Edgar Filing: PIONEER NATURAL RESOURCES CO

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Non-accelerated filer

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Smaller reporting company

PXD-2013.06.30

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, 2013



¨	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 July 30, 2013 138,546,648

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, 2013 and December 31, 2012	5

	Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012	7

	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2013 and 2012	8

	Consolidated Statement of Equity for the six months ended June 30, 2013	9

	Consolidated Statements of Cash Flows for the six months ended June 30, 2013 and 2012	10

	Notes to Consolidated Financial Statements	11

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	43

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44

Item 4.	Mine Safety Disclosures	44

Item 6.	Exhibits	45

Signatures		46

Exhibit Index		47

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 as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control.

These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's operating activities, access to and availability of transportation, processing, fractionation 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 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, 2012 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.


•	"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, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	695,625		$	229,396
Accounts receivable:
Trade, net	345,812			316,854
Due from affiliates	4,676			3,299
Income taxes receivable	927			7,447
Inventories	198,650			197,056
Prepaid expenses	23,634			13,438
Other current assets:
Derivatives	191,697			279,119
Other	4,171			3,746
Total current assets	1,465,192			1,050,355
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	15,373,058			14,259,708
Unproved properties	133,172			231,555
Accumulated depletion, depreciation and amortization	(4,859,716		)	(4,412,913		)
Total property, plant and equipment	10,646,514			10,078,350
Goodwill	279,687			298,142
Other property and equipment, net	1,231,127			1,217,694
Other assets:
Investment in unconsolidated affiliate	228,475			204,129
Derivatives	137,898			55,257
Other, net	173,694			165,103
	$	14,162,587		$	13,069,030

The financial information included as of June 30, 2013 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, 2013			December 31, 2012
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	813,532		$	729,942
Due to affiliates	65,151			96,935
Interest payable	61,464			68,083
Income taxes payable	938			208
Deferred income taxes	25,344			86,481
Other current liabilities:
Derivatives	6,453			13,416
Other	39,246			39,725
Total current liabilities	1,012,128			1,034,790
Long-term debt	2,823,428			3,721,193
Derivatives	—			12,307
Deferred income taxes	2,390,144			2,140,416
Other liabilities	288,730			293,016
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 145,814,643 and 134,966,740 shares issued at June 30, 2013 and December 31, 2012, respectively	1,458			1,350
Additional paid-in capital	4,844,720			3,683,934
Treasury stock at cost: 7,269,817 and 11,611,093 at June 30, 2013 and December 31, 2012, respectively	(327,927		)	(510,570		)
Retained earnings	2,947,040			2,514,640
Total equity attributable to common stockholders	7,465,291			5,689,354
Noncontrolling interests in consolidating subsidiaries	182,866			177,954
Total equity	7,648,157			5,867,308
Commitments and contingencies
	$	14,162,587		$	13,069,030

The financial information included as of June 30, 2013 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,
	2013			2012			2013			2012
Revenues and other income:
Oil and gas	$	845,136		$	641,737		$	1,632,991		$	1,360,693
Interest and other	1,159			(714		)	20,474			21,194
Derivative gains, net	144,445			275,812			102,202			367,562
Gain on disposition of assets, net	190,987			1,140			215,404			44,736
	1,181,727			917,975			1,971,071			1,794,185
Costs and expenses:
Oil and gas production	179,488			150,081			348,628			281,862
Production and ad valorem taxes	53,837			44,495			108,134			90,291
Depletion, depreciation and amortization	249,590			200,921			480,353			382,339
Impairment of oil and gas properties	—			444,880			—			444,880
Exploration and abandonments	23,973			37,178			51,600			90,465
General and administrative	66,654			54,957			130,405			118,024
Accretion of discount on asset retirement obligations	3,166			2,444			6,319			4,874
Interest	42,805			49,008			93,540			95,866
Other	18,711			30,651			40,060			54,258
	638,224			1,014,615			1,259,039			1,562,859
Income (loss) from continuing operations before income taxes	543,503			(96,640		)	712,032			231,326
Income tax benefit (provision)	(192,029		)	45,086			(251,358		)	(72,617		)
Income (loss) from continuing operations	351,474			(51,554		)	460,674			158,709
Income (loss) from discontinued operations, net of tax	—			12,017			(465		)	22,712
Net income (loss)	351,474			(39,537		)	460,209			181,421
Net income attributable to noncontrolling interests	(14,211		)	(30,855		)	(22,283		)	(37,194		)
Net income (loss) attributable to common stockholders	$	337,263		$	(70,392	)	$	437,926		$	144,227

Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	2.42		$	(0.67	)	$	3.24		$	0.98
Income (loss) from discontinued operations attributable to common stockholders	—			0.10			—			0.18
Net income (loss) attributable to common stockholders	$	2.42		$	(0.57	)	$	3.24		$	1.16
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	2.40		$	(0.67	)	$	3.19		$	0.95
Income (loss) from discontinued operations attributable to common stockholders	—			0.10			—			0.18
Net income (loss) attributable to common stockholders	$	2.40		$	(0.57	)	$	3.19		$	1.13
Weighted average shares outstanding:
Basic	137,539			123,028			133,263			122,754
Diluted	138,829			123,028			135,762			125,772
Dividends declared per share	$	—		$	—		$	0.04		$	0.04

Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	337,263		$	(82,409	)	$	438,391		$	121,515
Income (loss) from discontinued operations, net of tax	—			12,017			(465		)	22,712
Net income (loss)	$	337,263		$	(70,392	)	$	437,926		$	144,227

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,
	2013			2012			2013			2012
Net income (loss)	$	351,474		$	(39,537	)	$	460,209		$	181,421
Other comprehensive activity:
Net hedge losses included in continuing operations	—			2,347			—			4,855
Income tax benefit	—			(797		)	—			(1,725		)
Other comprehensive activity	—			1,550			—			3,130
Comprehensive income (loss)	351,474			(37,987		)	460,209			184,551
Comprehensive income attributable to the noncontrolling interests	(14,211		)	(30,855		)	(22,283		)	(37,194		)
Comprehensive income (loss) attributable to common stockholders	$	337,263		$	(68,842	)	$	437,926		$	147,357

