirement obligations (b)		—			220			—			442

		—			1,839			—			9,318

Income from discontinued operations before income taxes		39,308			4,203			39,308			2,710
Income tax provision:
Current		(53	)		(1,472	)		(53	)		(949	)
Deferred (b)		(13,099	)		—			(13,099	)		—

Income from discontinued operations	$	26,156		$	2,731		$	26,156		$	1,761

(a)

Represents (i) $35.3 million of interest paid to the Company by the MMS on excess royalty payments on Gulf of Mexico discontinued operations sold during 2006, (ii) $2.1 million of Canadian sales tax refunds attributable to Canadian discontinued operations sold during 2007 and (iii) $1.9 million of Argentine value added tax contingency charge reversals on Argentine discontinued operations sold during 2006.

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

NOTE T. Subsequent Events

The Company has evaluated subsequent events through the date of issuance of its unaudited consolidated financial statements. The Company is not aware of any reportable subsequent events.

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 second quarter of 2010 included the following highlights:

•

Daily sales volumes decreased by two percent to 113,451 BOEPD during the second quarter of 2010, as compared to 115,436 BOEPD during the second quarter of 2009. The decrease in second quarter 2010 sales volumes, as compared to the second quarter of 2009, was primarily due to the impact on 2010 production from a curtailment of drilling activities during 2009.

•

Average reported oil, NGL and gas prices increased during the second quarter of 2010 to $87.71 per Bbl, $34.40 per Bbl and $4.10 per Mcf, respectively, as compared to respective prices of $70.89 per Bbl, $26.78 per Bbl and $3.43 per Mcf during the second quarter of 2009.

•

Average per-BOE oil and gas production costs increased during the second quarter of 2010 to $9.42, as compared to $8.07 per BOE during the second quarter of 2009, primarily as a result of declines in net natural gas plant gathering and processing margins and the per-BOE effects of lower production on fixed components of lease operating expense.

•

Earnings attributable to common stockholders was $167.6 million ($1.41 per diluted share), as compared to net loss attributable to common stockholders of $87.0 million ($0.76 per diluted share) for the second quarter of 2009. The increase in earnings attributable to common stockholders is primarily due to $177.5 million mark-to-market derivative gains during the second quarter of 2010 as compared to $170.2 million of mark-to-market derivative losses during the second quarter of 2009, a $91.5 million increase in oil and gas revenues and a $23.4 million increase in income from discontinued operations, primarily associated with the receipt of interest on excess royalty payments to the MMS (see Note S of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements”).

•

Net cash provided by operating activities increased to $393.9 million for the second quarter of 2010, as compared to $223.9 million for the second quarter of 2009. The $170.0 million increase in net cash provided by operating activities was primarily due to increases in oil and gas revenues and changes in working capital.

•

Net debt to book capitalization decreased to 37 percent at June 30, 2010, as compared to 43 percent at December 31, 2009, principally due to debt repayments from divestiture proceeds, earnings attributable to gains on asset sales and mark-to-market gains on derivative contracts.

Eagle Ford Shale Joint Venture

During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction and associated therewith the Company received $272.0 million of cash proceeds during the second quarter of 2010, including normal closing adjustments. Pursuant to the transaction, the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $225.6 million of cash proceeds, including normal closing adjustments. The terms of the transaction also provide that the purchaser will pay 75 percent (up to $886.8 million, including $8.1 million attributable to recently leased acreage that was sold at closing) of the Company’s defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the six years ending on July 1, 2016, subject to extension.

The Company also sold a 49.9 percent member interest in EFS Midstream to the purchaser for $46.4 million of cash proceeds. The Company does not have voting control of EFS Midstream. The Company deconsolidated the financial statements of EFS Midstream and is accounting for its investment in the venture under the equity method.

EFS Midstream is obligated to construct midstream assets in the Eagle Ford Shale play that will provide gathering, treating and transportation services for the Eagle Ford Shale properties. As EFS Midstream constructs midstream assets, the Company will be responsible for funding 50.1 percent of EFS Midstream’s cash requirements. The Company’s share of EFS Midstream’s capital expenditures is estimated to be approximately $50 million during the second half of 2010. It is expected that the midstream assets will be constructed during the period from July 2010 through 2014, with first throughput and revenues realized during the fourth quarter of 2010 and ramping up thereafter based on planned exploration and development of the Eagle Ford Shale play.

PIONEER NATURAL RESOURCES COMPANY

Third Quarter 2010 Outlook

Based on current estimates, the Company expects that third quarter 2010 production will average 113,000 to 116,000 BOEPD. The range reflects the planned oil export schedule for Tunisia.

Third quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $11.75 to $13.75 per BOE based on current NYMEX strip prices for oil, NGLs and gas. Depletion, depreciation and amortization (“DD&A”) expense is expected to average $14.25 to $15.50 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $35 million to $45 million, primarily related to exploration wells being drilled in Tunisia, Eagle Ford Shale and a 2006 drilling commitment well that will be drilled in Utah targeting an oil prospect near existing discoveries, plus related acreage costs, and seismic and personnel costs. General and administrative expense is expected to be $41 million to $44 million. Interest expense is expected to be $44 million to $47 million, and other expense is expected to be $12 million to $17 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ net income, excluding noncash mark-to-market adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company’s third quarter effective income tax rate is expected to range from 40 percent to 50 percent, assuming current capital spending plans, higher tax rates in certain foreign jurisdictions and no significant mark-to-market changes in the Company’s derivative position. Cash income taxes are expected to range from $15 million to $25 million, principally related to South African and Tunisian income taxes.

Operations and Drilling Highlights

The following table summarizes the Company’s average daily oil, NGL, gas and total production by asset area during the six months ended June 30, 2010:


	Oil (Bbls)	NGLs (Bbls)	Gas (Mcf)	Total (BOE)
United States:
Permian Basin	15,747	10,369	42,801	33,248
Mid-Continent	4,059	7,634	56,236	21,066
Rocky Mountains	19	19	174,539	29,128
Barnett Shale	106	1,008	9,568	2,708
South Texas	54	—	50,103	8,405
Eagle Ford Shale	309	174	6,689	1,598
Alaska	6,335	—	—	6,335
Other	1	—	112	20

	26,630	19,204	340,048	102,508

South Africa	875	—	29,915	5,861
Tunisia	5,066	—	2,686	5,514

Total Worldwide	32,571	19,204	372,649	113,883

The Company intends to limit 2010 capital expenditures, excluding the effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, to internally-generated operating cash flow for the year. During the six months ended June 30, 2010, cash flow from operating activities was $693.2 million and the Company’s capital expenditures, excluding the effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs, were $528.0 million.

