Edgar Filing: PIONEER NATURAL RESOURCES CO

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Accelerated filer

Non-accelerated filer

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Smaller reporting company

PXD-2012.06.30

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________



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

For the quarterly period ended June 30, 2012



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

For the transition period from to

Commission File Number: 1-13245

______________________________

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

______________________________



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

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

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

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

______________________________

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

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

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

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

Yes ¨ No ý

Number of shares of Common Stock outstanding as of August 1, 2012 123,035,765

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

TABLE OF CONTENTS



		Page
Cautionary Statement Concerning Forward-Looking Statements		3

Definitions of Certain Terms and Conventions Used Herein		4

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	5

	Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011	7

	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2012 and 2011	8

	Consolidated Statement of Equity for the six months ended June 30, 2012	9

	Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	10

	Notes to Consolidated Financial Statements	11

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41

Item 4.	Controls and Procedures	45

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 4.	Mine Safety Disclosures	46

Item 6.	Exhibits	47

Signatures		48

Exhibit Index		49

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

Cautionary Statement Concerning Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (the "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "forecasts," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate" or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company ("Pioneer" or the "Company") are intended to identify forward-looking statements. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control.

These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements (including joint venture agreements) with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services 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 impacts of climate change, the risks associated with the ownership and operation of an industrial sand mining business, international operations and acts of war or terrorism. These and other risks are described in the Company's Annual Report on Form 10-K, this and other Quarterly Reports on Form 10-Q and other filings with the United States Securities and Exchange Commission (the "SEC"). In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Part I, Item 1. Business — Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors," "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Company's Annual Report on Form 10-K for the year ended December 31, 2011 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

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


•	"BBL" means a standard barrel containing 42 United States gallons.


•	"BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one BBL of oil or natural gas liquid.


•	"BOEPD" means BOE per day.


•	"BTU" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.


•	"Conway" means the daily average natural gas liquids components as priced in Oil Price Information Service ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.


•	"DD&A" means depletion, depreciation and amortization.


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


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


•	"MCF" means one thousand cubic feet and is a measure of gas volume.


•	"MMBTU" means one million BTUs.


•	"MMBTUPD" means MMBTU per day.


•	"Mont Belvieu" means the daily average natural gas liquids components as priced in OPIS in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.


•	"NGL" means natural gas liquid.


•	"NYMEX" means the New York Mercantile Exchange.


•	"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.


•	"Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.

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

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

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

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

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

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


•	"U.S." means United States.

•

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


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

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)



	June 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	317,769		$	537,484
Accounts receivable:
Trade, net of allowance for doubtful accounts of $706 and $806 as of June 30, 2012 and December 31, 2011, respectively	250,192			275,991
Due from affiliates	2,301			7,822
Income taxes receivable	2,417			3
Inventories	277,539			241,609
Prepaid expenses	28,213			14,263
Discontinued operations held for sale	70,177			73,349
Other current assets:
Derivatives	308,762			238,835
Other	26,663			12,936
Total current assets	1,284,033			1,402,292
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	12,964,291			12,013,805
Unproved properties	296,827			235,527
Accumulated depletion, depreciation and amortization	(4,013,770		)	(3,648,465		)
Total property, plant and equipment	9,247,348			8,600,867
Goodwill	298,142			298,142
Other property and equipment, net	1,134,532			573,075
Other assets:
Investment in unconsolidated affiliate	184,374			169,532
Derivatives	260,929			243,240
Other, net of allowance for doubtful accounts of $655 and $340 as of June 30, 2012 and December 31, 2011, respectively	160,376			160,008
	$	12,569,734		$	11,447,156

The financial information included as of June 30, 2012 has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in thousands, except share data)



	June 30, 2012			December 31, 2011
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	769,611		$	647,455
Due to affiliates	39,547			68,756
Interest payable	57,329			57,240
Income taxes payable	1,881			9,788
Deferred income taxes	89,656			57,713
Discontinued operations held for sale	77,310			75,901
Other current liabilities:
Derivatives	30,650			74,415
Deferred revenue	21,150			42,069
Other	41,857			36,174
Total current liabilities	1,128,991			1,069,511
Long-term debt	3,285,497			2,528,905
Derivatives	17,785			33,561
Deferred income taxes	2,154,301			1,942,446
Other liabilities	226,184			221,595
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 134,763,095 and 133,121,092 shares issued at June 30, 2012 and December 31, 2011, respectively	1,348			1,331
Additional paid-in capital	3,611,799			3,613,808
Treasury stock at cost: 11,727,359 and 11,264,936 at June 30, 2012 and December 31, 2011, respectively	(511,628		)	(458,281		)
Retained earnings	2,473,504			2,335,066
Accumulated other comprehensive loss - net deferred hedge losses, net of tax	—			(3,130		)
Total equity attributable to common stockholders	5,575,023			5,488,794
Noncontrolling interests in consolidating subsidiaries	181,953			162,344
Total equity	5,756,976			5,651,138
Commitments and contingencies
	$	12,569,734		$	11,447,156

The financial information included as of June 30, 2012 has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues and other income:
Oil and gas	$	641,737		$	562,412		$	1,360,693		$	1,038,140
Interest and other	6,043			13,594			34,491			42,067
Derivative gains (losses), net	275,812			229,478			367,562			(14,954		)
Gain (loss) on disposition of assets, net	1,140			(296		)	44,736			(2,487		)
	924,732			805,188			1,807,482			1,062,766
Costs and expenses:
Oil and gas production	156,838			101,741			295,159			200,576
Production and ad valorem taxes	44,495			35,864			90,291			69,160
Depletion, depreciation and amortization	200,921			135,511			382,339			258,345
Impairment of oil and gas properties	444,880			—			444,880			—
Exploration and abandonments	37,178			19,732			90,465			37,216
General and administrative	54,957			44,339			118,024			88,250
Accretion of discount on asset retirement obligations	2,444			2,048			4,874			4,092
Interest	49,008			44,995			95,866			90,222
Hurricane activity, net	—			(2		)	—			69
Other	30,651			12,053			54,258			29,914
	1,021,372			396,281			1,576,156			777,844
Income (loss) from continuing operations before income taxes	(96,640		)	408,907			231,326			284,922
Income tax benefit (provision)	45,086			(140,182		)	(72,617		)	(92,275		)
Income (loss) from continuing operations	(51,554		)	268,725			158,709			192,647
Income (loss) from discontinued operations, net of tax	12,017			(3,025		)	22,712			416,857
Net income (loss)	(39,537		)	265,700			181,421			609,504
Net income attributable to noncontrolling interests	(30,855		)	(20,123		)	(37,194		)	(15,333		)
Net income (loss) attributable to common stockholders	$	(70,392	)	$	245,577		$	144,227		$	594,171

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.67	)	$	2.10		$	0.98		$	1.50
Income (loss) from discontinued operations attributable to common stockholders	0.10			(0.03		)	0.18			3.53
Net income (loss) attributable to common stockholders	$	(0.57	)	$	2.07		$	1.16		$	5.03
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.67	)	$	2.06		$	0.95		$	1.46
Income (loss) from discontinued operations attributable to common stockholders	0.10			(0.03		)	0.18			3.44
Net income (loss) attributable to common stockholders	$	(0.57	)	$	2.03		$	1.13		$	4.90
Weighted average shares outstanding:
Basic	123,028			116,213			122,754			116,042
Diluted	123,028			118,592			125,772			118,986
Dividends declared per share	$	—		$	—		$	0.04		$	0.04

Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	(82,409	)	$	248,602		$	121,515		$	177,314
Income (loss) from discontinued operations, net of tax	12,017			(3,025		)	22,712			416,857
Net income (loss)	$	(70,392	)	$	245,577		$	144,227		$	594,171

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income (loss)	$	(39,537	)	$	265,700		$	181,421		$	609,504
Other comprehensive activity:
Net hedge (gains) losses included in continuing operations	2,347			(8,139		)	4,855			(16,195		)
Income tax (benefit) provision	(797		)	4,138			(1,725		)	4,886
Other comprehensive activity	1,550			(4,001		)	3,130			(11,309		)
Comprehensive income (loss)	(37,987		)	261,699			184,551			598,195
Comprehensive (income) loss attributable to the noncontrolling interests	(30,855		)	(16,698		)	(37,194		)	(8,522		)
Comprehensive income (loss) attributable to common stockholders	$	(68,842	)	$	245,001		$	147,357		$	589,673

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(in thousands, except dividends per share)

(Unaudited)



			Equity Attributable To Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Equity
Balance as of December 31, 2011	121,856		$	1,331	$	3,613,808		$	(458,281	)	$	2,335,066		$	(3,130	)	$	162,344		$	5,651,138
Dividends declared ($0.04 per share)	—		—		—			—			(4,982		)	—			—			(4,982		)
Exercise of long-term incentive plan stock options	65		—		(965		)	2,780			(807		)	—			—			1,008
Treasury stock purchases	(527	)	—		—			(56,129		)	—			—			(188		)	(56,317		)
Conversion of 2.875% senior convertible notes	—		—		(2		)	2			—			—			—			—
Tax benefit related to stock-based compensation	—		—		17,545			—			—			—			—			17,545
Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering	—		—		(49,072		)	—			—			—			—			(49,072		)
Compensation costs:
Vested compensation awards, net	1,642		17		(17		)	—			—			—			—			—
Compensation costs included in net income	—		—		30,502			—			—			—			559			31,061
Cash distributions to noncontrolling interests	—		—		—			—			—			—			(17,956		)	(17,956		)
Net income	—		—		—			—			144,227			—			37,194			181,421
Other comprehensive activity:
Deferred hedging activity, net of tax:
Net hedge losses included in continuing operations	—		—		—			—			—			3,130			—			3,130
Balance as of June 30, 2012	123,036		$	1,348	$	3,611,799		$	(511,628	)	$	2,473,504		$	—		$	181,953		$	5,756,976

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)