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			Noncontrolling Interests			Total Equity
Balance as of December 31, 2012	123,356		$	1,350	$	3,683,934		$	(510,570	)	$	2,514,640		$	177,954		$	5,867,308
Issuance of common stock	10,350		103		1,280,813			—			—			—			1,280,916
Dividends declared ($0.04 per share)	—		—		—			—			(5,526		)	—			(5,526		)
Exercise of long-term incentive plan stock options	111		—		(1,293		)	5,026			—			—			3,733
Treasury stock purchases	(152	)	—		—			(19,615		)	—			—			(19,615		)
Conversion of 2.875% senior convertible notes	4,381		—		(197,240		)	197,232			—			—			(8		)
Tax benefit related to conversion of 2.875% senior convertible notes	—		—		38,415			—			—			—			38,415
Tax benefit related to stock-based compensation	—		—		6,574			—			—			—			6,574
Compensation costs:
Vested compensation awards, net	499		5		(5		)	—			—			—			—
Compensation costs included in net income	—		—		33,522			—			—			580			34,102
Cash distributions to noncontrolling interests	—		—		—			—			—			(17,951		)	(17,951		)
Net income	—		—		—			—			437,926			22,283			460,209
Balance as of June 30, 2013	138,545		$	1,458	$	4,844,720		$	(327,927	)	$	2,947,040		$	182,866		$	7,648,157

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,
	2013			2012
Cash flows from operating activities:
Net income	$	460,209		$	181,421
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	480,353			382,339
Impairment of oil and gas properties	—			444,880
Exploration expenses, including dry holes	12,293			39,730
Deferred income taxes	233,738			57,291
Gain on disposition of assets, net	(215,404		)	(44,736		)
Accretion of discount on asset retirement obligations	6,319			4,874
Discontinued operations	(158		)	3,597
Interest expense	8,907			18,152
Derivative related activity	(14,488		)	(144,000		)
Amortization of stock-based compensation	34,027			30,970
Amortization of deferred revenue	—			(20,919		)
Other noncash items	(4,706		)	(7,513		)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(32,928		)	33,881
Income taxes receivable	6,520			(1,452		)
Inventories	(679		)	(33,318		)
Prepaid expenses	(10,196		)	(13,425		)
Other current assets	2,537			(8,846		)
Accounts payable	(9,172		)	30,580
Interest payable	(6,620		)	82
Income taxes payable	730			(7,907		)
Other current liabilities	(15,422		)	(20,271		)
Net cash provided by operating activities	935,860			925,410
Cash flows from investing activities:
Proceeds from disposition of assets	675,075			62,945
Payments for acquisition, net of cash acquired	—			(295,974		)
Additions to oil and gas properties	(1,388,180		)	(1,424,807		)
Additions to other assets and other property and equipment, net	(100,591		)	(164,230		)
Net cash used in investing activities	(813,696		)	(1,822,066		)
Cash flows from financing activities:
Borrowings under long-term debt	418,864			1,339,093
Principal payments on long-term debt	(1,322,771		)	(596,000		)
Proceeds from issuance of common stock, net of issuance costs	1,280,916			—
Distributions to noncontrolling interests	(17,951		)	(17,956		)
Payments of other liabilities	(143		)	(744		)
Exercise of long-term incentive plan stock options	3,733			1,008
Purchases of treasury stock	(19,615		)	(56,317		)
Excess tax benefits from share-based payment arrangements	6,574			17,545
Payments of financing fees	(8		)	(4,660		)
Dividends paid	(5,534		)	(5,028		)
Net cash provided by financing activities	344,065			676,941
Net increase (decrease) in cash and cash equivalents	466,229			(219,715		)
Cash and cash equivalents, beginning of period	229,396			537,484
Cash and cash equivalents, end of period	$	695,625		$	317,769

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, 2013

(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 operating in the United States, with field operations in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Barnett Shale Combo play in North Texas, the Raton field in southeastern Colorado, the Hugoton field in southwest Kansas, the West Panhandle field in the Texas Panhandle and in Alaska.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2013 and for the three and six months ended June 30, 2013 and 2012 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 in or omitted from 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, 2012.

Certain reclassifications have been made to the 2012 financial statement and footnote amounts in order to conform to the 2013 presentation.

Issuance of common stock. In February 2013, the Company issued 10.35 million shares of its common stock and realized $1.3 billion of cash proceeds, net of associated underwriting and offering expenses.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest"). The Company owns and controls Pioneer Natural Resources GP LLC (the "General Partner"), which manages Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations and cash flows of Pioneer Southwest are consolidated with those of the Company. Noncontrolling interests in consolidated subsidiaries includes $169.3 million attributable to outstanding Pioneer Southwest common units held by unitholders other than Pioneer or its subsidiaries as of June 30, 2013. See Note C for additional discussion of Pioneer Southwest.

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of the Company acquired an industrial sand mining business that is now called Premier Silica LLC ("Premier Silica"). Premier Silica's primary mine operations are in Brady, Texas. The Brady mine facilities primarily produce, process and provide sand to the Company for use as proppant in its fracture stimulation of oil and gas wells in Texas. Premier Silica's sand production that is in excess of the Company's sand needs for fracture stimulation and sand production that is not usable for fracture stimulation is primarily sold to third parties for industrial and recreational purposes. The aggregate purchase price of Premier Silica was $297.1 million, including closing adjustments.

Divestitures Recorded in Continuing Operations

Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem"), a U.S. subsidiary of the Sinochem Group, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas for total consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $614.5 million, including normal closing adjustments, resulting in a second quarter 2013 pretax gain of $180.9 million. The Company reduced the carrying value of goodwill and the gain recognized associated with the sale by $18.5 million, reflecting the portion of the Company's goodwill that related to the horizontal Wolfcamp Shale assets that were

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sold. Sinochem will pay the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play.

Sales of unproved oil and gas properties. For the three and six months ended June 30, 2013, the Company's pretax gains on disposition of assets from continuing operations of $191.0 million and $215.4 million, respectively, were primarily associated with the Southern Wolfcamp transaction noted above. Additionally, the Company sold (i) its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations during the first quarter of 2013 for net cash proceeds of $38.1 million, which resulted in a pretax gain of $22.4 million, and (ii) its interest in certain unproved oil and gas properties in the Barnett Shale during the second quarter of 2013 for net cash proceeds of $11.2 million, which resulted in a pretax gain of $8.3 million. For the three and six months ended June 30, 2012, the Company's pretax gains on disposition of assets amounted to $1.1 million and $44.7 million, respectively. The Company's gain on disposition of assets during the six months ended June 30, 2012 is primarily associated with the first quarter 2012 sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field for net cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million.