PIONEER NATURAL RESOURCES COMPANY

The following table summarizes by geographic area the Company’s finding and development costs incurred during the six months ended June 30, 2010:


	Acquisition Costs					Exploration Costs		Development Costs			Asset Retirement Obligations		Total
	Proved			Unproved		Exploration Costs		Development Costs			Asset Retirement Obligations		Total
	(in thousands)

United States:
Permian Basin	$	406		$	1,562	$	5,672	$	216,146		$	178	$	223,964
Mid-Continent		—			—		370		2,069			18		2,457
Rocky Mountains		(3	)		291		3,984		6,766			7		11,045
Barnett Shale		(89	)		23,393		12,408		117			5		35,834
South Texas		122			824		12,961		10,227			7		24,141
Eagle Ford Shale		2,272			100,160		65,271		59			51		167,813
Alaska		—			—		14,948		44,160			427		59,535
Other		—			—		2		—			—		2

		2,708			126,230		115,616		279,544			693		524,791

South Africa		—			—		126		(53	)		279		352
Tunisia		—			—		16,657		15,661			178		32,496
Other		—			—		329		—			—		329

Total Worldwide	$	2,708		$	126,230	$	132,728	$	295,152		$	1,150	$	557,968

The following table summarizes the Company’s development and exploration/extension drilling activities for the six months ended June 30, 2010:


	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
United States	11	202	192	1	20
Tunisia	—	1	1	—	—

Total Worldwide	11	203	193	1	20


	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Sold Wells	Ending Wells in Progress
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Sold Wells	Ending Wells in Progress
United States	8	19	9	—	1	17
Tunisia	5	2	2	—	—	5

Total Worldwide	13	21	11	—	1	22

Permian Basin area. During the first half of 2010, the Company drilled 185 wells in the Spraberry field. The Company is currently utilizing 20 rigs, and plans to drill approximately 440 wells during 2010. The Company intends to continue to expand its drilling program past 2010, with plans to increase its rig count to 40 rigs by 2012, which will allow the Company to drill approximately 1,000 wells per year. The Company acquired six rigs during the first half of 2010 and plans to acquire six additional Company-owned rigs to support about 30 percent of the planned 40-rig program.

During 2010, the Company commenced a Spraberry field waterflood project that is located on approximately 7,000 acres within an existing Spraberry unit. Drilling, conversion and facility work was completed during the second quarter of 2010 and the Company plans to commence water injection during the third quarter of 2010, with initial oil response expected during the first half of 2011.

PIONEER NATURAL RESOURCES COMPANY

During 2008, the Company initiated a program to test 20-acre infill drilling performance, as part of its announced recovery improvement initiatives. The Company drilled and completed eleven 20-acre wells in 2008 and completed nine additional 20-acre wells in 2009 with encouraging results. In the second half of 2010, the Company plans to drill approximately 25 additional 20-acre wells.

South Texas and Eagle Ford Shale area. The Company’s drilling activities in the South Texas area during 2010 continues to be primarily focused on delineation and development of Pioneer’s substantial acreage position in the Eagle Ford Shale play.

The Company drilled six wells in the Eagle Ford Shale play during the first half of 2010. Production from certain of these wells is awaiting the construction of permanent production facilities, which is scheduled to be completed during the fourth quarter of 2010. The Company is currently running five drilling rigs in the Eagle Ford Shale play and the Company intends to add at least two additional rigs by the end of 2010.

Alaska. During the second quarter of 2010, the Company continued drilling activities at its Oooguruk development project. The Company drilled and completed one horizontal water injection well and commenced drilling one dual lateral, horizontal production well during the second quarter of 2010, both within the project’s Nuiqsut reservoir. The newly drilled and completed water injection well will be pre-produced prior to commencing water injection, with initial gross production rates averaging 600 barrels of oil per day. The Company continued extended flow testing operations and analysis of the project’s Moraine reservoir with additional flow testing and analysis planned for the remainder of 2010.

On the Company’s Cosmopolitan Unit project in the Cook Inlet, the Company drilled a lateral sidetrack during 2007 from an existing wellbore on an onshore site to further appraise the resource potential of the unit. The initial un-stimulated production test results were encouraging. The Company performed casing repair workover operations on the well during the fourth quarter of 2009, fracture-stimulated the well during the first quarter of 2010 and plans to perform extended flow testing and analysis of the well during the remainder of 2010. The Company will continue to conduct permitting activities and facilities planning and may drill another appraisal well during 2011.

Tunisia. Following an extensive geosciences work program, the Company recommenced its drilling program in the Company-operated Cherouq concession with the successful drilling of a development well. Additionally, the Company is upgrading its existing production facilities by installing permanent processing equipment and artificial lift, which it intends to utilize to optimize production and reduce production costs.

During the second quarter of 2010, the Company continued its drilling activities on the Adam Concession with the successful drilling of an exploration well that will be placed on production during the early portion of the third quarter. On the Borj El Khadra Permit, the Company completed the acquisition and began processing of 1,185 square kilometers of 3-D seismic data in order to high-grade leads identified on existing 2-D seismic data. The Company plans to drill an exploration well on the permit in the second half of 2010, following interpretation of the processed data.

In the Anaguid Permit, the Company has submitted a plan of development in order to convert a portion of the existing exploration permit into a production concession to enable it to commence production from its Durra-1 discovery well. Additionally, the Company drilled another exploration well on the block, which is expected to be completed and tested during the third quarter of 2010.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $462.1 million and $969.9 million for the three and six months ended June 30, 2010, respectively, as compared to $370.7 million and $738.5 million for the same respective periods of 2009.