	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	181,421		$	609,504
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	382,339			258,345
Impairment of oil and gas properties	444,880			—
Exploration expenses, including dry holes	39,730			4,275
Deferred income taxes	57,291			87,337
(Gain) loss on disposition of assets, net	(44,736		)	2,487
Accretion of discount on asset retirement obligations	4,874			4,092
Discontinued operations	3,597			(390,868		)
Interest expense	18,152			15,432
Derivative related activity	(144,000		)	56,380
Amortization of stock-based compensation	30,970			21,155
Amortization of deferred revenue	(20,919		)	(22,290		)
Other noncash items	(7,513		)	(9,207		)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	33,881			(23,605		)
Income taxes receivable	(1,452		)	27,226
Inventories	(33,318		)	(74,136		)
Prepaid expenses	(13,425		)	(9,990		)
Other current assets	(8,846		)	8,772
Accounts payable	30,580			6,201
Interest payable	82			(1,642		)
Income taxes payable	(7,907		)	(11,485		)
Other current liabilities	(20,271		)	6,471
Net cash provided by operating activities	925,410			564,454
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	62,945			813,520
Payments for acquisition, net of cash acquired	(295,974		)	—
Investment in unconsolidated subsidiary	—			(82,857		)
Additions to oil and gas properties	(1,424,807		)	(757,148		)
Additions to other assets and other property and equipment, net	(164,230		)	(215,367		)
Net cash used in investing activities	(1,822,066		)	(241,852		)
Cash flows from financing activities:
Borrowings under long-term debt	1,339,093			72,610
Principal payments on long-term debt	(596,000		)	(115,810		)
Distributions to noncontrolling interests	(17,956		)	(13,366		)
Payments of other liabilities	(744		)	(305		)
Exercise of long-term incentive plan stock options	1,008			362
Purchases of treasury stock	(56,317		)	(39,218		)
Excess tax benefits from share-based payment arrangements	17,545			27,937
Payment of financing fees	(4,660		)	(8,739		)
Dividends paid	(5,028		)	(4,812		)
Net cash provided by (used in) financing activities	676,941			(81,341		)
Net increase (decrease) in cash and cash equivalents	(219,715		)	241,261
Cash and cash equivalents, beginning of period	537,484			111,160
Cash and cash equivalents, end of period	$	317,769		$	352,421

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

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

Table of Contents

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE A. Organization and Nature of Operations

Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with continuing operations in the United States.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2012 and for the three and six months ended June 30, 2012 and 2011 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed or omitted in this Report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

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

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

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

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at their estimated fair values. See Note E for further information regarding the fair value of the Company's derivatives. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing derivative hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income or loss ("AOCI - Hedging"), in the equity section of the Company's consolidated balance sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. As of June 30, 2012, all of the hedge gains or losses that were previously deferred in AOCI - Hedging have been transferred to earnings. The Company now recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and its counterparties are generally based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

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

Impairment of assets. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate that their carrying values may not be fully recoverable. If the carrying value of long-lived assets is determined to be impaired, it is reduced to its estimated fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. See Note O for additional information about the Company's impairment charge for the three and six months ended June 30, 2012, and future impairment risk.

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 2011, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

New accounting pronouncement. In September 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-08 Intangibles - Goodwill and Other (Topic 350) ("ASU 2011-08"). ASU 2011-08 amended FASB ASC Topic 350 to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU 2011-08 became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 did not impact the carrying value of the Company's goodwill. See Note O for information regarding the Company's impairment assessments.

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of Pioneer acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC (the "Acquisition"). During April 2012, the name of Oglebay Norton Industrial Sands, LLC was changed to Premier Silica LLC ("Premier Silica"). Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. Premier Silica's business is supportive to the Company's vertical integration strategy of controlling major cost components of the Company's drilling and production activities in the areas where the Company has a significant inventory of drilling locations and a significant number of producing wells. The aggregate purchase price of Premier Silica was $296.0 million, including estimated closing adjustments, and was funded from available cash and borrowings under the Company's credit facility.

The Acquisition was accounted for as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The Company's assessment of the fair values of Premier Silica's assets and liabilities is preliminary, and may be adjusted as a result of normal closing adjustments. The fair value of the tangible assets acquired totaled $468.9 million and were primarily comprised of proved sand reserves, probable sand reserves and mine processing facilities and equipment of $454.5 million. The fair value of liabilities assumed totaled $172.9 million and were primarily comprised of deferred income taxes of $150.8 million.

The Company recognized $1.2 million and $2.2 million of acquisition-related costs that were expensed in the three and six months ended June 30, 2012. These costs are included in other expense in the accompanying consolidated statements of operations for the three and six months ended June 30, 2012.

Divestitures Recorded as Discontinued Operations

South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest of its net assets in South Africa ("Pioneer South Africa"). In March 2012, the Company agreed to sell its net assets in Pioneer

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(Unaudited)

South Africa to an unaffiliated third party, using a January 1, 2012 effective date, for net cash proceeds of $52.0 million, before normal closing adjustments. The sale is expected to close in the third quarter of 2012. The Company has classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the Company's accompanying consolidated balance sheets as of June 30, 2012 and December 31, 2011 and (ii) Pioneer South Africa's results of operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations (representing a recasting of Pioneer South Africa results of operations for the three and six months ended June 30, 2011, which were originally classified as continuing operations).

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

Gulf of Mexico. During the six months ended June 30, 2011, the Bureau of Ocean Energy Management, Regulation, and Enforcement paid the Company $2.0 million of interest on excess royalty payments associated with properties that were sold by the Company during 2006. Accordingly, the interest income is classified as income from discontinued operations.

The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2012 and 2011:



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Revenues and other income:
Oil and gas	$	20,172		$	21,520		$	39,765		$	65,051
Interest and other	—			35			20			4,971
Gain (loss) on disposition of assets, net	—			(4,574		)	(23		)	645,298
	20,172			16,981			39,762			715,320
Costs and expenses:
Oil and gas production	1,345			714			2,135			3,937
Depletion, depreciation and amortization (a)	—			13,544			—			27,236
Exploration and abandonments	1			1,875			86			4,587
General and administrative	12			2,582			1,132			9,397
Accretion of discount on asset retirement obligations (a)	652			610			1,304			1,302
Interest	—			773			(75		)	773
Other	1,581			3,012			1,185			4,214
	3,591			23,110			5,767			51,446
Income (loss) from discontinued operations before income taxes	16,581			(6,129		)	33,995			663,874
Current tax provision	(3,334		)	(12,745		)	(8,739		)	(26,638		)
Deferred tax (provision) benefit (a)	(1,230		)	15,849			(2,544		)	(220,379		)
Income (loss) from discontinued operations	$	12,017		$	(3,025	)	$	22,712		$	416,857

____________________


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

Divestitures Recorded in Continuing Operations

The Company's net gain/loss on disposition of assets for the three and six months ended June 30, 2012 of $1.1 million and $44.7 million, respectively, was primarily associated with the sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field during the three months ended March 31, 2012 to unaffiliated third parties for proceeds of $54.7

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June 30, 2012

(Unaudited)

million, including normal closing adjustments. Associated therewith, the Company recorded a pretax gain of $42.6 million.

During the three and six months ended June 30, 2011, the Company's net loss on disposition of assets was primarily associated with the sales of excess materials and supplies inventory.

NOTE D. Exploratory Costs

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

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



	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
	(in thousands)
Beginning capitalized exploratory costs	$	138,002		$	107,596
Additions to exploratory costs pending the determination of proved reserves	205,938			380,832
Reclassification due to determination of proved reserves	(148,805		)	(266,415		)
Exploratory well costs charged to exploration expense	(1,408		)	(28,286		)
Ending capitalized exploratory costs	$	193,727		$	193,727

As of June 30, 2012 and December 31, 2011, the Company had no exploratory projects for which exploratory costs have been capitalized for a period greater than one year from the date drilling was completed.

NOTE E. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:


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


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


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

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

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June 30, 2012

(Unaudited)

The following table presents the Company's assets and liabilities that are measured at fair value as of June 30, 2012:



	Fair Value Measurement at the End of the Reporting Period Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2012
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	251	$	168		$	—	$	419
Commodity derivatives	—		569,691			—		569,691
Deferred compensation plan assets	44,191		—			—		44,191
Total assets	$	44,442	$	569,859		$	—	$	614,301
Liabilities:
Commodity derivatives	$	—	$	(13,742	)	$	—	$	(13,742	)
Interest rate derivatives	—		(34,693		)	—		(34,693		)
Total liabilities	$	—	$	(48,435	)	$	—	$	(48,435	)
Total recurring fair value measurements	$	44,442	$	521,424		$	—	$	565,866

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities that are both actively traded and not actively traded on major exchanges. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on directly observable prices on major exchanges. As of June 30, 2012, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain trading securities that are not actively traded on major exchanges were classified as Level 2 inputs.

Interest rate derivatives. The Company's interest rate derivative liabilities as of June 30, 2012 represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of June 30, 2012 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("NGL"), gas and diesel swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company's oil, gas, NGL and diesel swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.

The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs which include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and three-way collar contracts, which is based on active and independent market-quoted volatility factors.

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(Unaudited)

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of June 30, 2012 and December 31, 2011 are as follows:



	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,285,497	$	3,934,014	$	2,528,905	$	3,105,585

Long term debt includes the Company's credit facility, the Pioneer Southwest credit facility and the Company's senior notes. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

Credit facilities. The fair values of the Company's and Pioneer Southwest's credit facilities are calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rate (in the case of the Company's credit facility) or LIBOR (in the case of the Pioneer Southwest credit facility) yield curves and (iii) the applicable credit-adjustments.

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

The Company has other financial instruments consisting primarily of cash equivalents, short-term receivables, accounts payable trade and other liabilities that approximate fair value due to the nature of the instrument and relatively short maturities. Non-financial assets and liabilities initially measured at fair value include certain assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.

NOTE F. Income Taxes

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Current	$	(3,494	)	$	(2,540	)	$	(15,326	)	$	(4,938	)
Deferred	48,580			(137,642		)	(57,291		)	(87,337		)
Income tax benefit (provision)	$	45,086		$	(140,182	)	$	(72,617	)	$	(92,275	)
Effective tax rate (a)	35		%	36		%	37		%	34		%

____________________


(a)	Represents the income tax benefit or provision divided by the income or loss from continuing operations before income taxes excluding the effect of net income attributable to noncontrolling interests.

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 2006. As of June 30, 2012, 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.

NOTE G. Long-term Debt

The Company's long-term debt consists of senior notes and revolving credit facilities, including the effects of net deferred fair value hedge losses and issuance discounts. As of June 30, 2012, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Credit facility. During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that matures in March 2016, unless extended in

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accordance with the terms of the Credit Facility. As of June 30, 2012, the Company had $110.0 million of outstanding borrowings under the Credit Facility and $40.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.1 billion of unused borrowing capacity under the Credit Facility. During July 2012, $39.0 million of the undrawn letters of credit were canceled.