Divestitures Recorded as Discontinued Operations

South Africa. During the first quarter of 2012, the Company agreed to sell its assets in South Africa ("Pioneer South Africa"), effective January 1, 2012, for $60.0 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities associated with the assets. In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a third quarter 2012 pretax gain of $28.6 million. The Company classified Pioneer South Africa's results of operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

For the three and six months ended June 30, 2012, the Company recognized revenues and other income of $20.2 million and $39.8 million, respectively, and pretax earnings of $16.6 million and $34.0 million, respectively, associated with discontinued operations, principally related to the results of operations of Pioneer South Africa prior to its divestiture in August 2012.

Acquisition Proposal

The consummation of the transaction contemplated by the Pioneer Southwest Merger Proposal is subject to approval of the Company's Board of Directors (the "Board"), approval of the Conflicts Committee and the Board of Directors of the General Partner and the negotiation of a definitive agreement. There can be no assurance that a definitive agreement will be executed or that any transaction will be approved or consummated. See Note J for a description of the litigation contingencies associated with the Pioneer Southwest Merger Proposal.

NOTE D. 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.

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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.

The following table presents the Company's assets and liabilities that are measured at fair value as of June 30, 2013:



	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, 2013
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	146	$	146	$	—	$	292
Commodity derivatives	—		329,595		—		329,595
Deferred compensation plan assets	55,997		—		—		55,997
Total assets	56,143		329,741		—		385,884
Liabilities:
Commodity derivatives	—		6,453		—		6,453
Total recurring fair value measurements	$	56,143	$	323,288	$	—	$	379,431

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities that are both actively traded and not actively traded on major exchanges. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of June 30, 2013, substantially all of the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain trading securities that are not actively traded on major exchanges were classified as Level 2 inputs.

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("NGL") and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represent Level 2 inputs in the hierarchy. 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 that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and collar contracts with short puts, which is based on active and independent market-quoted volatility factors.

Assets and liabilities measured at fair value on a nonrecurring basis. 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 six months ended June 30, 2012, reductions in management's longer-term commodity price outlooks

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("Management's Price Outlooks") provided indications of possible impairment of the Company's dry gas properties in the Barnett Shale field in North Texas. As a result of management's assessments, during the second quarter of 2012, the Company recognized a pretax noncash impairment charge of $444.9 million to reduce the carrying value of the Barnett Shale field to its estimated fair value. The Company calculated the estimated fair value of the Barnett Shale field as of June 30, 2012 using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of Barnett Shale field's discounted future cash flows as of June 30, 2012 included Management's Price Outlooks for (i) oil and gas prices of $87.09 per barrel ("BBL") for oil and $4.64 per British thermal unit ("MMBTU") for gas, (ii) production costs, (iii) capital expenditures, (iv) production and (v) estimated proved reserves and risk-adjusted probable reserves. Management's commodity price outlooks represent longer-term outlooks that are developed based on third-party futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

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, 2013 and December 31, 2012 are as follows:



	June 30, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	2,823,428	$	3,197,908	$	3,721,193	$	4,555,770

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 active market-quoted London Interbank Offered Rate ("LIBOR") yield curves (in the case of the Pioneer Southwest credit facility) 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, receivables, prepaid expenses, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their 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 E. Derivative Financial Instruments

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

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

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The following table sets forth the volumes per day in BBLs associated with the Company's outstanding oil derivative contracts as of June 30, 2013 and the weighted average oil prices per BBL for those contracts:



	Six Months Ending December 31,		Year Ending December 31,
	2013		2014		2015		2016
Collar contracts with short puts:
Volume (BBL) (a)	74,250		69,000		32,000		2,000
Price per BBL:
Ceiling	$	120.11	$	114.05	$	103.23	$	94.75
Floor	$	92.21	$	93.70	$	93.13	$	85.00
Short put	$	74.44	$	77.61	$	78.13	$	70.00
Swap contracts:
Volume (BBL) (a)	3,000		—		—		—
Price per BBL	$	81.02	$	—	$	—	$	—
Rollfactor swap contracts:
Volume (BBL) (a)	6,000		15,000		—		—
NYMEX roll price (b)	$	0.43	$	0.38	$	—	$	—
Basis swap contracts:
Cushing to LLS index swap volume (BBL)	1,500		—		—		—
Price per BBL (c)	$	8.53	$	—	$	—	$	—

____________________

(a)

During the period from July 1, 2013 to July 30, 2013, the Company (i) converted collar contracts with short puts for 6,750 BBLs per day of the Company's August through December 2013 production with a ceiling price of $119.70 per BBL, a floor price of $97.07 per BBL and a short put price of $76.07 per BBL into swap contracts for 6,750 BBLs per day of August through December 2013 production with a price of $102.04 per BBL, (ii) entered into additional swap contracts for 10,000 BBLs per day of the Company's 2014 production with a price of $93.87 per BBL, (iii) entered into additional rollfactor swap contracts for 5,000 BBLs per day of the Company's September through December 2013 production with a NYMEX roll price of $1.36 per BBL, (iv) entered into additional rollfactor swap contracts for 4,000 BBLs per day of the Company's 2014 production with a NYMEX roll price of $0.73 per BBL, (v) entered into additional collar contracts with short puts for 33,000 BBLs per day of the Company's 2015 production with a ceiling price of $95.53 per BBL, a floor price of $85.00 per BBL and a short put price of $70.00 per BBL and (vi) entered into additional collar contracts with short puts for 18,000 BBLs per day of the Company's 2016 production with a ceiling price of $93.09 per BBL, a floor price of $85.00 per BBL and a short put price of $70.00 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 Cushing WTI and Louisiana Light Sweet crude ("LLS").

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

The following table sets forth the volumes per day in BBLs associated with the Company's outstanding NGL derivative contracts as of June 30, 2013 and the weighted average NGL prices per BBL for those contracts:



	Six Months Ending December 31,		Year Ending December 31,
	2013		2014
Collar contracts with short puts (a):
Volume (BBL)	1,064		1,000
Price per BBL:
Ceiling	$	105.28	$	109.50
Floor	$	89.30	$	95.00
Short put	$	75.20	$	80.00
Collar contracts (b):
Volume (BBL)	2,500		3,000
Price per BBL:
Ceiling	$	12.68	$	13.72
Floor	$	10.50	$	10.78

____________________


(a)	Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(b)	Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.