The increase in oil and gas revenues during the three and six months ended June 30, 2010, as compared to the same periods of 2009, is reflective of increases in revenues for all geographic operating segments. The increase in revenues was due to increases in average reported commodity prices, partially offset by decreases in sales volumes in the United States and Tunisia as a result of significant reductions in drilling activity during 2009.

The following table provides average daily sales volumes from continuing operations, by geographic area and in total, for the three and six months ended June 30, 2010 and 2009:

PIONEER NATURAL RESOURCES COMPANY


	Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009
Oil (Bbls):
United States	27,448	23,873	26,630	25,109
South Africa	641	379	875	312
Tunisia	5,178	7,154	5,066	6,754

Worldwide	33,267	31,406	32,571	32,175

NGLs (Bbls):
United States	19,291	18,921	19,204	20,778

Gas (Mcf):
United States	333,916	355,661	340,048	370,565
South Africa	28,810	33,243	29,915	31,771
Tunisia	2,628	1,753	2,686	2,048

Worldwide	365,354	390,657	372,649	404,384

Total (BOE):
United States	102,392	102,069	102,508	107,647
South Africa	5,443	5,920	5,861	5,608
Tunisia	5,616	7,447	5,514	7,095

Worldwide	113,451	115,436	113,883	120,350

In the United States, average daily sales volumes were essentially the same for the three months ended June 30, 2010 and decreased by five percent during the six months ended June 30, 2010, as compared to the same respective periods of 2009. For the three and six months ended June 30, 2010, average sales volumes decreased by 25 percent and 22 percent, respectively, in Tunisia, while average daily sales volumes decreased by eight percent and increased by five percent, respectively, in South Africa.

During the three and six months ended June 30, 2010, as compared to the three and six months ended June 30, 2009, oil volumes delivered under the Company’s VPPs decreased by nine percent for each respective period. The Company satisfied its remaining VPP gas delivery obligations at the end of 2009.

The oil, NGL and gas prices that the Company reports are based on the market price received for the commodities adjusted for the amortization of the Company’s cash flow hedging activities and the amortization of deferred VPP revenue. See “Derivative activities” and “Deferred revenue” discussion below for additional information regarding the Company’s cash flow hedging activities and amortization of VPP revenue.

PIONEER NATURAL RESOURCES COMPANY

The following table provides average reported prices (including transfers of deferred hedge gains and the amortization of deferred VPP revenue) and average realized prices (excluding transfers of deferred hedge gains and the amortization of deferred VPP revenue) by geographic area and in total, for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Average reported prices:
Oil (per Bbl):
United States	$	89.50	$	75.13	$	90.74	$	64.39
South Africa	$	76.88	$	62.27	$	77.32	$	56.33
Tunisia	$	79.56	$	57.23	$	76.80	$	52.57
Worldwide	$	87.71	$	70.89	$	88.21	$	61.83
NGL (per Bbl):
United States	$	34.40	$	26.78	$	38.07	$	24.69
Gas (per Mcf):
United States	$	3.87	$	3.24	$	4.52	$	3.82
South Africa	$	6.11	$	5.29	$	6.21	$	4.66
Tunisia	$	10.89	$	7.78	$	11.15	$	6.74
Worldwide	$	4.10	$	3.43	$	4.71	$	3.90
Average realized prices:
Oil (per Bbl):
United States	$	72.53	$	52.78	$	73.05	$	43.39
South Africa	$	76.88	$	62.27	$	77.32	$	56.33
Tunisia	$	79.56	$	57.23	$	76.80	$	52.57
Worldwide	$	73.71	$	53.91	$	73.75	$	45.44
NGL (per Bbl):
United States	$	33.36	$	25.42	$	37.03	$	23.45
Gas (per Mcf):
United States	$	3.84	$	2.79	$	4.50	$	3.17
South Africa	$	6.11	$	5.29	$	6.21	$	4.66
Tunisia	$	10.89	$	7.78	$	11.15	$	6.74
Worldwide	$	4.07	$	3.02	$	4.68	$	3.31

Derivative activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts 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. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for the scheduled amortization of net deferred gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil and gas revenues.

The following table provides the transfers of deferred hedge gains from Accumulated Other Comprehensive Income (“AOCI”) associated with oil, NGL and gas price cash flow hedges to oil, NGL and gas revenue for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,				Three Months Ended June 30,
	2010		2009		2010		2009
	(in thousands)

Increase to oil revenue from AOCI transfers	$	19,792	$	23,896	$	40,209	$	46,260
Increase to NGL revenue from AOCI transfers		1,820		2,342		3,619		4,678
Increase to gas revenue from AOCI transfers		920		2,252		1,830		18,974

Total	$	22,532	$	28,490	$	45,658	$	69,912

PIONEER NATURAL RESOURCES COMPANY

Deferred revenue. During the three and six months ended June 30, 2010 and 2009, the Company’s amortization of deferred VPP revenue increased oil and gas revenues by $22.6 million and $45.1 million, respectively, as compared to an increase of $37.0 million and $73.7 million during the same respective periods of 2009. See Note N of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s VPPs.

Interest and other income. Interest and other income for the three and six months ended June 30, 2010 was $20.3 million and $40.1 million, respectively, as compared to $88.6 million and $99.3 million for the same respective periods in 2009. The decrease in interest and other income during the three and six months ended June 30, 2010, as compared to the same respective periods in 2009, was primarily due to a $73.9 million and $67.1 million decrease in Alaskan Petroleum Production tax credit recoveries, respectively. See Note P of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding interest and other income.

Derivative gains, net. During the three and six months ended June 30, 2010, the Company recorded $177.5 million and $443.0 million, respectively, of net derivative gains on commodity price and interest rate derivatives. For the three months ended June 30, 2010, $146.2 million represented unrealized gains subject to continuing market risk and $31.3 million represented realized gains. For the six months ended June 30, 2010, $413.2 million represented unrealized gains subject to continuing market risk and $29.8 million represented realized gains. During the three and six months ended June 30, 2009, the Company recorded $170.2 million and $70.4 million, respectively, of net derivative losses.