Pioneer Southwest credit facility. During March 2012, Pioneer entered into an Amended and Restated 5-Year Revolving Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility provides for aggregate loan commitments of $300 million. As of June 30, 2012, Pioneer Southwest had $69.0 million of outstanding borrowings and $231.0 million of unused borrowing capacity under the Pioneer Southwest Credit Facility.

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

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

Convertible senior notes. As of June 30, 2012 and December 31, 2011, the Company had $479.9 million of 2.875% Convertible Senior Notes outstanding. The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the 2.875% Convertible Senior Notes were issued.

The Company's stock prices during March 2012 met the average price threshold that caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the following three months ended June 30, 2012. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $22 thousand principal amount of the notes for conversion. The Company paid certain of the tendering holders a total of $7 thousand cash and issued to the tendering holders 50 shares of the Company's common stock in May 2012 in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement. In August 2012, the Company anticipates paying the other tendering holders $15 thousand cash for the remaining notes tendered and issuing shares to be determined based upon the conversion calculation in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

The Company's stock prices during March 2011 met the average price threshold that caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the following three month period. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During the third quarter of 2011, the Company paid the tendering holders a total of $71 thousand cash, including accrued interest, and issued to the tendering holders 340 shares of the Company's common stock in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

During June 2012, the Company's stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders for the three months ended September 30, 2012. The Company's 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock price or other conditions. If the 2.875% Convertible Senior Notes had qualified for and been converted as of June 30, 2012, the note holders would have received $479.9 million of cash and approximately 1.8 million shares of the Company's common stock, which was valued at $161.0 million at June 30, 2012.

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

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NOTE H. Derivative Financial Instruments

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

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices.

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



	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013		2014
Collar contracts with short puts:
Volume (BBL) (a)	51,610			67,290		40,000
Average price per BBL:
Ceiling	$	118.73		$	120.61	$	122.77
Floor	$	84.80		$	88.88	$	91.50
Short put	$	69.12		$	71.72	$	74.88
Collar contracts:
Volume (BBL)	2,000			—		—
Average price per BBL:
Ceiling	$	127.00		$	—	$	—
Floor	$	90.00		$	—	$	—
Swap contracts:
Volume (BBL) (a)	3,000			3,000		—
Average price per BBL	$	79.32		$	81.02	$	—
Rollfactor swap contracts:
Volume (BBL)	—			6,000		—
NYMEX roll price (b)	$	—		$	0.43	$	—
Basis swap contracts:
Index swap volume (BBL)	20,000			—		—
Average price per BBL (c)	$	(1.15	)	$	—	$	—

____________________


(a)	Subsequent to June 30, 2012, the Company entered into additional NYMEX (i) swap contracts for 8,000 BBLs per day of August 2012 through December 2012 production with a price of $93.09 per BBL and (ii) collar contracts with short puts for 5,000 BBLs per day of 2014 production with a ceiling price of $102.22 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL.


(b)	Represents swaps that fix the difference between (i) each day's price per BBL of WTI for the first nearby month less (ii) the price per BBL of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per BBL of WTI for the first nearby month less (iv) the price per BBL of WTI for the third nearby NYMEX month, multiplied by .3333.


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

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL product component prices. As of June

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30, 2012, the Company had NGL swap derivatives for 750 BBLs per day of July 2012 through December 2012 NGL sales at an average price of $35.03 per BBL and NGL collar contracts with short put derivatives for 3,000 BBLs per day of July 2012 through December 2012 sales with a ceiling price of $79.99 per BBL, a floor price of $67.70 per BBL and a short put price of $55.76 per BBL. Subsequent to June 30, 2012, the Company entered into additional NGL swap contracts for 2,000 BBLs per day of August 2012 through December 2012 production priced at $80.06 per BBL.

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

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



	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013			2014 (a)			2015 (a)
Collar contracts with short puts:
Volume (MMBTU)	—			—			30,000			135,000
Price per MMBTU:
Ceiling	$	—		$	—		$	7.66		$	5.44
Floor	$	—		$	—		$	5.67		$	4.22
Short put	$	—		$	—		$	4.33		$	3.22
Collar contracts:
Volume (MMBTU)	65,000			150,000			80,000			50,000
Price per MMBTU:
Ceiling	$	6.60		$	6.25		$	6.39		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00
Swap contracts:
Volume (MMBTU)	275,000			112,500			10,000			—
Price per MMBTU	$	4.97		$	5.62		$	6.18		$	—
Basis swap contracts:
Volume (MMBTU)	136,000			142,500			140,000			—
Price per MMBTU	$	(0.34	)	$	(0.22	)	$	(0.21	)	$	—

____________________

(a)

Subsequent to June 30, 2012, the Company (i) terminated its 2014 gas derivative positions, including basis swaps, for net proceeds of $47.1 million, (ii) terminated its 2015 collar contracts for proceeds of $19.4 million and (iii) terminated 2015 collar contracts with short puts for 30,000 MMBTU per day with a ceiling price of $7.11 per MMBTU, a floor price of $5.00 per MMBTU and a short put price of $4.00 per MMBTU for proceeds of $4.7 million.

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

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



	Six Months Ending December 31,
	2012
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	26,739
Price differential ($/MMBTU)	$	0.25
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBTU):
Basis swap contracts:
Short index swap volume	3,343
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12
Long index swap volume	$	(3,343	)
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)

Diesel derivative activities. The Company utilizes diesel derivative swap contracts to mitigate its fuel price risk associated with diesel used in Company-owned drilling rigs and fracture stimulation fleet equipment. As of June 30, 2012, the Company has diesel derivative swap contracts for 250 BBLs per day for 2013 at an average per BBL fixed price of $111.30. The diesel derivative contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment.

Interest rates. As of June 30, 2012, the Company was a party to interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.06 percent, for a 10-year period ending in August 2022, on a notional amount of $200 million. These derivative contracts mature and settle by their terms during August 2012. Subsequent to June 30, 2012, the Company terminated its 2012 interest rate swap positions at a cost of $28.4 million.

During April 2012, the Company entered into interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21 percent, for a 10-year period ending in December 2025, on a notional amount of $250 million. These derivative contracts mature and settle by their terms during December 2015.

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

Fair Value of Derivative Instruments as of June 30, 2012

Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet

Location

Fair

Value

Balance Sheet

Location

Fair

Value

(in thousands)

Derivatives not designated as hedging instruments

Commodity price derivatives

Derivatives - current

318,503

Derivatives - current

17,108

Interest rate derivatives

Derivatives - current

—

Derivatives - current

23,283

Commodity price derivatives

Derivatives - noncurrent

270,681

Derivatives - noncurrent

16,127

Interest rate derivatives

Derivatives - noncurrent

—

Derivatives - noncurrent

11,410

589,184

67,928

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

Fair Value of Derivative Instruments as of December 31, 2011

Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet

Location

Fair

Value

Balance Sheet

Location

Fair

Value

(in thousands)

Derivatives not designated as hedging instruments

Commodity price derivatives

Derivatives - current

248,809

Derivatives - current

68,735

Interest rate derivatives

Derivatives - current

—

Derivatives - current

15,654

Commodity price derivatives

Derivatives - noncurrent

257,368

Derivatives - noncurrent

47,689

506,177

132,078

___________________


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



Derivatives in Cash Flow Hedging	Location of Gain/(Loss) Reclassified from	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
Derivatives in Cash Flow Hedging	Location of Gain/(Loss) Reclassified from	Three Months Ended June 30,						Six Months Ended June 30,
Relationships	AOCI into Earnings	2012			2011			2012			2011
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	(2,347	)	$	8,208		$	(3,156	)	$	16,332
Interest rate derivatives	Interest expense	—			(69		)	(1,699		)	(137		)
Total		$	(2,347	)	$	8,139		$	(4,855	)	$	16,195



		Amount of Gain (Loss) Recognized in Earnings on Derivatives
Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in	Three Months Ended June 30,					Six Months Ended June 30,
Instruments	Earnings on Derivatives	2012			2011		2012			2011
		(in thousands)
Commodity price derivatives	Derivative gains (losses), net	$	298,471		$	214,903	$	386,601		$	(27,377	)
Interest rate derivatives	Derivative gains (losses), net	(22,659		)	14,575		(19,039		)	12,423
Total		$	275,812		$	229,478	$	367,562		$	(14,954	)

AOCI - Hedging. As of December 31, 2011, the Company had $3.2 million and $1.7 million of net deferred losses on the effective portions of discontinued oil and interest rate hedges, respectively, and $1.8 million of associated net deferred tax benefits classified in AOCI—Hedging in the accompanying consolidated balance sheet. During the six months ended June 30, 2012, the Company transferred the respective AOCI - Hedging balances to oil revenue, interest expense and income tax provisions.

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table provides the Company's derivative assets and liabilities by counterparty as of June 30, 2012:



	Assets		Liabilities
	(in thousands)

JP Morgan Chase	$	119,358	$	15,217
Citibank, N.A.	87,788		438
Barclays Capital	53,131		—
BMO Financial Group	42,192		—
BNP Paribas	40,677		—
J. Aron & Company	33,071		—
Wells Fargo Bank, N.A.	31,419		20,981
Credit Suisse	29,795		—
Toronto Dominion	29,206		—
Credit Agricole	28,179		2,177
Societe Generale	24,356		—
Merrill Lynch	16,880		2,775
Morgan Stanley	16,184		885
Den Norske Bank	9,790		—
BP Corporation North America	4,040		—
Deutsche Bank	2,194		2,363
Vitol	1,345		—
Macquarie Bank	86		—
Royal Bank of Canada	—		262
UBS	—		3,337
Total	$	569,691	$	48,435

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells, restoration of certain sand mines 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.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Beginning asset retirement obligations	$	134,314		$	154,689		$	136,742		$	152,291
Liabilities assumed in acquisitions	8,515			—			8,515			6
New wells placed on production	1,581			1,404			2,411			2,075
Changes in estimates	1,603			(179		)	1,603			121
Disposition of wells	—			(367		)	—			(448		)
Liabilities settled	(3,054		)	(6,235		)	(8,742		)	(7,469		)
Accretion of discount from continuing operations	2,444			2,048			4,874			4,092
Accretion of discount from integrated services (a)	54			—			54			—
Accretion of discount from discontinued operations	—			610			—			1,302
Ending asset retirement obligations	$	145,457		$	151,970		$	145,457		$	151,970

_____________________


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

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of June 30, 2012 and December 31, 2011, the current portions of the Company's asset retirement obligations were $18.6 million and $14.2 million, respectively.