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

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The following table sets forth the volumes per day in MMBTUs associated with the Company's outstanding gas derivative contracts as of June 30, 2013 and the weighted average gas prices per MMBTU for those contracts:



	Six Months Ending December 31,			Year Ending December 31,
	2013			2014			2015			2016
Collar contracts with short puts:
Volume (MMBTU)	—			115,000			285,000			20,000
Price per MMBTU:
Ceiling	$	—		$	4.70		$	5.07		$	5.36
Floor	$	—		$	4.00		$	4.00		$	4.00
Short put	$	—		$	3.00		$	3.00		$	3.00
Collar contracts:
Volume (MMBTU)	152,500			—			—			—
Price per MMBTU:
Ceiling	$	6.22		$	—		$	—		$	—
Floor	$	4.98		$	—		$	—		$	—
Swap contracts:
Volume (MMBTU)	169,185			175,000			20,000			—
Price per MMBTU	$	5.07		$	4.02		$	4.31		$	—
Basis swap contracts:
Volume (MMBTU)	162,500			45,082			30,000			—
Price per MMBTU	$	(0.22	)	$	(0.18	)	$	(0.18	)	$	—

Interest rate derivative activities. During the period ended June 30, 2013, the Company terminated its interest rate derivative contracts that locked 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 and received cash proceeds of $482 thousand. During the period from July 1, 2013 to July 30, 2013, the Company entered into interest rate derivative contracts whereby the Company will receive a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.21 percent on a notional amount of $175 million through July 15, 2022.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of June 30, 2013 and December 31, 2012 and therefore all changes in the fair values of its derivative contracts are recognized 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, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty, as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty.

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The aggregate fair value of the Company's derivative instruments reported in the consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:



Fair Value of Derivative Instruments as of June 30, 2013
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	196,651	$	(4,954	)	$	191,697
Commodity price derivatives	Derivatives - noncurrent	$	139,764	$	(1,866	)	137,898
							$	329,595
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	11,407	$	(4,954	)	$	6,453
Commodity price derivatives	Derivatives - noncurrent	$	1,866	$	(1,866	)	—
							$	6,453



Fair Value of Derivative Instruments as of December 31, 2012
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	286,805	$	(7,686	)	$	279,119
Commodity price derivatives	Derivatives - noncurrent	$	61,618	$	(6,361	)	55,257
							$	334,376
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	21,102	$	(7,686	)	$	13,416
Commodity price derivatives	Derivatives - noncurrent	$	8,944	$	(6,361	)	2,583
Interest rate derivatives	Derivatives - noncurrent	$	9,724	$	—		9,724
							$	25,723

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.




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	2013		2012			2013		2012
		(in thousands)
Commodity price derivatives	Derivative gains, net	$	138,179	$	298,471		$	91,996	$	386,601
Interest rate derivatives	Derivative gains, net	6,266		(22,659		)	10,206		(19,039		)
Total		$	144,445	$	275,812		$	102,202	$	367,562

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NOTE F. 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. After an exploratory well has been completed and found oil and gas reserves, a determination may be pending as to whether the oil and gas reserves can be classified as proved. In those circumstances, the Company continues to capitalize the well or project costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. 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, 2013:



	Three Months Ended June 30, 2013			Six Months Ended June 30, 2013
	(in thousands)
Beginning capitalized exploratory costs	$	293,757		$	212,670
Additions to exploratory costs pending the determination of proved reserves	340,542			692,117
Reclassification due to determination of proved reserves	(289,285		)	(552,039		)
Disposition of assets	(87,704		)	(87,704		)
Exploratory well costs charged to exploration expense	(2,309		)	(10,043		)
Ending capitalized exploratory costs	$	255,001		$	255,001

The following table provides an aging, as of June 30, 2013 and December 31, 2012, of capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized for a period greater than one year based on the date drilling was completed:



	June 30, 2013		December 31, 2012
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	126,110	$	190,678
More than one year	128,891		21,992
	$	255,001	$	212,670

Number of projects with exploratory costs that have been suspended for a period greater than one year	2		1

Alaska - Oooguruk. As of June 30, 2013 and December 31, 2012, the Company had $22.4 million and $22.0 million, respectively, of suspended well costs recorded for the K-13 well in the Alaska Oooguruk field. Drilling on the K-13 well was completed during September 2011. During well completion operations, subsurface damages were sustained. The Company has equipment on site with plans to recomplete the well during the second half of 2013. The well may require additional stimulation work that, if required, is expected to be completed during the first quarter of 2014.

Alaska - Nuna. The Company's Nuna project, which has $106.5 million of suspended project costs as of June 30, 2013, includes the Nuna-1 exploration well that was drilled during 2012 to test the Torok formation and a second appraisal well that was drilled and logged during the first quarter of 2013. The Company flow-tested the Nuna-1 well during the second quarter of 2012 and again in the first quarter of 2013. The second appraisal well encountered a mechanical problem and could not be flow-tested before the end of the winter drilling season. The results of the flow-tests on the Nuna-1 well and the log data from the second Nuna

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well are both very encouraging. The Company is currently conducting a front-end engineering design ("FEED") study to evaluate the potential for onshore production facilities to support the project.

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, 2013, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Corporate credit facility. The Company maintains a corporate credit facility (the "Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $1.5 billion that expires in December 2017. As of June 30, 2013, the Company had no outstanding borrowings under the Credit Facility.

Pioneer Southwest credit facility. Pioneer Southwest maintains a Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that has aggregate loan commitments of $300 million that expires in March 2017. As of June 30, 2013, Pioneer Southwest had outstanding borrowings of $176.0 million under the Pioneer Southwest Credit Facility. Pioneer Southwest's borrowing capacity under the Pioneer Southwest Credit Facility is subject to a covenant requiring that Pioneer Southwest maintain a specified ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas assets to total debt, with the variables on which the calculation of net present value is based (including assumed commodity prices and discount rates) being subject to adjustment by the lenders. The net present value covenant limits Pioneer Southwest's available borrowing capacity under the Pioneer Southwest Credit Facility to $99.8 million as of June 30, 2013.