Gain (loss) on disposition of assets, net. The Company recorded net gains on the disposition of assets of $7.6 million and $24.6 million during the three and six months ended June 30, 2010, respectively, as compared to a net gain on the disposition of assets of $53 thousand for the three months ended June 30, 2009 and a net loss on the disposition of assets of $62 thousand during the six months ended June 30, 2009. The increase in net gains is primarily associated with the first and second quarter 2010 sales of certain proved and unproved oil and gas properties in the Uinta/Piceance area and gains associated with the Eagle Ford Shale joint venture transaction. See Note O of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s gains and losses on dispositions of assets.

Hurricane activity, net. The Company recorded a net hurricane related charge of $5.2 million during the three months ended June 30, 2010, net hurricane related recoveries of $2.2 million during the six months ended June 30, 2010, and net hurricane related charges of $16.1 million and $16.5 million during the same respective periods of 2009. Hurricane activity, net is associated with the Company’s East Cameron platform facility, located on the Gulf of Mexico shelf, which was destroyed during 2005 by Hurricane Rita.

The Company estimates that it will expend approximately $3.1 million to complete the operations to reclaim and abandon the East Cameron platform facilities during the second half of 2010 or during 2011. Since January 2007, the Company has expended approximately $205.2 million on operations to reclaim and abandon the East Cameron platform facilities. The Company’s remaining estimate to reclaim and abandon the East Cameron facilities is based upon an analysis prepared by the Company. See Note R 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.

Oil and gas production costs. The Company recorded oil and gas production costs of $97.3 million and $187.0 million during the three and six months ended June 30, 2010, respectively, as compared to $84.8 million and $195.2 million during the same respective periods of 2009. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company’s gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE from continuing operations increased by 17 percent and one percent during the three and six months ended June 30, 2010, respectively, as compared to the same respective periods in 2009. The increase in United States production costs is primarily due to the aforementioned decline in net natural gas plant gathering and processing margins and the per-BOE effects of lower production on fixed lease operating cost components, partially offset by reductions in VPP delivery commitments. The decrease in South Africa production costs per BOE is primarily attributable to a decrease in operating costs and an increase in sales volumes. The decrease in Tunisia production costs per BOE is associated with Adam concession tariff recoveries, reduced utilization of leased operations support facilities and reduced workover activities.

PIONEER NATURAL RESOURCES COMPANY

The following tables provide the components of the Company’s oil and gas production costs per BOE from continuing operations and total production costs per BOE from continuing operations by geographic area for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Lease operating expenses	$	7.61	$	6.58	$	7.35	$	7.17
Third-party transportation charges		0.87		0.94		0.89		0.94
Net natural gas plant/gathering charges		0.29		0.07		0.03		0.29
Workover costs		0.65		0.48		0.81		0.55


Total production costs	$	9.42	$	8.07	$	9.08	$	8.95


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
United States	$	10.01	$	8.11	$	9.62	$	8.91
South Africa	$	1.81	$	0.83	$	1.58	$	3.88
Tunisia	$	6.41	$	13.22	$	6.91	$	13.85
Worldwide	$	9.42	$	8.07	$	9.08	$	8.95

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $25.3 million and $52.4 million during the three and six months ended June 30, 2010, respectively, as compared to $23.7 million and $51.4 million for the same respective periods of 2009. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. Consequently, during the three and six months ended June 30, 2010, the Company’s production and ad valorem taxes per BOE have, in the aggregate, increased nine percent and eight percent, reflecting increasing commodity prices.

The following table provides the Company’s production and ad valorem taxes per BOE from continuing operations and total production and ad valorem taxes per BOE from continuing operations for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
Ad valorem taxes	$	1.50	$	1.44	$	1.46	$	1.43
Production taxes		0.96		0.82		1.09		0.93


Total ad valorem and production taxes	$	2.46	$	2.26	$	2.55	$	2.36

Depletion, depreciation and amortization expense. The Company’s total DD&A expense was $150.3 million ($14.56 per BOE) and $301.1 million ($14.61 per BOE) for the three and six months ended June 30, 2010, respectively, as compared to $158.7 million ($15.11 per BOE) and $346.8 million ($15.92 per BOE) during the same respective periods of 2009. The decrease in DD&A expense during the three and six months ended June 30, 2010, as compared to the same respective periods of 2009, is primarily due to a decrease in depletion expense on oil and gas properties.

Depletion expense was $13.77 per BOE and $13.86 per BOE during the three and six months ended June 30, 2010, respectively, as compared to $14.41 per BOE and $15.25 per BOE during the same respective periods of 2009. The four percent and nine percent decreases in per-BOE depletion expense during the three and six months ended June 30, 2010, respectively, is primarily due to an increase in proved reserves as a result of higher commodity prices extending the economic lives of proved properties.

PIONEER NATURAL RESOURCES COMPANY

The following table provides depletion expense per BOE from continuing operations by geographic area for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009

United States	$	12.65	$	13.48	$	12.58	$	14.64
South Africa	$	37.23	$	37.95	$	38.03	$	36.45
Tunisia	$	11.43	$	8.48	$	12.04	$	7.84
Worldwide	$	13.77	$	14.41	$	13.86	$	15.25

Impairment of oil and gas properties. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. The Company recognized an impairment charge of $21.1 million to reduce the carrying value of the Company’s oil and gas properties in the Uinta/Piceance areas during the first half of 2009. Declines in gas prices and downward adjustments to the economically recoverable resource potential of the Company’s Uinta/Piceance oil and gas properties during the first half of 2009 led to the impairment charge.

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 oil and gas properties for impairment.