NOTE J. Incentive Plans

Stock-based compensation

For the three and six months ended June 30, 2012, the Company recorded $21.7 million and $43.3 million, respectively, of stock-based compensation expense for all plans, as compared to $13.8 million and $26.4 million for the same respective periods of 2011. As of June 30, 2012, there was $156.0 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $27.0 million attributable to stock-based awards that are expected to be settled in cash on their vesting date, rather than in equity shares ("Liability Awards"). This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of June 30, 2012 and December 31, 2011, accounts payable – due to affiliates includes $8.2 million and $9.2 million, respectively, of liabilities attributable to Liability Awards.

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

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



	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units		Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2011	1,857,612		322,925		114,128	564,044		7,492		65,157
Awards granted	897,591		223,375		47,875	98,819		7,496		37,487
Awards vested	(1,199,536	)	(115,700	)	—	—		(7,492	)	—
Options exercised	—		—		—	(64,509	)	—		—
Awards forfeited	(15,145	)	(10,342	)	—	—		—		—
Outstanding as of June 30, 2012	1,540,522		420,258		162,003	598,354		7,496		102,644

Postretirement Benefit Obligations

As of June 30, 2012 and December 31, 2011, the Company had $8.5 million and $7.5 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities in the accompanying consolidated balance sheets. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years, and two funded plans that the Company assumed sponsorship for in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of June 30, 2012 or December 31, 2011. The Company's funding policy for the Premier Silica plans is to contribute amounts sufficient to meet legal funding requirements, plus any additional amounts that the Company may determine to be appropriate considering the funded status of the plan, tax deductibility, the cash flow generated by the Company, and other factors. The Company continually reassesses the amount and timing of any discretionary contributions and could elect to make such a contribution in 2012.

NOTE K. Commitments and Contingencies

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

NOTE L. Net Income (Loss) Per Share

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

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2012 and 2011:



	Three Months Ended June 30, 2012								Six Months Ended June 30, 2012
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	(82,409	)	$	12,017	$	(70,392	)	$	121,515		$	22,712		$	144,227
Participating basic earnings	(265		)	—		(265		)	(1,833		)	(343		)	(2,176		)
Basic net income (loss) attributable to common stockholders	(82,674		)	12,017		(70,657		)	119,682			22,369			142,051
Reallocation of participating earnings	—			—		—			130			24			154
Diluted income (loss) attributable to common stockholders	$	(82,674	)	$	12,017	$	(70,657	)	$	119,812		$	22,393		$	142,205



	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	248,602		$	(3,025	)	$	245,577		$	177,314		$	416,857		$	594,171
Participating basic earnings	(4,847		)	—			(4,847		)	(3,238		)	(7,611		)	(10,849		)
Basic net income (loss) attributable to common stockholders	243,755			(3,025		)	240,730			174,076			409,246			583,322
Reallocation of participating earnings	164			—			164			81			190			271
Diluted income (loss) attributable to common stockholders	$	243,919		$	(3,025	)	$	240,894		$	174,157		$	409,436		$	583,593

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2012 and 2011:



	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(in thousands)
Weighted average common shares outstanding:
Basic	123,028	116,213	122,754	116,042
Dilutive common stock options (a)	—	178	205	188
Convertible senior notes dilution (a)	—	1,772	2,642	2,333
Contingently issuable performance unit shares (a)	—	429	171	423
Diluted	123,028	118,592	125,772	118,986

____________________

(a)

The following common share equivalents were excluded from the weighted average diluted shares for the three months ended June 30, 2012 because they would have been anti-dilutive to the loss recorded for the period: 206,495 outstanding options to purchase the Company's common stock, 184,236 common shares attributable to unvested performance units and 1,825,147 common shares issuable if holders of the Company's 2.875% Convertible Senior Notes had exercised their conversion rights (see Note G). Options to purchase 185,772 shares of the Company's common stock were excluded from the diluted income per share calculations for the six months ended June 30, 2012 because they would have been anti-dilutive to the calculation.

NOTE M. Interest and Other Income

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



	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012		2011
	(in thousands)
Equity in income of unconsolidated affiliate (a)	$	7,861		$	502	$	14,842	$	801
Alaskan Petroleum Production Tax credits and refunds (b)	—			—		11,846		27,452
Third-party income (loss) from vertical integration services (c)	(3,820		)	8,881		2,729		7,913
Other income	592			3,698		2,234		4,334
Deferred compensation plan income	150			299		1,523		1,166
Interest income	1,260			214		1,317		401
Total interest and other income	$	6,043		$	13,594	$	34,491	$	42,067

____________________


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


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


(c)	Third-party income (loss) from vertical integration services represents third-party working interests' share of earnings associated with Company-provided fracture stimulation, drilling and related services.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE N. Other Expense

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012		2011
	(in thousands)
Transportation commitment charges (a)	$	9,227		$	5,688		$	17,680	$	10,960
Above market drilling rig rates (b)	5,760			5,410			10,746		10,569
Terminated drilling rig contract charges (c)	8,960			—			8,960		—
Inventory valuation charges (d)	1,262			302			7,454		587
Other	4,578			(934		)	6,346		2,549
Premier Silica acquisition costs	1,190			—			2,173		—
Contingency and environmental accrual adjustments	(326		)	1,587			702		2,882
Loss on extinguishment of debt	—			—			197		2,367
Total other expense	$	30,651		$	12,053		$	54,258	$	29,914

____________________


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


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


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


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

NOTE O. Impairment

The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate their carrying values may not be fully recoverable. During the past year, reductions in management's outlook for commodity prices have provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in Southeastern Colorado. As a result of management's assessments, during the fourth quarter of 2011 and second quarter of 2012, the Company recognized pretax noncash impairment charges of $354.4 million and $444.9 million, respectively, to reduce the carrying value of the Edwards Trend/Austin Chalk fields and the Barnett Shale field to their estimated fair values. The Company calculated the estimated fair value of the Barnett Shale field as of June 30, 2012 using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted cash flows include management's outlook for (i) oil and gas prices of $87.09 per BBL for oil and $4.64 per MCF of gas, (ii) production costs, (iii) capital expenditures and (iv) production and estimated proved reserves and risk-adjusted probable reserves. Management's commodity price outlooks represent longer-term outlooks that are developed based on third-party futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Impairment risk. The Company's estimates of undiscounted future net cash flows attributable to the Raton field's gas properties indicated on June 30, 2012 that its carrying amount was expected to be recovered. However, the carrying value of this field continues to be at risk for impairment if future estimates of undiscounted cash flows decline. As of June 30, 2012, the Company's Raton field has a carrying value of $2.3 billion.

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE P. Subsequent Event

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

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PIONEER NATURAL RESOURCES COMPANY

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

Financial and Operating Performance

The Company's financial and operating performance for the second quarter of 2012 included the following highlights:

•

Earnings attributable to common stockholders was a net loss of $70.4 million ($0.57 per diluted share), as compared to net income attributable to common stockholders of $245.6 million ($2.03 per diluted share) for the second quarter of 2011. The decrease in earnings attributable to common stockholders is primarily comprised of a $331.0 million decrease in earnings from continuing operations, which includes:


▪	a $444.9 million pretax charge for impairment of oil and gas properties in the Barnett Shale field associated with reductions in management's commodity price outlook (see Note O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Results of Operations," below);


▪	a $55.1 million increase in oil and gas production costs, primarily due to increases in variable lease operating expenses and third-party transportation fees due to higher sales volumes and a decrease in revenues attributable to processing third-party gas volumes in Company-owned facilities;


▪	a $65.4 million increase in DD&A, primarily due to increased sales volumes;


▪	an $18.6 million increase in other expense, primarily associated with $9.0 million of drilling rig contract termination fees and a $3.5 million increase in unused firm transportation costs; and


▪	a $17.4 million increase in exploration and abandonments expense, primarily associated with an $8.5 million increase in unproved leasehold abandonments and a $7.6 million increase in geological and geophysical costs; partially offset by


▪	$185.3 million of incremental income tax benefits associated with the loss from continuing operations;


▪	a $79.3 million increase in oil and gas revenues as a result of an increase in sales volumes, partially offset by lower average commodity prices; and


▪	a $46.3 million increase in net derivative gains from net derivative settlements and unrealized mark-to-market adjustments.

•

During the second quarter of 2012, average daily sales volumes increased by 32 percent to 150,506 BOEPD, as compared to 113,937 BOEPD during the second quarter of 2011. The increase in second quarter 2012 average daily sales volumes, as compared to the second quarter of 2011, was primarily due to the Company's successful drilling program during the last six months of 2011 and the first half of 2012;


•	Average reported oil, NGL and gas prices decreased during the second quarter of 2012 to $88.32 per BBL, $32.62 per BBL and $2.00 per MCF, respectively, as compared to $104.34 per BBL, $48.16 per BBL and $4.11 per MCF, respectively, in the second quarter of 2011;

•

Average oil and gas production costs per BOE increased to $11.45 for the second quarter of 2012, as compared to $9.81 for the second quarter of 2011, primarily due to a decrease in revenues attributable to processing third-party gas volumes in Company-owned facilities as a result of lower gas and NGL prices and an increase in third party transportation and processing charges associated with increasing Eagle Ford Shale production (see "Results of Operations," below, for more information about changes in production costs);


•	Net cash provided by operating activities increased to $499.3 million for the three months ended June 30, 2012, as compared to $421.2 million for the three months ended June 30, 2011. The $78.1 million increase in net cash provided by operating activities was primarily due to increases in oil and gas sales volumes and realized derivative gains;

•

During April 2012, the Company acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC. The Company changed the name of Oglebay Norton Industrial Sands, LLC to Premier Silica LLC ("Premier Silica") in April 2012. Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. The aggregate purchase price of Premier Silica was $296.0 million, including estimated closing adjustments, and was funded from available cash and borrowings under the Company's credit facility;


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

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PIONEER NATURAL RESOURCES COMPANY


•	As of June 30, 2012, the Company's net debt to book capitalization was 34 percent, as compared to 26 percent as of December 31, 2011. The Company was upgraded to investment grade by one of its debt rating agencies during the fourth quarter of 2011 and by another agency during the second quarter of 2012;

•

In June and July 2012, the Company liquidated swap, collar and three-way collar derivatives for 250,000 MMBTUPD of 2014 gas production and 80,000 MMBTUPD of 2015 gas production. These liquidated volumes represent 100 percent and 43 percent of Pioneer's gas derivative positions in 2014 and 2015, respectively. The Company also liquidated 140,000 MMBTUPD of gas basis swaps for 2014. As a result of these liquidations, the Company realized $143.1 million of net cash proceeds, of which $71.9 million was realized during June 2012 and $71.2 million was realized during July 2012.