Convertible senior notes. As of December 31, 2012, the Company had $479.9 million of 2.875% Convertible Senior Notes due 2038 ("Convertible Senior Notes") outstanding. During December 2012 and March 2013, respectively, the Company's stock price met the price threshold that causes the Convertible Senior Notes to be convertible for the three months ended March 31, 2013 and June 30, 2013, respectively, at the option of the holders 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 Convertible Senior Notes were issued. In addition, on April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479.1 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479.1 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock during the six months ended June 30, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $845 thousand in principal and interest to redeem all Convertible Senior Notes that remained outstanding.

NOTE H. Incentive Plans

Stock-based compensation

For the three and six months ended June 30, 2013, the Company recorded $25.2 million and $52.8 million, respectively, of stock-based compensation expense for all plans, as compared to $21.7 million and $43.3 million, respectively, for the same periods of 2012. As of June 30, 2013, there was $189.1 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $50.3 million attributable to stock-based awards that are expected to be settled in cash on their vesting date, rather than in equity shares ("Liability Awards"). This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of June 30, 2013 and December 31, 2012, accounts payable – due to affiliates includes $13.7 million and $18.8 million, respectively, of liabilities attributable to Liability Awards.

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(Unaudited)

The following table summarizes the activity that occurred during the six months ended June 30, 2013, for each type of share-based incentive award issued by Pioneer or Pioneer Southwest:



	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, 2012	1,512,762		405,916		91,370		467,486		7,496		102,644
Awards granted	412,080		238,269		94,917		—		—		32,242
Awards vested	(493,153	)	(181,368	)	—		—		(7,496	)	(35,118	)
Options exercised	—		—		—		(111,469	)	—		—
Awards forfeited	(49,103	)	(20,291	)	(10,842	)	(11,085	)	—		—
Outstanding as of June 30, 2013	1,382,586		442,526		175,445		344,932		—		99,768

Postretirement Benefit Obligations

As of June 30, 2013 and December 31, 2012, the Company had $9.1 million and $9.7 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years, and one funded plan that the Company assumed sponsorship for in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of June 30, 2013 or December 31, 2012. The Company's funding policy for the Premier Silica plan is to contribute amounts sufficient to meet legal funding requirements, plus any additional amounts that the Company may determine to be appropriate considering the funded status of the plan, tax deductibility, the cash flow generated by the Company, and other factors. The Company continually reassesses the amount and timing of any discretionary contributions and may elect to make such contributions in future periods.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

(Unaudited)

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Company's asset retirement obligation activity during the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Beginning asset retirement obligations	$	190,861		$	134,314		$	197,754		$	136,742
Liabilities assumed in acquisitions	—			8,515			—			8,515
New wells placed on production	1,296			1,581			2,449			2,411
Changes in estimates (a)	(1,315		)	1,603			(5,597		)	1,603
Dispositions	(231		)	—			(4,310		)	—
Liabilities settled	(2,649		)	(3,054		)	(5,498		)	(8,742		)
Accretion of discount	3,166			2,444			6,319			4,874
Accretion of discount from integrated services (b)	1			54			12			54
Ending asset retirement obligations	$	191,129		$	145,457		$	191,129		$	145,457

_____________________


(a)	The changes in estimates during the three and six months ended June 30, 2013 are attributable to lengthening the economic lives of certain wells, which reduced the present values of the associated asset retirement obligations.


(b)	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 K 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, 2013 and December 31, 2012, the current portions of the Company's asset retirement obligations were $12.6 million and $13.3 million, respectively.

NOTE J. Commitments and Contingencies

The Company is a party to 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.

On May 13, 2013, David Flecker, a purported unitholder of Pioneer Southwest, in connection with the Pioneer Southwest Merger Proposal, filed a class action petition on behalf of Pioneer Southwest's unitholders and a derivative suit on behalf of Pioneer Southwest against Pioneer, Pioneer Natural Resources USA, Inc., the General Partner and the directors of the General Partner, in the 134^th Judicial District of Dallas County, Texas. A similar class action petition and derivative suit was filed against the same defendants on May 20, 2013, in the 160^th Judicial District of Dallas County, Texas, by purported unitholder Vipul Patel.

The class action and derivative complaints allege, among other things, that the consideration offered by Pioneer is unfair and inadequate and that the defendants have breached their duties under the Pioneer Southwest partnership agreement as well as the implied covenant of good faith and fair dealing, and are engaging in self-dealing. Specifically, the lawsuits allege that: (i) the defendants are engaging in self-dealing, are not acting in good faith toward Pioneer Southwest, and have breached and are breaching their duties owed to Pioneer Southwest; (ii) the defendants are failing to properly value Pioneer Southwest and its various assets and operations and are ignoring or are not protecting against the numerous conflicts of interest arising out of the proposed transaction; (iii) the defendants breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process and (iv) Pioneer, Pioneer Natural Resources USA, Inc. and the General Partner have aided and abetted the defendant directors named in the lawsuits for the purpose of advancing their own interests. Based on these allegations, the plaintiffs seek to enjoin the defendants from proceeding with or consummating the merger. To the extent that the merger is implemented before relief is granted, plaintiffs

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

(Unaudited)

seek to have the merger rescinded. The plaintiffs also seek money damages and attorneys' fees. Pioneer has filed a motion to dismiss the Flecker petition due to improper forum.

Pioneer cannot predict the outcome of these or any other lawsuits that might be filed, nor can Pioneer predict the amount of time and expense that will be required to resolve these lawsuits. Pioneer and the other defendants named in the lawsuits intend to defend vigorously against these and any other actions. See Note C for a description of the Pioneer Southwest Merger Proposal.