Exploration and abandonments expense. The following tables provide the Company’s geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense by geographic area for the three and six months ended June 30, 2010 and 2009 (in thousands):


	United States			South Africa		Tunisia		Other		Total
Three Months Ended June 30, 2010
Geological and geophysical	$	18,051		$	54	$	3,969	$	306	$	22,380
Exploratory dry holes		(125	)		—		105		—		(20	)
Leasehold abandonments and other		4,763			—		—		—		4,763

	$	22,689		$	54	$	4,074	$	306	$	27,123


Three Months Ended June 30, 2009
Geological and geophysical	$	9,305		$	195	$	1,841	$	201	$	11,542
Exploratory dry holes		2,824			—		1,403		—		4,227
Leasehold abandonments and other		5,849			—		—		—		5,849

	$	17,978		$	195	$	3,244	$	201	$	21,618

PIONEER NATURAL RESOURCES COMPANY


	United States			South Africa		Tunisia		Other		Total
Six Months Ended June 30, 2010
Geological and geophysical	$	31,117		$	126	$	7,916	$	329	$	39,488
Exploratory dry holes		(234	)		—		84		—		(150	)
Leasehold abandonments and other		8,582			—		—		—		8,582

	$	39,465		$	126	$	8,000	$	329	$	47,920


Six Months Ended June 30, 2009
Geological and geophysical	$	19,285		$	289	$	4,132	$	581	$	24,287
Exploratory dry holes		2,709			—		6,417		—		9,126
Leasehold abandonments and other		19,375			—		—		—		19,375

	$	41,369		$	289	$	10,549	$	581	$	52,788

The Company’s exploration and abandonment expense during the three and six months ended June 30, 2010 is primarily comprised of acquisitions of 3-D seismic in the U.S. and Tunisia, geological and geophysical personnel costs and unproved property abandonments.

During the six months ended June 30, 2010, the Company drilled and evaluated 11 exploration/extension wells, all of which were successfully completed as discoveries. During the same period in 2009, the Company drilled and evaluated seven exploration/extension wells, four of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and six months ended June 30, 2010 was $42.4 million and $83.3 million, respectively, as compared to $33.3 million and $67.9 million during the same respective periods of 2009. The increase in general and administrative expense for the three and six months ended June 30, 2010 was primarily due to respective increases of $7.1 million and $11.9 million in performance-related compensation expense and $701 thousand and $1.8 million in office occupancy expense, respectively, as compared to the same respective periods of 2009.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.6 million and $5.6 million for the three and six months ended June 30, 2010, respectively, as compared to $2.8 million and $5.5 million during the same respective periods of 2009. 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 $45.4 million and $92.9 million for the three and six months ended June 30, 2010, respectively, as compared to $43.5 million and $84.6 million during the same respective periods of 2009. The weighted average interest rate on the Company’s indebtedness for the three and six months ended June 30, 2010, including the effects of interest rate derivatives and capitalized interest, was 7.0 percent and 6.9 percent as compared to 5.5 percent and 5.4 percent for the same respective periods of 2009.

The $1.9 million and $8.3 million increases in interest expense during the three and six months ended June 30, 2010, as compared to the same periods of 2009, are primarily due to increases in the Company’s effective interest rates, partially offset by decreases in weighted average borrowings.

Other expense. Other expense for the three and six months ended June 30, 2010 was $14.7 million and $31.3 million, respectively, as compared to $36.7 million and $68.1 million for the same respective periods of 2009. The $22.0 million decrease in other expense for the three months ended June 30, 2010, is primarily attributable to a $12.4 million decrease in excess and terminated rig related costs and a $6.8 million decrease in transportation commitment charges. The $36.8 million decrease in other expense for the six months ended June 30, 2010, is primarily attributable to a $22.4 million decrease in excess and terminated rig related costs, the aforementioned $6.8 million decrease in transportation commitment charges and a $5.8 million decrease in contingency and environmental accrual adjustments. See Note Q of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information.

Income tax provision. The Company recognized an income tax provision from continuing operations of $94.7 million and $255.2 million during the three and six months ended June 30, 2010, respectively, as compared to income tax benefits of $41.7 million and $42.5 million during the same respective periods of 2009. The increase in the

PIONEER NATURAL RESOURCES COMPANY

income tax provision for the three and six months ended June 30, 2010, as compared to the same period of 2009, is primarily due to increases in income from continuing operations before income taxes, reflecting the significant increases in commodity prices and noncash derivative gains associated with mark-to-market accounting. The Company’s effective tax rates of 40 percent during the three and six months ended June 30, 2010, excluding net income attributable to noncontrolling interests, differs from the combined United States federal and state statutory rate of approximately 37 percent primarily due to foreign tax rates and statutes in foreign jurisdictions that differ from those in the U.S.

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

Income from discontinued operations, net of tax. The Company reported income from discontinued operations, net of tax of $26.2 million for each of the three and six months ended June 30, 2010 as compared to income from discontinued operations, net of tax of $2.7 million and $1.8 million for the same respective periods of 2009. See Note S of the Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interest for the three and six months ended June 30, 2010 was $21.1 million and $36.5 million, respectively, as compared to net loss attributable to noncontrolling interests of $0.5 million and net income attributable to noncontrolling interests of $3.3 million for the same respective periods of 2009. The $21.6 million and $33.2 million increases in net income attributable to noncontrolling interest is primarily due to an increase in Pioneer Southwest’s net income during the three and six months ended June 30, 2010, as compared to the three and six months ended June 30, 2009, and an increase in noncontrolling ownership in Pioneer Southwest during the fourth quarter of 2009. See Note B of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding Pioneer Southwest and the Company’s noncontrolling interest in consolidated subsidiaries’ net income.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company’s primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas assets, payment of contractual obligations including funding of EFS Midstream, 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 internally-generated cash flows and with its liquidity under its 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 Company intends to limit its capital expenditures to a level that allows the Company to deliver net cash flow from operating activities in excess of capital requirements in order to enhance and preserve financial flexibility. The Company expects its 2010 capital expenditures to be approximately $1.1 billion (excluding effects of asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS midstream investments). The Company’s capital expenditure forecast for 2010 has been updated for the expected ramp up of Eagle Ford Shale drilling activity associated with the aforementioned joint venture. During the first half of 2010, the Company’s capital costs (excluding effects of asset retirement obligations, capitalized interest and geological and geophysical administrative costs) were $528.0 million, as compared to $182.1 million during the first half of 2009.

Investing activities. Investing activities used $238.4 million of cash during the six months ended June 30, 2010, as compared to $259.8 million used during the six months ended June 30, 2009. The $21.4 million decrease in net cash used in investing activities for the six months ending June 30, 2010 is primarily due to a $293.6 million increase in proceeds from disposition of assets, partially offset by a $219.4 million increase in additions to oil and gas properties and a $52.8 million increase in additions to other assets and other property and equipment. During the six months ended June 30, 2010 and 2009, the Company’s expenditures for additions to oil and gas properties were funded by net cash provided by operating activities.