Third Quarter 2012 Outlook

Based on current estimates, the Company expects the following operations and financial results for the quarter ending September 30, 2012:

Production is forecasted to average 155,000 to 159,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $13.50 to $15.50 per BOE based on current NYMEX strip prices for oil, NGLs and gas. DD&A expense is expected to average $13.00 to $15.00 per BOE.

Total exploration and abandonment expense is expected to be $25 million to $40 million. General and administrative expense is expected to be $55 million to $60 million. Interest expense is expected to be $51 million to $56 million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

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

The Company's effective income tax rate, excluding the effect of net income attributable to noncontrolling interest, is expected to range from 35 percent to 40 percent, assuming current capital spending plans and no significant mark-to-market changes in the Company's derivative position. Cash income taxes are expected to range from $5 million to $10 million, primarily attributable to alternative minimum tax and state taxes.

Operations and Drilling Highlights

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during the six months ended June 30, 2012:



	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	42,117	12,092	59,530	64,130
Raton Basin	—	—	153,397	25,566
South Texas - Eagle Ford Shale	8,852	5,639	53,130	23,346
Mid-Continent	3,198	6,856	48,251	18,096
South Texas - Edwards and Austin Chalk	71	1	38,642	6,513
Barnett Shale	1,024	2,631	17,997	6,654
Alaska	4,285	—	—	4,285
Other	3	3	121	27
	59,550	27,222	371,068	148,617

During 2012 and 2011, the Company has focused its capital budget expenditures on oil- and liquids-rich-gas drilling activities as a result of the decline in gas prices. As a result of these capital activities and commodity price changes, the Company's total liquids production and revenue from continuing operations has increased to 58 percent and 89 percent, respectively, for the six months ended June 30, 2012 from 50 percent and 77 percent, respectively, for the same period last year.

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The following table summarizes by geographic area the Company's finding and development costs incurred from continuing operations during the six months ended June 30, 2012:



	Acquisition Costs					Exploration		Development		Asset Retirement
	Proved		Unproved			Costs		Costs		Obligations		Total
	(in thousands)
Permian Basin	$	1,942	$	51,098		$	141,310	$	932,518	$	1,592	$	1,128,460
Raton Basin	49		(23		)	4,401		6,122		—		10,549
South Texas - Eagle Ford Shale	—		4,901			90,328		3,546		32		98,807
Mid-Continent	—		2,318			2,944		6,737		—		11,999
South Texas - Edwards and Austin Chalk	—		207			2,835		4,478		—		7,520
Barnett Shale	5,012		5,005			112,416		27,102		175		149,710
Alaska	—		—			60,346		55,934		2,256		118,536
Other	—		33,250			1,014		6		—		34,270
	$	7,003	$	96,756		$	415,594	$	1,036,443	$	4,055	$	1,559,851

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



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	161	362	426	7	90
Raton Basin	5	—	4	—	1
Barnett Shale	—	2	2		—
Alaska	1	2	2	—	1
Total United States	167	366	434	7	92



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	—	20	5	—	15
South Texas - Eagle Ford Shale	39	63	64	—	38
Mid-Continent	5	—	—	5	—
Barnett Shale	26	16	22	—	20
Alaska	1	2	1	1	1
Total United States	71	101	92	6	74

Permian Basin area. The Company currently has 34 rigs operating in the Spraberry field, of which 30 are drilling vertical wells and four are drilling Wolfcamp Shale horizontal wells. The Company plans to operate 27 to 30 vertical rigs during the remainder of 2012 and increase its horizontal Wolfcamp Shale rig count to seven near year end. During 2012, the Company expects to drill approximately 660 vertical wells and 35 to 40 horizontal Wolfcamp Shale wells. During the six months ended June 30, 2012, the Company completed 435 vertical wells and three horizontal Wolfcamp Shale wells.

In the horizontal Wolfcamp Shale play, the Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Wolfcamp A, B, C and D intervals and its drilling results to-date. The Company's horizontal drilling activity for the remainder of 2012 will be focused on the 200,000 acres in the southern part of the play to hold expiring acreage. The Company plans to continue drilling in the B interval and to test the A interval in this area. Pioneer's first two A interval wells have been drilled and are awaiting completion.

The Company expects to drill approximately 90 horizontal wells in the southern part of the play by the end of 2013 to hold approximately 50,000 expiring acres, with 30 to 35 horizontal wells being drilled in 2012. During the fourth quarter of 2012, the Company plans to begin delineating the northern part of its Spraberry acreage position by drilling in Midland, Martin and Gaines Counties. Wells drilled in this area are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths compared to the southern part of the play. Pioneer believes a successful drilling program in this area could substantially increase its prospective horizontal Wolfcamp Shale acreage position.

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

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

The Company continues to expand its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has 15 Company-owned drilling rigs, five Company-owned vertical fracture stimulation fleets and two Company-owned horizontal fracture stimulation fleets currently operating in the Spraberry field. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, the Company has contracted for tubular and pumping unit requirements through 2012 and well cementing services through 2016.

In early April 2012, the Company completed the acquisition of Premier Silica, which is expected to supply the Company's growing brown sand requirements for fracture stimulating wells in the vertical Spraberry and horizontal Wolfcamp Shale plays along with the Barnett Shale Combo play.

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

The Company completed 64 horizontal Eagle Ford Shale wells during the first six months of 2012, all of which were successful, with average lateral lengths of approximately 5,500 feet and, on average, 13-stage fracture stimulations. The Company is currently running 12 drilling rigs and three fracture stimulation fleets, two of which are Pioneer-owned fleets, in the play.

To improve the execution of its drilling and completions program and reduce costs, the Company is testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company plans to continue to monitor the performance of these wells and plans to use white sand in 50 percent of its 2012 drilling program.

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

Alaska. The Company owns a 70 percent working interest in, and is the operator of, the Oooguruk development project. Since inception, the Company has drilled 15 production wells and nine injection wells to develop this project. During the first quarter of 2012, the Company drilled two exploration wells, the first of which was drilled from an onshore location to further evaluate the productivity of the Torok formation and the feasibility of future development expansion. The Company flow tested the well during April 2012 until production could no longer be transported along the ice road being utilized. The well was successful with a gross initial production rate of approximately 2,000 barrels of oil per day, which was constrained due to surface facility capacity limitations. Based on the better than expected production results from this well, the Company plans to drill an appraisal well during the first quarter of 2013 to further delineate the discovery. The second exploration well was drilled from an ice pad on the west side of the Oooguruk unit to test the Ivishak formation, which is the main producing horizon in the Prudhoe Bay field. This well was non-commercial and was plugged and abandoned.

The Company also tested a new fracture stimulation design on new wells completed in the Nuiqsut and Torok intervals from the Oooguruk development facilities. Gross production from the Nuiqsut well averaged approximately 3,000 barrels of oil per day during the second quarter. The Company plans to drill up to four additional Nuiqsut wells over the remainder of 2012 that will be

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similarly fracture stimulated this winter.

Barnett Shale. During the first six months of 2012, the Company had two drilling rigs and one Pioneer-owned fracture stimulation fleet operating in the field and completed 24 Barnett Shale Combo wells, all of which were successful. During August 2012, the Company plans to reduce to one drilling rig as a result of lower NGL and gas prices. In total, the Company has accumulated over 93,000 gross acres in the liquid-rich area of the field and has acquired approximately 340 square miles of proprietary 3-D seismic covering its acreage, which it is using to high-grade future drilling location selections.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $641.7 million and $1.4 billion for the three and six months ended June 30, 2012, respectively, as compared to $562.4 million and $1.0 billion for the same respective periods in 2011.

The increase in oil and gas revenues during the three months ended June 30, 2012, as compared to the same period in 2011, is reflective of 71 percent, 23 percent and 10 percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the quarter-to-quarter comparison were declines of 15 percent, 32 percent and 51 percent in reported oil, NGL and gas prices, respectively. The increase in oil and gas revenues during the six months ended June 30, 2012, as compared to the same period in 2011, is reflective of 71 percent, 34 percent and 12 percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the six month comparisons were declines of six percent, 18 percent and 44 percent in reported oil, NGL and gas prices, respectively.

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



	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
Oil (BBLs)	61,428	35,872	59,550	34,904
NGLs (BBLs)	26,960	21,839	27,222	20,251
Gas (MCF)	372,713	337,354	371,068	331,295
Total (BOE)	150,506	113,937	148,617	110,371

Average daily BOE sales volumes increased by 32 percent and 35 percent for the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, principally due to the Company's successful drilling program. However, the production growth for the three and six months ended June 30, 2012, as compared to the same periods in 2011, would have been higher had production not been negatively impacted during the second quarter of 2012 by approximately 4,800 BOEPD due to unplanned third-party NGL fractionation downtime and NGL fractionation capacity limitations at Mont Belvieu, Texas. Specifically, portions of the Company's gas production include NGLs that are separated at the Midkiff/Benedum and Sale Ranch gas processing facilities in West Texas. These NGLs are then transported to third-party fractionation facilities at Mont Belvieu. During May, a significant third-party facility was shut down for planned maintenance. When the facility came back on line in late May, it had operating problems and was not able to achieve its pre-shutdown fractionation capacity. As a result of this problem and the fractionation capacity limitations across the Mont Belvieu complex, the Company built an NGL inventory of 256 thousand barrels that could not be processed for sale in June, thereby negatively impacting production for the second quarter by approximately 2,800 BOEPD. Within the next month, the fractionation facility is expected to increase processing rates to its pre-shutdown processing capacity, thereby allowing the Company's NGL inventory and ongoing production to be fractionated and sold over the remainder of 2012.

The Midkiff/Benedum gas processing plants were also forced to reject ethane into the residue gas stream during the second quarter of 2012 as a result of the NGL capacity limitations at Mont Belvieu. The net impact of rejecting ethane was a loss in production of approximately 2,000 BOEPD. Ethane rejection continues and is expected to impact the Company's production over the remainder of 2012 based on the outlook for continuing tight fractionation capacity at Mont Belvieu. Due to low ethane prices, there is not a significant economic impact to rejecting ethane versus recovering and selling it. Pioneer estimates that its revenues are lower as a result of ethane rejection by approximately $18 thousand per day at current gas and NGL prices.