NOTE K. Interest and Other Income

The following table provides the components of the Company's interest and other income for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Alaskan Petroleum Production Tax credits and refunds (a)	$	6,362		$	—		$	25,770		$	11,846
Equity interest in income of unconsolidated affiliate	2,547			1,104			6,083			1,545
Other income	1,689			592			3,565			2,234
Deferred compensation plan income	355			150			1,982			1,523
Interest income	81			1,260			174			1,317
Income (loss) from vertical integration services (b)	(9,875		)	(3,820		)	(17,100		)	2,729
Total interest and other income	$	1,159		$	(714	)	$	20,474		$	21,194

____________________


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

(b)

Income (loss) from vertical integration services represent net margins that result from Company-provided fracture stimulation, drilling and related service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three and six months ended June 30, 2013, these net margins include $46.9 million and $103.2 million of gross vertical integration revenues, respectively, and $56.8 million and $120.3 million of total vertical integration costs and expenses, respectively. For the same periods in 2012, these net margins include $86.3 million and $161.7 million of gross vertical integration revenues, respectively, and $90.1 million and $159.0 million of total vertical integration costs and expenses, respectively.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

(Unaudited)

NOTE L. Other Expense

The following table provides the components of the Company's other expense for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013		2012
	(in thousands)
Transportation commitment charge (a)	$	8,371	$	9,227		$	17,746	$	17,680
Above market and idle drilling and well services equipment rates (b)	4,944		5,760			8,451		10,746
Other	3,754		5,768			8,321		8,716
Inventory impairment (c)	855		1,262			2,442		7,454
Contingency and environmental accrual adjustments	787		(326		)	2,081		702
Terminated drilling rig contract charges (d)	—		8,960			1,019		8,960
Total other expense	$	18,711	$	30,651		$	40,060	$	54,258

____________________


(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)	Represents valuation charges on excess materials and supplies inventories.


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

NOTE M. Income Taxes

The Company's income tax benefits or provisions attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Current	$	(10,185	)	$	(3,494	)	$	(17,620	)	$	(15,326	)
Deferred	(181,844		)	48,580			(233,738		)	(57,291		)
Income tax benefit (provision)	$	(192,029	)	$	45,086		$	(251,358	)	$	(72,617	)

For each of the three and six months ended June 30, 2013, the Company's effective tax rate, excluding income attributable to the noncontrolling interest, was 36 percent as compared to 35 percent and 37 percent for the same respective periods of 2012. The Company's effective tax rates differ from the U.S. statutory rate of 35 percent primarily due to state income tax apportionments and nondeductible expenses.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2011 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2008. As of June 30, 2013, 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 N. Net Income Per Share

The Company uses the two-class method of calculating net income per share because certain of the Company's and its consolidated subsidiaries' unvested share-based awards qualify as participating securities. Participating securities participate in the Company's dividend or partnership distributions and are assumed to participate in the Company's undistributed income proportionate to their share of the 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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

(Unaudited)

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, such as during the three months ended June 30, 2012, 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.

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, 2013 and 2012:



	Three Months Ended June 30, 2013								Six Months Ended June 30, 2013
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	337,263		$	—	$	337,263		$	438,391		$	(465	)	$	437,926
Participating basic earnings	(4,584		)	—		(4,584		)	(5,586		)	—			(5,586		)
Basic net income (loss) attributable to common stockholders	332,679			—		332,679			432,805			(465		)	432,340
Reallocation of participating earnings	73			—		73			124			—			124
Diluted income (loss) attributable to common stockholders	$	332,752		$	—	$	332,752		$	432,929		$	(465	)	$	432,464



	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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2013

(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, 2013 and 2012:



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
	(in thousands)
Weighted average common shares outstanding:
Basic	137,539	123,028	133,263	122,754
Dilutive common stock options (a)	137	—	147	205
Convertible Senior Notes dilution (a)	954	—	2,193	2,642
Contingently issuable performance unit shares (a)	199	—	159	171
Diluted	138,829	123,028	135,762	125,772

____________________

(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. For the three and six months ended June 30, 2013, options to purchase 5,707 and 52,263 shares of the Company's common stock, respectively, were excluded from the diluted income per share calculations because they would have been anti-dilutive to the calculations.

NOTE O. Subsequent Event

In July 2013, Pioneer Southwest declared a cash distribution of $0.52 per common unit for the period from April 1 to June 30, 2013. The distribution is payable on August 9, 2013 to unitholders of record at the close of business on August 2, 2013. 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 2013 included the following highlights:

•

Net income attributable to common stockholders for the second quarter of 2013 was $337.3 million ($2.40 per diluted share), as compared to a net loss of $70.4 million ($0.57 per diluted share) for the second quarter of 2012. The increase in net income attributable to common stockholders is comprised of a $403.0 million increase in net income from continuing operations and a $16.6 million decline in net income attributable to noncontrolling interests, partially offset by a $12.0 million decline in income from discontinued operations, net of tax, as a result of completing the sale of Pioneer South Africa during the third quarter of 2012. The primary components of the increase in net income from continuing operations include:


▪	a $444.9 million decrease in pretax charges for impairment of oil and gas properties related to the Barnett Shale impairment recorded in the second quarter of 2012;


▪	a $203.4 million increase in oil and gas revenues as a result of an increase in sales volumes and average oil and gas prices, partially offset by lower average NGL prices; and


▪	a $180.9 million gain associated with the sale of 40 percent of Pioneer's interest in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field (see further discussion below and in Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Results of Operations"); partially offset by


▪	a $237.1 million increase in the Company's income tax provision;


▪	a $131.4 million decrease in net derivative gains as a result of cash settlements and changes in forward commodity prices and the Company's portfolio of derivatives;


▪	a $48.7 million increase in DD&A expense, primarily due to increased sales volumes and an increase in the carrying value of proved oil and gas properties; and


▪	a $29.4 million increase in oil and gas production costs, primarily due to higher sales volumes, increases in lease operating expenses due to inflation of field services costs and higher workover activities in Alaska.


•	During the second quarter of 2013, average daily sales volumes from continuing operations increased by 17 percent to 176,211 BOEPD, as compared to 150,506 BOEPD during the second quarter of 2012. The increase in second quarter 2013 average daily sales volumes, as compared to the second quarter of 2012, was primarily due to the Company's successful drilling program.


•	Average reported oil and gas prices increased during the second quarter of 2013 to $90.82 per BBL and $3.74 per MCF, respectively, as compared to $88.32 per BBL and $2.00 per MCF, respectively, in the second quarter of 2012. Average reported NGL prices decreased during the second quarter of 2013 to $28.19 per BBL, as compared to $32.62 per BBL in the second quarter of 2012.


•	Average oil and gas production costs per BOE increased to $11.20 for the second quarter of 2013, as compared to $10.96 for the second quarter of 2012, primarily due to the aforementioned inflation of field services costs and Alaskan workover activities.