The increase in other property and equipment during the six months ended June 30, 2010 includes the purchase of five drilling rigs and deposits on seven additional rigs to be acquired during the third or fourth quarters of 2010.

PIONEER NATURAL RESOURCES COMPANY

During the first quarter of 2010, the Company formed a majority-owned subsidiary to acquire the drilling rigs and to conduct drilling activities for the Company in the Spraberry field in West Texas.

Dividends/distributions. During February 2010 and 2009, the Company’s board of directors (“the Board”) declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $4.8 million and $4.7 million of aggregate dividends during the six months ended June 30, 2010 and 2009, respectively. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company’s liquidity and capital resources at the time.

During January and April of both 2010 and 2009, the Pioneer Southwest board of directors (the “Pioneer Southwest Board”) declared quarterly distributions of $0.50 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $12.6 million and $9.4 million during the six months ended June 30, 2010 and 2009, respectively. Future distributions are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the current distribution amount based on Pioneer Southwest’s liquidity and capital resources at the time.

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, VPP obligations and midstream asset funding commitments. Additionally, the Company has entered into a hydrocarbon gathering and handling agreement with EFS Midstream. Under the terms of the agreement, the Company is obligated to deliver to EFS Midstream, for gathering, treating and transportation services over a twenty year term, production from substantially all of the properties that the Company operates in the Eagle Ford Shale play, contingent upon EFS Midstream constructing the equipment necessary to perform the services. 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 June 30, 2010, 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), (v) EFS Midstream capital funding commitments and (vi) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. Since December 31, 2009, the material changes in the Company’s contractual obligations included a commitment to pay certain minimum annual gathering, treating and transportation payments to EFS Midstream and to fund future EFS Midstream capital expenditures, a $229.6 million decrease in outstanding long-term borrowings, a $45.1 million decrease in the Company’s VPP obligations, a $404.2 million increase in the Company’s net derivative assets and a decrease of $20.6 million in the Company’s contractual drilling rig commitments.

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 June 30, 2010, these contracts represented net assets of $246.9 million, including $9.0 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 June 30, 2010. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information about the Company’s derivative instruments and market risk.

Capital resources. The Company’s primary capital resources are net cash provided by operating activities, proceeds from sales of nonstrategic assets and proceeds from financing activities (principally borrowings under the Company’s credit facility). If internal cash flows do not meet the Company’s expectations, the Company may further reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or from other sources, such as asset sales.

PIONEER NATURAL RESOURCES COMPANY

Operating activities. Net cash provided by operating activities during the six months ended June 30, 2010 was $693.2 million, as compared to $248.3 million during the same period of 2009. The increase in net cash provided by operating activities for the six months ended June 30, 2010 is primarily due to increases in oil, NGL and gas prices and working capital changes, partially offset by a decrease in commodity sales volumes.

Asset divestitures. See Note O of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and “Eagle Ford Shale Joint Venture,” above for information regarding the Company’s joint venture and Uinta/Piceance divestitures. During the first quarter of 2010, the Company also received $24.4 million from the Tunisian national oil company as contractual reimbursement of past capital costs incurred in Tunisia.

Financing activities. Net cash used in financing activities for the six months ended June 30, 2010 was $284.5 million, as compared to $27.5 million of net cash provided by financing activities during the six months ended June 30, 2009. The $312.0 million increase in cash used by financing activities during the six months ended June 30, 2010, as compared to the six months ended June 30, 2009, is primarily due to applying the proceeds from the Eagle Ford Shale joint venture transaction and Uinta/Piceance divestitures to reduce credit facility indebtedness.

On March 15, 2010, the Company redeemed for cash all of its outstanding 5.875% senior notes due 2012 for a price equal to the principal amount plus accrued and unpaid interest. Associated therewith, the Company paid $6.3 million.

As the Company pursues its strategy, it may utilize various financing sources, including, to the extent available, fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.

Liquidity. The Company’s principal sources of short-term liquidity are cash on hand and unused borrowing capacity under its credit facility. As of June 30, 2010, the Company had no outstanding borrowings under its credit facility and was in compliance with all of its debt covenants. After adjusting for $65.2 million of undrawn and outstanding letters of credit under its credit facility, the Company had approximately $1.4 billion of unused borrowing capacity as of June 30, 2010. If internal cash flows do not meet the Company’s expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or 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.

Debt ratings. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies consider many factors in determining the Company’s ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in the Company’s debt ratings could negatively impact the Company’s ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Book capitalization and current ratio. The Company’s net book capitalization at June 30, 2010 was $6.4 billion, consisting of $197.7 million of cash and cash equivalents, debt of $2.5 billion and stockholders’ equity of $4.1 billion. The Company’s net debt to net book capitalization was 37 percent and 43 percent at June 30, 2010 and December 31, 2009, respectively. The Company’s ratio of current assets to current liabilities was 1.21 to 1.00 at June 30, 2010 as compared to 1.08 to 1.00 at December 31, 2009.

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

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, 2009. 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, 2009.

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.

The following table reconciles the changes that occurred in the fair values of the Company’s open derivative contracts during the six months ending 2010:


	Derivative Contract Net Assets (Liabilities) (a)
	Commodities			Interest Rates			Total
	(in thousands)

Fair value of contracts outstanding as of December 31, 2009	$	(121,562	)	$	(17,841	)	$	(139,403	)
Changes in contract fair value (b)		407,753			33,600			441,353
Contract maturities		(47,613	)		1,564			(46,049	)

Fair value of contracts outstanding as of June 30, 2010	$	238,578		$	17,323		$	255,901

(a)	Represents the fair values of open derivative contracts subject to market risk. The Company also had $9.0 million and $17.9 million of obligations under terminated derivatives as of June 30, 2010 and December 31, 2009, respectively, for which no market risk exists.

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

Interest rate sensitivity. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” and Capital Commitments, Capital Resources and Liquidity included in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information regarding debt transactions.

The following table provides information about financial instruments to which the Company was a party as of June 30, 2010 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 June 30, 2010. 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 July 28, 2010.