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

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Average reported prices:
Oil (per BBL)	$	88.32	$	104.34	$	94.45	$	100.05
NGL (per BBL)	$	32.62	$	48.16	$	37.26	$	45.42
Gas (per MCF)	$	2.00	$	4.11	$	2.26	$	4.00
Total (per BOE)	$	46.86	$	54.24	$	50.31	$	51.97
Average realized prices:
Oil (per BBL)	$	86.87	$	98.39	$	92.81	$	93.93
NGL (per BBL)	$	32.62	$	48.16	$	37.26	$	45.42
Gas (per MCF)	$	2.00	$	4.11	$	2.26	$	4.00
Total (per BOE)	$	46.26	$	52.37	$	49.65	$	50.03

Derivative activities. The primary purposes for which the Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts are to (i) reduce the effect of price volatility on the commodities the Company produces, sells and consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three and six months ended June 30, 2012, the Company transferred $2.3 million and $3.2 million, respectively, of deferred oil hedge losses from AOCI-Hedging to oil revenue, as compared to transferring $8.2 million and $16.3 million of deferred oil hedge gains, respectively, from AOCI-Hedging to oil revenue during the same respective periods in 2011.

Deferred revenue. During the three and six months ended June 30, 2012, the Company's amortization of deferred VPP revenue increased oil revenues by $10.4 million and $20.9 million as compared to an increase of $11.2 million and $22.3 million during the same respective periods in 2011.

Derivative gains, net. During the three months ended June 30, 2012, the Company recorded $275.8 million of net derivative gains on commodity price and interest rate derivatives, of which $119.1 million represented unrealized net gains and $156.7 million represented realized net gains. During the six months ended June 30, 2012, the Company recorded $367.6 million of net derivative gains on commodity price and interest rate derivatives, of which $147.2 million represented unrealized net gains and $220.4 million represented realized net gains. During the three and six months ended June 30, 2011, the Company recorded $229.5 million of net derivative gains and $15.0 million of net derivative losses, respectively. Derivative gains and losses result from changes in the fair values of the Company's derivative contracts. In June 2012 and July 2012, the Company liquidated swap, collar and three-way collar derivatives for 250,000 MMBTUPD of 2014 gas production and 80,000 MMBTUPD of 2015 gas production. These liquidated volumes represented 100 percent and 43 percent of Pioneer's gas derivative positions in 2014 and 2015, respectively. The Company also liquidated 140,000 MMBTUPD of gas basis swaps for 2014. As a result of these liquidations, the Company realized approximately $143.1 million of net cash proceeds, of which $71.9 million was realized during June 2012 and $71.2 million was realized during July 2012. See Notes E and H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Company's derivative activities and market risks associated with those activities.

Interest and other income. Interest and other income for the three and six months ended June 30, 2012 was $6.0 million and $34.5 million, respectively, as compared to $13.6 million and $42.1 million, respectively, for the same periods in 2011. The $7.6 million decrease in interest and other income during the three months ended June 30, 2012, as compared to the same period in 2011, was primarily due to a $12.7 million decrease in third-party income from vertical integration services, partially offset by a $7.4 million increase in equity earnings from EFS Midstream. The $7.6 million decrease in interest and other income during the six months ended June 30, 2012, as compared to the same period in 2011, was primarily due to a $15.6 million decrease in Alaskan PPT credit recoveries and a $5.2 million decrease in third-party income from vertical integration services, partially offset by a $14.0 million increase in equity earnings from EFS Midstream. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding interest and other income.

Gain (Loss) on disposition of assets, net. The Company recorded net gains on the disposition of assets of $1.1 million and $44.7 million, respectively, during the three and six months ended June 30, 2012 as compared to net losses on the disposition of assets of $296 thousand and $2.5 million, respectively, for the same periods of 2011. The net gain for the three months ended June 30, 2012 is primarily associated with sales of transportation equipment. The net gain for the six months ended June 30, 2012 is

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primarily attributable to the Company's sale of a portion of its working interest in an unproved oil and gas property in the Eagle Ford Shale to unaffiliated third parties. The net losses for the three and six months ended June 30, 2011 were primarily associated with sales of excess materials and supplies inventory. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's gains and losses on the disposition of assets.

Oil and gas production costs. The Company recorded oil and gas production costs of $156.8 million and $295.2 million during the three and six months ended June 30, 2012, respectively, as compared to $101.7 million and $200.6 million during the same respective periods in 2011. In general, lease operating expenses and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from the gathering and processing of third-party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the three and six months ended June 30, 2012 increased by 17 percent and 9 percent, respectively, as compared to the same periods in 2011. The increase in production costs per BOE during the three and six months ended June 30, 2012, as compared to the same three and six months in 2011, is primarily due to increases in third-party transportation and processing charges associated with increasing Eagle Ford Shale production and decreases in net natural gas plant margins as a result of lower gas and NGL prices.

The following table provides the components of the Company's oil and gas production costs per BOE for the three and six months ended June 30, 2012 and 2011:



	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
Lease operating expenses	$	8.08	$	7.94		$	7.90	$	7.99
Third-party transportation charges	1.77		1.10			1.75		1.07
Net natural gas plant/gathering charges	0.64		(0.26		)	0.44		0.06
Workover costs	0.96		1.03			0.83		0.93
Total production costs	$	11.45	$	9.81		$	10.92	$	10.05

Production and ad valorem taxes. The Company's production and ad valorem taxes were $44.5 million and $90.3 million during the three and six months ended June 30, 2012, respectively, as compared to $35.9 million and $69.2 million for the same respective periods in 2011. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During the three months ended June 30, 2012, the Company's per-BOE production taxes decreased, as compared to the three months ended June 30, 2011, primarily due to lower 2012 commodity prices. During the six months ended June 30, 2012, the Company's per-BOE ad valorem taxes declined, as compared to the six months ended June 30, 2011, primarily due to increased production from new wells placed on production, partially offset by higher 2011 commodity prices.

The following table provides the Company's production and ad valorem taxes per BOE for the three and six months ended June 30, 2012 and 2011:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Ad valorem taxes	$	1.44	$	1.41	$	1.27	$	1.45
Production taxes	1.81		2.05		2.07		2.01
Total ad valorem and production taxes	$	3.25	$	3.46	$	3.34	$	3.46

Depletion, depreciation and amortization expense. The Company's DD&A expense was $200.9 million ($14.67 per BOE) and $382.3 million ($14.14 per BOE) for the three and six months ended June 30, 2012, respectively, as compared to $135.5 million ($13.07 per BOE) and $258.3 million ($12.93 per BOE) during the same respective periods in 2011. The increase in per BOE depletion expense during the three and six months ended June 30, 2012, as compared to the same period of 2011, is primarily due to increases in depletion expense per BOE on oil and gas properties, partially offset by the per-BOE effect of increasing production on relatively fixed depreciation on other property and equipment.

Depletion expense on oil and gas properties was $14.05 per BOE and $13.53 per BOE during the three and six months ended June 30, 2012, respectively, as compared to $12.33 and $12.23 per BOE during the same respective periods in 2011. The 14 percent

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and 11 percent increases in per-BOE depletion expense during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, are primarily due to (i) increased drilling expenditures on proved undeveloped locations, primarily in the Spraberry field and (ii) declines in proved gas reserves due to lower first-day-of-the-month gas prices during the 12-month period ending on June 30, 2012, partially offset by (iii) the impact of the fourth quarter 2011 impairment of $354.4 million of South Texas Edwards and Austin Chalk field carrying values.

Impairment of oil and gas properties. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate their carrying values may not be fully recoverable. During the past year, reductions in management's outlook for commodity prices have provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in Southeastern Colorado. As a result of management's assessments, during the fourth quarter of 2011 and second quarter of 2012, the Company recognized pretax noncash impairment charges of $354.4 million and $444.9 million, respectively, to reduce the carrying values of the South Texas Edwards Trend/Austin Chalk fields and Barnett Shale field to their estimated fair values.

The Company's estimates of undiscounted future net cash flows attributable to the Raton field oil and gas properties indicated on June 30, 2012 that its carrying amount was expected to be recovered. However, the carrying value of this field continues to be at risk for impairment if future estimates of undiscounted cash flows decline. For example, the Company estimates that the carrying value of the Raton field may become partially impaired if management's outlook for gas prices, which was $4.64 per MCF as of June 30, 2012, were to decline by approximately $0.10 per MCF to $0.20 per MCF, assuming none of the other impairment inputs changed. The Company's Raton field is a relatively long-lived asset that had a carrying value of $2.3 billion as of June 30, 2012. If the Raton field were to become impaired in a future quarter, the Company would recognize noncash, pretax impairment charges in that period that could range from $1.5 billion to $1.8 billion.

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

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

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense for the three and six months ended June 30, 2012 and 2011 (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Geological and geophysical	$	24,391	$	16,780	$	50,426	$	32,393
Exploratory dry holes	1,409		163		28,286		808
Leasehold abandonments and other	11,378		2,789		11,753		4,015
	$	37,178	$	19,732	$	90,465	$	37,216

The Company's geological and geophysical costs increased by $7.6 million and $18.0 million during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, primarily as a result of increased seismic expenditures supportive of drilling activities in the Spraberry and Barnett Shale fields. The Company's leasehold abandonments and other expense increased by $8.6 million and $7.7 million during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, primarily due to increases in leasehold abandonments in dry gas areas. The Company's exploratory dry holes increased by $1.2 million and $27.5 million during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, primarily due to dry hole provisions of $1.1 million and $20.2 million, respectively, related to an unsuccessful exploration well in Alaska, and first quarter 2012 dry hole provisions in the South Texas Austin Chalk field and Mid-Continent area.

During the six months ended June 30, 2012, the Company drilled and evaluated 98 exploration/extension wells, 92 of which were successfully completed as discoveries. During the same period in 2011, the Company drilled and evaluated 64 exploration/extension wells, all of which were successfully completed as discoveries.