•	Net cash provided by operating activities increased to $575.8 million for the three months ended June 30, 2013, as compared to $499.3 million for the three months ended June 30, 2012. The $76.5 million increase in net cash provided by operating activities is primarily due to an increase in oil and gas sales, partially offset by a decrease in realized derivative gains.

•

In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for total consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $614.5 million, including normal closing adjustments, resulting in a second quarter 2013 pretax gain of $180.9 million. Sinochem will pay the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play.


•	In April 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013 for cash at a price equal to the full principal amount plus accrued and unpaid interest, in accordance with the indenture agreement. During the three months ended June 30, 2013, the

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PIONEER NATURAL RESOURCES COMPANY

Company paid $217.8 million of cash and issued 2.0 million shares of the Company's common stock to the tendering holders of the Convertible Senior Notes during the three months ended June 30, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $845 thousand in principal and interest to redeem all Convertible Senior Notes that remained outstanding. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Convertible Senior Notes.

•

As of June 30, 2013, the Company's net debt to book capitalization declined to 22 percent, as compared to 37 percent as of December 31, 2012, principally reflective of an increase in cash and cash equivalents of $466.2 million and a decrease in long-term debt of $897.8 million. These changes primarily resulted from the application of net cash proceeds from the February 2013 sale of 10.35 million shares of common stock and the May 2013 completion of the Wolfcamp joint venture with Sinochem.

Recent Developments

On May 7, 2013, the Company delivered a proposal to the chairman of the Conflicts Committee to acquire all of the outstanding common units of Pioneer Southwest held by unitholders other than Pioneer or its subsidiaries for consideration of .2234 of a share of common stock of Pioneer for each outstanding common unit of Pioneer Southwest held by such unitholders in a transaction to be structured as a merger of Pioneer Southwest with a wholly-owned subsidiary of Pioneer. The Company's proposal was made based on the assumption that Pioneer Southwest would declare and pay the distribution for the period April 1, 2013 to June 30, 2013 (which was declared in July 2013 and is to be paid on August 9, 2013, to unitholders of record on August 2, 2013) and then suspend future common unit distributions pending the execution of a definitive agreement and the consummation of a transaction. The consummation of the transaction contemplated by the Pioneer Southwest Merger Proposal is subject to approval of the Board, approval of the Conflicts Committee and the Board of Directors of the General Partner and the negotiation of a definitive agreement. There can be no assurance that a definitive agreement will be executed or that any transaction will be approved or consummated.

The consolidation of the properties of Pioneer and Pioneer Southwest in the Midland Basin in West Texas through this proposed transaction would facilitate the Company's plans to fully and optimally develop the area utilizing horizontal drilling and would provide organizational, operational and administrative efficiencies. Pioneer owns 100 percent of the General Partner and owns approximately 52.4 percent of the 35,713,700 outstanding common units of Pioneer Southwest. See Notes B, C and J of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about Pioneer Southwest and for descriptions of litigation contingencies associated with the Pioneer Southwest Merger Proposal.

Third Quarter 2013 Outlook

Based on current estimates, the Company expects the following operations and financial results for the quarter ending September 30, 2013:

Production is forecasted to average 174,000 to 179,000 BOEPD during the third quarter of 2013, reflecting an expectation that third quarter production will be impacted by (i) the continuation of ethane rejection in the Spraberry field as a result of low ethane prices, (ii) the sale to Sinochem in May 2013 of a portion of the Company's interest in its Wolfcamp Shale properties in the southern portion of the Spraberry field and (iii) the timing of placing new horizontal wells on production associated with lower cost pad drilling, which is expected to be weighted towards the end of the third quarter and during the fourth quarter. As a result, fourth quarter 2013 production is forecasted to increase to 185,000 to 195,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $14.00 to $16.00 per BOE based on current NYMEX strip commodity prices. DD&A expense is expected to average $14.50 to $16.50 per BOE.

Total exploration and abandonment expense is expected to be $25 million to $35 million. General and administrative expense is expected to be $65 million to $70 million. Interest expense is expected to be $43 million to $48 million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.

Noncontrolling interest in consolidated subsidiaries' net income, excluding noncash mark-to-market adjustments, is expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company's effective income tax rate, excluding the effect of net income attributable to noncontrolling interest, is expected to range from 35 percent to 40 percent assuming current capital spending plans and no significant mark-to-market changes in the Company's derivative position. Cash income taxes are expected to range from $10 million to $15 million and are primarily attributable to federal 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, 2013:



	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	52,710	13,793	74,251	78,878
South Texas - Eagle Ford Shale	13,307	10,172	84,525	37,567
Raton Basin	—	—	137,219	22,870
Mid-Continent	3,051	6,626	40,558	16,437
Barnett Shale	1,404	3,111	24,110	8,534
South Texas - Edwards and Austin Chalk	75	1	31,407	5,311
Alaska	3,959	—	—	3,959
Other	3	3	58	14
	74,509	33,706	392,128	173,570

During 2013 and 2012, the Company has focused its capital budgets and expenditures on oil and liquids-rich-gas drilling activities due to low gas prices. As a result of these capital activities, the Company's total liquids production from continuing operations increased to 62 percent of total production, on a BOE basis, for the six months ended June 30, 2013, as compared to 58 percent for the same period last year. Despite the increase in liquids production, the Company's liquids revenue, as a percent of total commodity sales, decreased to 85 percent for the six months ended June 30, 2013, as compared to 89 percent for the same period last year, due to a 53 percent increase in the average reported gas prices and declines of five percent and 21 percent in reported oil and NGL prices, respectively, as compared to the six months ended June 30, 2012.

The following table summarizes by geographic area the Company's finding and development costs incurred during the six months ended June 30, 2013:



	Acquisition Costs				Exploration		Development		Asset Retirement
	Proved		Unproved		Costs		Costs		Obligations			Total
	(in thousands)
Permian Basin	$	623	$	18,028	$	368,258	$	586,978	$	1,212		$	975,099
South Texas - Eagle Ford Shale	1		930		207,798		73,032		764			282,525
Raton Basin	—		—		3,351		2,148		—			5,499
Mid-Continent	—		105		1,374		2,570		—			4,049
Barnett Shale	3,188		4,539		69,335		17,059		279			94,400
South Texas - Edwards and Austin Chalk	—		—		2,959		1,037		—			3,996
Alaska	—		—		50,724		85,823		(5,449		)	131,098
Other	11		847		16,369		1		44			17,272
	$	3,823	$	24,449	$	720,168	$	768,648	$	(3,150	)	$	1,513,938

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the Company's development and exploration/extension drilling activities for the six months ended June 30, 2013:



	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	136	145	230	—	51
South Texas - Eagle Ford Shale	11	17	14	—	14
Barnett Shale	—	3	—	—	3
Alaska	4	2	3	—	3
	151	167	247	—	71



	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	17	64	44	—	37
South Texas - Eagle Ford Shale	21	54	46	—	29
South Texas - Edwards and Austin Chalk	—	1	1	—	—
Barnett Shale	9	23	16	6	10
Alaska	2	1	—	—	3
Other	—	5	—	—	5
	49	148	107	6	84

Permian Basin area. The Company completed 274 wells in the Permian Basin area during the first six months of 2013, all of which were successful.