PIONEER NATURAL RESOURCES COMPANY


	Six Months Ending December 31, 2010																				(Asset) Liability Fair Value at June 30, 2010
				Year Ending December 31,															Total
				2011			2012			2013			2014			Thereafter			Total
	($ in thousands)

Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	—		$	480,000		$	—		$	2,089,985		$	2,569,985	$	2,677,572
Weighted average interest rate		6.05	%		6.05	%		6.05	%		5.53	%		5.51	%		7.07	%
Variable rate principal maturities:
Pioneer Natural Resources credit facility	$	—		$	—		$	—											$	—	$	—
Weighted average interest rate		2.46	%		2.82	%		3.66	%
Pioneer Southwest credit facility	$	—		$	—		$	—		$	72,000								$	72,000	$	67,990
Weighted average interest rate		1.33	%		1.69	%		2.54	%		3.41	%
Interest Rate Swaps:
Credit facility:
Notional debt amount (b)	$	189,000		$	23,625																$	(3,254	)
Fixed rate payable (%)		3.00	%		3.00	%
Variable rate receivable (%)		0.46	%		0.82	%
Notional debt amount (b)	$	470,000		$	470,000		$	470,000		$	470,000		$	470,000		$	470,000				$	20,577
Fixed rate receivable (%)		2.92	%		2.92	%		2.92	%		2.92	%		2.92	%		2.92	%
Variable rate payable (%)		0.46	%		0.82	%		1.66	%		2.53	%		2.97	%		3.05	%

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

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

Commodity derivative instruments and price sensitivity. The following tables provide information about the Company’s oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of June 30, 2010. Although mitigated by the Company’s derivative activities, declines in commodity prices would reduce the Company’s revenues and internally-generated cash flows.

The Company manages commodity price risk with derivative contracts, such as swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum (“floor”) and maximum (“ceiling”) prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company’s realized price will exceed the variable market prices by the long put-to-short put price differential.

See Note 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.

PIONEER NATURAL RESOURCES COMPANY


	Six Months Ending December 31, 2010														Asset (Liability) Fair Value at June 30, 2010
				Year Ending December 31,
				2011			2012			2013			2014
															(in thousands)

Oil Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts		2,500			750			3,000			3,000			—	$	3,678
Weighted average fixed price per Bbl	$	93.34		$	77.25		$	79.32		$	81.02		$	—
Collar contracts		—			2,000			—			—			—	$	26,956
Weighted average ceiling price per Bbl	$	—		$	170.00		$	—		$	—		$	—
Weighted average floor price per Bbl	$	—		$	115.00		$	—		$	—		$	—
Collar contracts with short puts		30,125			37,000			28,000			1,250			—	$	27,519
Weighted average ceiling price per Bbl	$	85.04		$	99.22		$	120.59		$	111.50		$	—
Weighted average floor price per Bbl	$	68.37		$	73.92		$	80.54		$	83.00		$	—
Weighted average short put price per Bbl	$	55.23		$	59.41		$	65.00		$	68.00		$	—
Average forward NYMEX oil prices (b)	$	80.02		$	82.94		$	84.44		$	85.21

NGL Derivatives:
Average daily notional Bbl volumes:
Swap contracts		1,250			750			750			—			—	$	188
Weighted average fixed price per Bbl	$	47.38		$	34.65		$	35.03		$	—		$	—
Collar contracts		2,000			1,000			—			—			—	$	2,392
Weighted average ceiling price per Bbl	$	49.98		$	50.93		$	—		$	—		$	—
Weighted average floor price per Bbl	$	41.58		$	42.21		$	—		$	—		$	—
Collar contracts with short puts		2,000			—			—			—			—	$	3,202
Weighted average ceiling price per Bbl	$	58.92		$	—		$	—		$	—		$	—
Weighted average floor price per Bbl	$	47.64		$	—		$	—		$	—		$	—
Weighted average short put price per Bbl	$	38.71		$	—		$	—		$	—		$	—
Average forward Mont Belvieu NGL prices (c)	$	41.72		$	40.75		$	39.98

Gas Derivatives (a):
Average daily notional MMBtu volumes (c):
Swap contracts		167,500			97,500			70,000			67,500			30,000	$	90,733
Weighted average fixed price per MMBtu	$	6.26		$	6.32		$	5.97		$	6.11		$	6.07
Collar contracts		40,000			—			40,000			—			—	$	8,604
Weighted average ceiling price per MMBtu	$	7.19		$	—		$	6.96		$	—		$	—
Weighted average floor price per MMBtu	$	5.75		$	—		$	5.00		$	—		$	—
Collar contracts with short puts		95,000			200,000			190,000			45,000			50,000	$	107,213
Weighted average ceiling price per MMBtu	$	7.94		$	8.55		$	7.96		$	7.49		$	8.08
Weighted average floor price per MMBtu	$	6.00		$	6.32		$	6.12		$	6.00		$	6.00
Weighted average short put price per MMBtu	$	5.00		$	4.88		$	4.55		$	4.50		$	4.50
Average forward NYMEX gas prices (b)	$	4.76		$	5.20		$	5.53		$	5.72		$	5.92
Basis swap contracts		251,739			120,000			42,500			12,500			—	$	(31,907	)
Weighted average fixed price per MMBtu	$	(0.67	)	$	(0.62	)	$	(0.46	)	$	(0.63	)	$	—
Average forward basis differential prices (d)	$	(0.37	)	$	(0.32	)	$	(0.26	)	$	(0.38	)

(a)

Subsequent to June 30, 2010, the Company (i) entered into additional crude collar contracts with short puts for 5,000 Bbls per day of the Company’s 2013 production with a ceiling price of $116.30 per Bbl, a floor price of $80.00 per Bbl and a short put price of $65.00 per Bbl and (ii) unwound crude collar contracts with short puts for 2,750 Bbls per day of the Company’s 2010 production with a ceiling price of $98.54 per Bbl, a floor price of $75.00 per Bbl and a short put price of $60.00 per Bbl. The Company also entered into additional gas swap contracts for 20,000 MMBtu, 30,000 MMBtu and 20,000 MMBtu, respectively, of the Company’s 2011, 2012 and 2014 production at an average price of $5.20 per MMBtu, $5.53 per MMBtu and $6.03 per MMBtu, respectively.