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General and administrative expense. General and administrative expense for the three and six months ended June 30, 2012 was $55.0 million and $118.0 million, respectively, as compared to $44.3 million and $88.3 million during the same respective periods in 2011. The $10.7 million increase in general and administrative expense for the three months ended June 30, 2012, as compared to the same period in 2011, was primarily due to increases of $4.7 million, $4.7 million and $1.8 million in share-based compensation, salaries and occupancy expense, respectively, related to staffing increases in support of the Company's capital expansion and integrated services initiatives. The $29.7 million increase in general and administrative expense for the six months ended June 30, 2012, as compared to the same period in 2011, was primarily due to increases of $12.1 million, $9.4 million, $2.7 million and $2.6 million in share-based compensation, salaries, occupancy and contract services expenses, respectively, related to staffing increases and other costs supportive of the Company's capital expansion and integrated services initiatives.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.4 million and $4.9 million for the three and six months ended June 30, 2012, respectively, as compared to $2.0 million and $4.1 million during the same respective periods in 2011. See Note I of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $49.0 million and $95.9 million for the three and six months ended June 30, 2012, respectively, as compared to $45.0 million and $90.2 million during the same respective periods in 2011. The weighted average interest rate on the Company's indebtedness for the three and six months ended June 30, 2012, including the effects of capitalized interest, was 6.2 percent and 6.8 percent, as compared to 7.3 percent for each of the same respective periods in 2011. Interest expense increased by $4.0 million and $5.6 million during the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011, primarily due to increases of $2.5 million and $1.8 million, respectively, in interest on credit facility borrowings; decreases of $1.1 million and $929 thousand, respectively, in capitalized interest and a $2.6 million increase in amortization of note discounts and deferred hedge losses in the six-month comparison.

Other expense. Other expense for the three and six months ended June 30, 2012 was $30.7 million and $54.3 million, respectively, as compared to $12.1 million and $29.9 million for the same respective periods in 2011. The $18.6 million increase in other expense for the three months ended June 30, 2012, as compared to the same period in 2011, is primarily attributable to a $9.0 million increase in second quarter 2012 rig contract termination fees, associated with reducing the Spraberry vertical drilling rig count from 40 rigs to 30 rigs, and a $3.5 million increase in unused gas transportation commitment charges. The $24.4 million increase in other expense for the six months ended June 30, 2012, as compared to the same period in 2011, is primarily attributable to the aforementioned $9.0 million in rig contract termination fees, a $6.9 million increase in inventory valuation charges and a $6.7 million increase in unused gas transportation commitment charges. See Note N of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision/benefit. The Company recorded an income tax benefit from continuing operations of $45.1 million for the three months ended June 30, 2012 and an income tax provision of $72.6 million for the six months ended June 30, 2012, as compared to income tax provisions of $140.2 million and $92.3 million for the same respective periods in 2011. The Company's effective tax rates, excluding net income attributable to noncontrolling interests, for the three and six months ended June 30, 2012 were 35 percent and 37 percent, respectively, as compared to the Company's combined United States federal and state statutory rate of approximately 37 percent.

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

Income from discontinued operations, net of tax. The Company reported income from discontinued operations, net of tax of $12.0 million and $22.7 million for the three and six months ended June 30, 2012, respectively, as compared to a loss from discontinued operations, net of tax of $3.0 million for the three months ended June 30, 2011 and income from discontinued operations, net of tax of $416.9 million for the six months ended June 30, 2011.

During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest of its net assets in South Africa. In March 2012, the Company agreed to sell its net assets in South Africa to an unaffiliated third party, using a January 1, 2012 effective date, for net cash proceeds of $52.0 million, before normal closing adjustments. The sale is expected to close during the third quarter of 2012.

During February 2011, the Company completed the sale of 100 percent of the Company's share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $802.5 million, including normal post-closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million.

See Note C of the Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's discontinued operations.

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Net income attributable to noncontrolling interest. Net income attributable to the noncontrolling interests for the three and six months ended June 30, 2012 was $30.9 million and $37.2 million, respectively, as compared to $20.1 million and $15.3 million for the same respective periods of 2011. The $10.8 million and $21.9 million increases in income attributable to noncontrolling interests for the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, is primarily due to fluctuations in Pioneer Southwest's mark-to-market derivative gains and losses.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payment of contractual obligations, dividends/distributions and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets, joint ventures or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2012 is focused on oil- and liquids-rich-gas drilling activities with total expenditures of $2.9 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), consisting of $2.4 billion for drilling operations and $500 million for vertical integration and infrastructure facilities additions, including the April 2012 acquisition of Premier Silica for $296.0 million. Based on results for the six months ended June 30, 2012 and management's commodity price outlook, the Company expects its cash flows from operating activities, rig reductions in the Spraberry and Barnett Shale Combo plays, proceeds from asset divestitures, including 2014 and 2015 gas derivatives, and availability under its credit facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2012.

Investing activities. Investing activities used $1.8 billion of cash during the six months ended June 30, 2012 as compared to $241.9 million of cash used in investing activities during the six months ended June 30, 2011. The $1.6 billion increase in cash used in investing activities for the six months ending June 30, 2012, as compared to the six months ended June 30, 2011, is primarily due to (i) a $750.6 million decrease in proceeds from disposition of assets primarily attributable to the 2011 sale of Pioneer Tunisia, (ii) a $667.7 million increase in additions to oil and gas properties and (iii) the $296.0 million acquisition of Premier Silica, partially offset by (iv) an $82.9 million decrease in investments in EFS Midstream and (v) a $51.1 million decrease in additions to other assets and other property and equipment, primarily comprised of drilling rigs, fracture stimulation equipment and well servicing equipment used in the Company's vertical integration services. During the six months ended June 30, 2012, the Company's investing activities were funded by net cash provided by operating activities, cash on hand and borrowings under its credit facility.

Dividends/distributions. During February of both 2012 and 2011, the Company's board of directors ("the Board") declared semiannual dividends of $0.04 per common share. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company's liquidity and capital resources at the time.

During January 2012 and April 2012, the Pioneer Southwest board of directors (the "Pioneer Southwest Board") declared a quarterly distribution of $0.51 and $0.52 per limited partner unit, respectively, compared to the quarterly distributions of $0.50 and $0.51 per limited partner unit declared in January and April 2011 respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $17.5 million and $12.7 million during the six months ended June 30, 2012 and 2011, respectively. During July 2012, the Pioneer Southwest Board declared quarterly distribution of $0.52 per limited partner unit for unitholders of record on August 2, 2012, payable August 9, 2012. Future distributions by Pioneer Southwest are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the distribution amount based on Pioneer Southwest's liquidity and capital resources at the time.

Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportation commitments, VPP obligations, EFS Midstream capital funding commitments and other liabilities. 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, 2012, 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, gathering, treating, fractionation and transportation commitments, (iv) open purchase commitments, (v) a VPP obligation (to physically deliver volumes and pay related lease operating expenses and capital costs in the future), (vi) take-or-pay obligations that allow the payer to recover make up volumes in the future and (vii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other parties that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. Since December 31, 2011, the material changes in the Company's contractual obligations include (i) a $757.0 million increase in the principal balances of outstanding long-term debt, (ii) a $20.9 million decrease in the Company's VPP obligations and (iii) a $147.2 million increase in

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the Company's derivative net assets. During 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility to fund infrastructure investments that are in excess of operating cash flow; accordingly, future capital needs of EFS Midstream are expected to be funded from its operating cash flow and the borrowings under its credit facility.

The Company's commodity and interest rate derivative contracts are periodically measured and recorded at fair value and continue to be subject to market or credit risk. As of June 30, 2012, these contracts represented net assets of $521.3 million. The ultimate liquidation value of the Company's commodity and interest rate derivatives will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives' fair values as of June 30, 2012. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Company's derivative instruments and market risk.

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

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

Operating activities. Net cash provided by operating activities during the six months ended June 30, 2012 was $925.4 million as compared to $564.5 million during the same period of 2011. The increase in net cash provided by operating activities for the six months ended June 30, 2012, as compared to the six months ended June 30, 2011, is primarily due to increases in oil and gas sales volumes, realized derivative gains and working capital changes.

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

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

Financing activities. Net cash provided by financing activities during the six months ended June 30, 2012 was $676.9 million as compared to net cash used in financing activities of $81.3 million during the six months ended 2011. The $758.2 million increase in cash provided by financing activities during the six months ended June 30, 2012, as compared to the six months ended June 30, 2011, is primarily due to (i) a $786.3 million increase in net borrowings on long-term debt, partially offset by (ii) a $17.1 million increase in treasury stock purchases from employees to satisfy employee withholding tax payments on the vesting of share-based awards and (iii) a $10.4 million decrease in excess tax benefits from share-based payment arrangements.

During March 2012, Pioneer Southwest entered into the Pioneer Southwest Credit Facility with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility provides for aggregate loan commitments of $300.0 million. As of June 30, 2012, there were $69.0 million of outstanding borrowings under the Pioneer Southwest Credit Facility. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information about the available loans, interest rates and debt covenant terms of the Company's credit facility and the Pioneer Southwest Credit Facility.

Effective April 1, 2012, the Company's 2.875% Convertible Senior Notes became convertible at the option of the holders for the quarter ended June 30, 2012. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $22 thousand principal amount of the notes for conversion. The Company paid certain of the tendering holders a total of $7 thousand cash and issued to the tendering holders 50 shares of the Company's common stock in May 2012 in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement. In August 2012, the Company anticipates paying the other tendering holders $15 thousand cash for the remaining notes tendered and issuing shares to be determined based upon the conversion calculation in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

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During June 2012, the Company's stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders for the three months ending September 30, 2012. The Company's 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock price or other conditions. If the 2.875% Convertible Senior Notes had qualified for and been converted as of June 30, 2012, the note holders would have received $479.9 million of cash and approximately 1.8 million shares of the Company's common stock, which was valued at $161.0 million at June 30, 2012.

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

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

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

Liquidity. The Company's principal sources of short-term liquidity are cash on hand and unused borrowing capacity under its credit facility. As of June 30, 2012, the Company had $110.0 million in outstanding borrowings under its credit facility and was in compliance with all of its debt covenants. After adjusting for $40.1 million of undrawn and outstanding letters of credit under its credit facility, the Company had $1.1 billion of unused borrowing capacity as of June 30, 2012. If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or other sources, such as asset sales or joint ventures. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal operating cash flows, cash on hand and available capacity under the Company's credit facility will be adequate to fund 2012 capital expenditures and dividend/distribution payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

Debt ratings. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factors in determining the Company's ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction 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. In November 2011, the Company achieved an investment grade rating with one of the credit rating agencies and in May 2012 received an investment grade rating from a second credit rating agency.