(b)	The average forward NYMEX oil and gas prices are based on July 26, 2010 market quotes.

(c)	Forward Mont Belvieu NGL prices are derived from active-market NGL component price quotes.

(d)	The average forward basis differential prices are based on July 26, 2010 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

PIONEER NATURAL RESOURCES COMPANY

Item 4.

Controls and Procedures

Evaluation of disclosure controls and procedures. The Company’s management, under the supervision and with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the 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, including that such information is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, 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.

PIONEER NATURAL RESOURCES COMPANY

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

The Company is party to the legal proceeding that is 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.

Exploration and development drilling may not result in commercially productive reserves.

Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and these operations may be curtailed, delayed or canceled, or become costlier as a result of a variety of factors, including:

•

unexpected drilling conditions;

•

unexpected pressure or irregularities in formations;

•

equipment failures or accidents;

•

adverse weather conditions;

•

restricted access to land for drilling or laying pipelines; and

•

access to, and the cost and availability of, the equipment, services and personnel required to complete the Company’s drilling, completion and operating activities.

The Company’s future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on the Company’s future results of operations and financial condition. While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment expense in 2010. Increased levels of drilling activity in the oil and gas industry in recent periods have led to increased costs of some drilling equipment, materials and supplies. Although the Company has experienced some decrease in these costs over the past year, such decreases could be short-lived. A return to the trends of increasing demand and costs in the future may affect the Company’s profitability, cash flow and ability to complete development projects as scheduled and on budget.

The Company’s expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

The Company has identified drilling locations and prospects for future drilling opportunities, including development, exploratory and infill drilling and enhanced recovery activities. These drilling locations and prospects represent a significant part of the Company’s future drilling plans. The Company’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services and personnel, and drilling results. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or

PIONEER NATURAL RESOURCES COMPANY

meet the Company’s expectations for success. As such, the Company’s actual drilling and enhanced recovery activities may materially differ from the Company’s current expectations, which could have a significant adverse effect on the Company’s proved reserves, financial condition and results of operations.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Company’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Commodity Futures Trading Commission (“CFTC”) has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may require the Company to comply with margin requirements and with certain clearing and trade-execution requirements, although the application of those provisions to the Company is uncertain at this time. The financial reform legislation may also require the counterparties to the Company’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce the Company’s ability to monetize or restructure its existing derivative contracts, and increase the Company’s exposure to less creditworthy counterparties. If the Company reduces its use of derivatives as a result of the legislation and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Company’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company, its financial condition, and its results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into rock formations to fracture the surrounding rock and to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions and has not been subject to federal regulation. The U.S. Environmental Protection Agency, or the EPA, has commenced a study of the potential environmental effects of hydraulic fracturing practices. A committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before the United States Congress to provide for federal regulation of hydraulic fracturing and to require disclosure to the government or the public of the chemicals used in the fracturing process. In addition, some states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances and that could give authority to regulatory agencies other than oil and gas commissions (such as environmental or water commissions) to regulate hydraulic fracturing. Some legislators and other persons have asserted that chemicals used in the fracturing process could or do adversely affect drinking water supplies. Some of the proposed legislation could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. These laws and regulations, if adopted, could result in additional permitting requirements at the state or federal level that could lead to permitting delays and increases in costs. These laws and regulations, if adopted, could also make it more difficult or costly for us to perform hydraulic fracturing and could increase the Company’s costs of compliance and doing business. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is able to produce from its reserves.

Legislation and regulatory initiatives relating to offshore operations could result in increased costs and additional operating restrictions.

The Oil Pollution Act of 1990 (the “OPA”) and regulations adopted pursuant to the OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States. The OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict, joint and several liability for

PIONEER NATURAL RESOURCES COMPANY

all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The State of Alaska has also adopted laws and regulations relating to offshore operations in its waters. The United States Congress is currently considering a variety of amendments to the OPA in response to the recent Deepwater Horizon incident in the Gulf of Mexico, including an increase in the minimum level of financial responsibility, elimination of liability limitations, and enhancements to safety and spill-response requirements. Additional state regulation in these areas is also possible. Any new requirements would likely increase the cost of operations for the Company’s offshore activities, which could have an adverse effect on the Company’s results of operations. If the Company is unable to satisfy new legislative and regulatory requirements, it may be required to curtail operations, sell its offshore properties or operations, or enter into partnerships with other companies that can meet the new requirements, which may have an adverse effect on the value of the Company’s offshore assets and the results of its operations. The Company cannot predict at this time whether the OPA will be amended or new state regulations adopted, or what the substance of any such amendment or regulations will be. In addition, the Company’s costs could also increase for its onshore operations due to changes in standard industry practices in anticipation of, or in reaction to, any new offshore 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 June 30, 2010:


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)
April 2010	3,197	$	64.96	—
May 2010	98	$	58.16	—
June 2010	112	$	65.92	—

Total	3,407	$	64.80	—	$	355,789,018

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

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

PIONEER NATURAL RESOURCES COMPANY

Item 6.

Exhibits

Exhibits


Exhibit Number		Description
10.1(a)	—	Form of Restricted Stock Unit Agreement for Non-Employee Directors to be used in connection with annual equity awards 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.

101.INS(b)	—	XBRL Instance Document.

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

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

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

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

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

(a)	Filed herewith.

(b)	Furnished herewith.

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: July 30, 2010	By:	/s/ Richard P. Dealy
		Richard P. Dealy
		Executive Vice President and Chief
		Financial Officer

Date: July 30, 2010	By:	/s/ Frank W. Hall
		Frank W. Hall
		Vice President and Chief
		Accounting Officer

PIONEER NATURAL RESOURCES COMPANY

Exhibit Index


Exhibit Number		Description
10.1(a)	—	Form of Restricted Stock Unit Agreement for Non-Employee Directors to be used in connection with annual equity awards 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.

101.INS(b)	—	XBRL Instance Document.

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

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

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

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

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

(a)	Filed herewith.

(b)	Furnished herewith.