Book capitalization and current ratio. The Company's net book capitalization at June 30, 2012 was $8.7 billion, consisting of $317.8 million of cash and cash equivalents, debt of $3.3 billion and equity of $5.8 billion. The Company's net debt to net book capitalization was 34 percent and 26 percent at June 30, 2012 and December 31, 2011, respectively. The Company's ratio of current assets to current liabilities was 1.14 to 1.00 at June 30, 2012 as compared to 1.31 to 1.00 at December 31, 2011.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2011. As such, the information contained herein should be read in conjunction with the related disclosures in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company's potential exposure to market risks. The term "market risks," insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices, 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. None of the Company's market risk sensitive instruments are entered into for speculative purposes.

The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during the six months ending June 30, 2012:



	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2011	$	389,753		$	(15,654	)	$	374,099
Changes in contract fair value (a)	386,601			(19,039		)	367,562
Contract maturities	(146,689		)	—			(146,689		)
Contract terminations	(73,716		)	—			(73,716		)
Fair value of contracts outstanding as of June 30, 2012	$	555,949		$	(34,693	)	$	521,256

____________________


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

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

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The following table provides information about financial instruments to which the Company was a party as of June 30, 2012 and that are sensitive to changes in interest rates. For debt obligations, the table presents maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt's estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of June 30, 2012. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on August 1, 2012.



	Six Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at June 30.
	2012			2013			2014			2015			2016			Thereafter			Total		2012
	($ in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	479,923		$	—		$	—		$	455,385		$	2,234,600		$	3,169,908	$	(3,738,296	)
Weighted average interest rate	6.02		%	5.41		%	5.27		%	6.78		%	6.88		%	5.89		%
Variable rate principal maturities:
Pioneer Natural Resources credit facility	$	—		$	—		$	—		$	—		$	110,000		$	—		$	110,000	$	(126,351	)
Weighted average interest rate	2.13		%	2.17		%	2.31		%	2.59		%	2.81		%	—
Pioneer Southwest credit facility	$	—		$	—		$	—		$	—		$	—		$	69,000		$	69,000	$	(69,367	)
Weighted average interest rate	2.01		%	2.04		%	2.18		%	2.46		%	2.68		%	2.85		%
Interest Rate Swaps: (b)
Notional debt amount	$	117,222		$	—		$	—		$	250,000		$	—		$	—		$	367,222	$	(34,693	)
Fixed rate payable (%)	3.06		%	—		%	—		%	3.21		%	—		%	—		%
Variable rate receivable (%)	0.38		%	—		%	—		%	0.84		%	—		%	—		%

____________________


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


(b)	Subsequent to June 30, 2012, the Company terminated its 2012 interest rate swap positions at a cost of $28.4 million.

Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of June 30, 2012. Although mitigated by the Company's derivative activities, declines in oil, NGL and gas prices would reduce the Company's revenues.

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

See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for a description of the accounting procedures followed by the Company relative to its derivative financial instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

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	Six Months Ending December 31,			Year Ending December 31,								Asset (Liability) Fair Value at June 30,
	2012			2013			2014			2015		2012
												(in thousands)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (a)	51,610			67,290			40,000			—		$	201,428
Weighted average ceiling price per BBL	$	118.73		$	120.61		$	122.77		$	—
Weighted average floor price per BBL	$	84.80		$	88.88		$	91.50		$	—
Weighted average short put price per BBL	$	69.12		$	71.72		$	74.88		$	—
Collar contracts	2,000			—			—			—		$	2,803
Weighted average ceiling price per BBL	$	127.00		$	—		$	—		$	—
Weighted average floor price per BBL	$	90.00		$	—		$	—		$	—
Swap contracts (a)	3,000			3,000			—			—		$	(11,668	)
Weighted average fixed price per BBL	$	79.32		$	81.02		$	—		$	—
Average forward NYMEX oil prices (b)	$	89.40		$	91.11		$	90.19		$	—
Rollfactor swap contracts	—			6,000			—			—		$	1,167
Weighted average fixed price per BBL (c)	$	—		$	0.43		$	—		$	—
Average forward rollfactor prices (b)	$	—		$	(0.04	)	$	—		$	—
Basis swap contracts	20,000			—			—			—		$	5,384
Weighted average fixed price per BBL	$	(1.15	)	$	—		$	—		$	—
Average forward basis differential prices (d)	$	(1.08	)	$	—		$	—		$	—
NGL Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts	3,000			—			—			—		$	11,766
Weighted average ceiling price per BBL	$	79.99		$	—		$	—		$	—
Weighted average floor price per BBL	$	67.70		$	—		$	—		$	—
Weighted average short put price per BBL	$	55.76		$	—		$	—		$	—
Swap contracts (e)	750			—			—			—		$	19
Weighted average fixed price per BBL	$	35.03		$	—		$	—		$	—
Average forward NGL prices (f)	$	49.02		$	—		$	—		$	—
Diesel swap contracts	—			250			—			—		$	235
Weighted average fixed price per BBL	$	—		$	111.30		$	—		$	—
Average forward diesel prices (g)	$	—		$	121.73		$	—		$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts (h)	—			—			30,000			135,000		$	10,483
Weighted average ceiling price per MMBTU	$	—		$	—		$	7.66		$	5.44
Weighted average floor price per MMBTU	$	—		$	—		$	5.67		$	4.22
Weighted average short put price per MMBTU	$	—		$	—		$	4.33		$	3.22
Collar contracts (h)	65,000			150,000			80,000			50,000		$	158,240
Weighted average ceiling price per MMBTU	$	6.60		$	6.25		$	6.39		$	7.92
Weighted average floor price per MMBTU	$	5.00		$	5.00		$	5.00		$	5.00
Swap contracts (h)	275,000			112,500			10,000			—		$	191,085
Weighted average fixed price per MMBTU	$	4.97		$	5.62		$	6.18		$	—
Average forward NYMEX gas prices (b)	$	3.29		$	3.73		$	4.09		$	4.28
Basis swap contracts (h)	136,000			142,500			140,000			—		$	(15,096	)
Weighted average fixed price per MMBTU	$	(0.34	)	$	(0.22	)	$	(0.21	)	$	—
Average forward basis differential prices (i)	$	(0.09	)	$	(0.13	)	$	(0.15	)	$	—

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___________________


(a)	Subsequent to June 30, 2012, the Company entered into additional NYMEX (i) swap contracts for 8,000 BBLs per day of August 2012 through December 2012 production with a price of $93.09 per BBL and (ii) collar contracts with short puts for 5,000 BBLs per day of 2014 production with a ceiling price of $102.22 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL.


(b)	The average forward NYMEX oil and gas prices are based on August 1, 2012 market quotes.


(c)	Represents swaps that fix the difference between (i) each day's price per BBL of WTI for the first nearby month less (ii) the price per BBL of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per BBL of WTI for the first nearby month less (iv) the price per BBL of WTI for the third nearby NYMEX month, multiplied by .3333.


(d)	The average forward basis differential prices are based on August 1, 2012 market quotes for basis differentials between Midland WTI and Cushing WTI.


(e)	Subsequent to June 30, 2012, the Company entered into additional NGL swap contracts for 2,000 BBLs per day of August 2012 through December 2012 production priced at $80.06 per BBL.


(f)	Forward component NGL prices are derived from active-market NGL component price quotes as of August 1, 2012.


(g)	The average forward diesel price is based on August 1, 2012 market quotes.

(h)


(i)	The average forward basis differential prices are based on August 1, 2012 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

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

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



	Six Months Ending December 31,			Asset Fair Value at June 30,
	2012			2012
				(in thousands)
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	26,739			$	73
Price differential ($/MMBTU)	$	0.25
Average forward basis differential prices (a)	$	0.10
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	3,343			$	30
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12
Index swap volume	(3,343		)
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)
Average forward basis differential prices (b)	$	0.07

____________________


(a)	The average forward basis differential prices are based on August 1, 2012 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

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PIONEER NATURAL RESOURCES COMPANY

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended June 30, 2012 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

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PIONEER NATURAL RESOURCES COMPANY

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the 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 "Part I, Item 1. Business – Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk," as updated by the discussions in Part II of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, which risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K except as updated by the referenced Form 10-Q.

These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of treasury stock under plans or programs during the three months ended June 30, 2012:

Period

Total Number of

Shares (or Units)

Purchased (a)

Average Price Paid per

Share (or Unit)

Total Number of

Shares (or Units)

Purchased As Part of

Publicly Announced

Plans or Programs

Approximate Dollar

Amount of Shares that

May Yet Be Purchased

under Plans or

Programs

April 2012

—

May 2012

—

June 2012

—

Total

—

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

Item 4. Mine Safety Disclosures

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

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PIONEER NATURAL RESOURCES COMPANY

Item 6. Exhibits

Exhibits



Exhibit Number		Description
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).

3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).

3.3	—	Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).

4.1	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).

4.2	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.1 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).

10.1	—	First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan dated effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. File No. 1-13245, filed with the SEC on May 18, 2012).

10.2	(a) —	Amendment to Restricted Stock Award Agreement between the Company and Scott D. Sheffield dated as of May 25, 2012.

31.1	(a) —	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

31.2	(a) —	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

32.1	(b) —	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

32.2	(b) —	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

95.1	(a) —	Mine Safety Disclosures

101.INS	(a) —	XBRL Instance Document.

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

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

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

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

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

_____________


(a)	Filed herewith.


(b)	Furnished herewith.

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PIONEER NATURAL RESOURCES COMPANY

SIGNATURES

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



	PIONEER NATURAL RESOURCES COMPANY

Date: August 6, 2012	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy
		Executive Vice President and Chief Financial Officer

Date: August 6, 2012	By:	/s/ FRANK W. HALL
		Frank W. Hall
		Vice President and Chief Accounting Officer

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PIONEER NATURAL RESOURCES COMPANY

Exhibit Index



Exhibit Number		Description
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).

3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).

3.3	—	Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).

4.1	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).

4.2	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.1 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).

10.1	—	First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan dated effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. File No. 1-13245, filed with the SEC on May 18, 2012).

10.2	(a) —	Amendment to Restricted Stock Award Agreement between the Company and Scott D. Sheffield dated as of May 25, 2012.

31.1	(a) —	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

31.2	(a) —	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.

32.1	(b) —	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

32.2	(b) —	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.

95.1	(a) —	Mine Safety Disclosures

101.INS	(a) —	XBRL Instance Document.

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

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

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

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

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

_____________


(a)	Filed herewith.


(b)	Furnished herewith.