The Company currently has 27 rigs operating in the Spraberry field, of which 15 are drilling vertical wells and 12 are drilling horizontal wells. During 2013, the Company expects to drill approximately 290 vertical wells and 120 horizontal wells, with the horizontal wells being drilled in three Wolfcamp Shale intervals and three Spraberry Shale intervals. Excluding the southern joint venture area, the Company expects to incur $1.2 billion of drilling capital in the Spraberry field during 2013.

The Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Spraberry and Wolfcamp A, B, C and D intervals and its drilling results to-date. The Company's horizontal drilling activity for 2013 will be focused on both the northern and southern portions of the play. During 2013, the Company expects to spud 30 to 40 horizontal wells in the northern portion of the play and 86 horizontal wells in the southern portion of the play.

During the fourth quarter of 2012, the Company initiated horizontal Wolfcamp Shale drilling activities to delineate the northern portion of its Spraberry acreage position. Wells drilled in the northern portion of the play are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths. In addition, during 2013, the Company plans to drill several Spraberry Shale and Jo Mill horizontal wells. The Company is utilizing five horizontal rigs in its northern acreage during the remainder of 2013 to delineate the area's resource potential.

Specifically, the Company's five-rig northern Spraberry drilling program is currently focused in Midland and Martin counties and consists of three rigs drilling Wolfcamp Shale wells and two rigs drilling Jo Mill and Spraberry Shale wells. During the third quarter of 2013, the Company is planning to move two of the northern rigs to Andrews County and drill the Company's first Wolfcamp and Spraberry Shale interval wells in that area. Current plans are for all wells to be drilled on two-well pads to gain efficiencies; therefore, the wells will not be completed until after the second well on each pad is drilled and accordingly production from these wells is not expected until later in the year.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval, including the Strawn and Atoka intervals. The 2013 drilling program reflects 90 percent of the vertical wells being deepened below the Wolfcamp interval. Based on results to-date, the Company estimates that 85 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.

In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $614.5 million, including normal closing adjustments, resulting in a second quarter 2013 pretax

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gain of $180.9 million. Sinochem will pay the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play.

The Company and Sinochem have agreed to a plan to drill 86 horizontal Wolfcamp Shale wells during 2013, 120 wells in 2014 and 165 wells in 2015. Associated therewith, the Company expects to incur $425.0 million of drilling and facilities capital during 2013. Sinochem elected to participate in certain vertical wells that were drilled in the joint interest area after the December 1, 2012 effective date and received its share of production and costs from the Wolfcamp and deeper horizons based on the reserve contribution from the Wolfcamp and deeper intervals relative to reserves from all completed intervals. Pioneer's and Sinochem's participation in vertical wells is based on each party's interest without any drilling carry applied. Pioneer retained 100 percent of its vertical production in the joint interest area for wells drilled before the December 1, 2012 effective date. Pioneer also retained its current working interests in all horizons shallower than the Wolfcamp horizon and continues as operator of the properties in the joint interest area.

During the second quarter of 2013, the Company placed 22 new horizontal wells on production in the southern joint venture area. During 2013, the Company has lowered its well costs by utilizing slickwater fracture stimulation techniques, cheaper hybrid fracture stimulation techniques and pad drilling.

The Company continues to expand its integrated services to control drilling and operating costs and support the execution of its drilling and production activities in the Spraberry field. The Company owns 15 vertical drilling rigs and is presently utilizing four Company-owned vertical fracture stimulation fleets totaling approximately 80,000 horsepower and three Company-owned horizontal fracture stimulation fleets totaling approximately 90,000 horsepower 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, Premier Silica (the Company's wholly-owned sand mining subsidiary) is supplying the majority of the Company's brown sand requirements for proppant that is being used to fracture stimulate vertical and horizontal wells in the Spraberry and Wolfcamp Shale intervals.

Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2013 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2013 drilling program has been focused on liquids-rich drilling, with less than 10 percent of the wells designated to hold strategic dry gas acreage.

The Company completed 60 horizontal Eagle Ford Shale wells during the first six months of 2013, all of which were successful, with average lateral lengths of approximately 5,100 feet and, on average, 14-stage fracture stimulations. The Company plans to incur $575 million of drilling capital and utilize 10 drilling rigs in 2013 to drill approximately 130 Eagle Ford Shale wells. The Company plans to primarily use two Pioneer-owned fracture stimulation fleets during 2013 in the Eagle Ford Shale area.

The Company's drilling operations in the Eagle Ford Shale continue to focus on improving drilling efficiencies. The number of wells drilled from pads, as opposed to single-well locations, is expected to increase from about 45 percent of the Eagle Ford Shale wells during 2012 to about 80 percent in 2013, reflecting that most of the Company's acreage is now held by production. Pad drilling saves the Company a significant amount of capital costs per well, as compared to single-well location drilling.

The Company has been using lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. The Company is expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company fracture stimulated 39 wells with white sand proppant in the first half of 2013, with significant capital savings per well. The Company is continuing to monitor the performance of these wells and expects that greater than 75 percent of its 2013 drilling program will use lower-cost white sand proppant.

The unconsolidated affiliate formed by the Company to operate gathering facilities in the Eagle Ford Shale area, EFS Midstream LLC ("EFS Midstream"), is obligated to construct midstream assets in the Eagle Ford Shale area. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term.

Barnett Shale. The Company completed 22 Barnett Shale Combo wells during the first six months of 2013, of which 16 were successful. The Company increased from one drilling rig to two drilling rigs late in the first quarter. During 2013, the Company expects to drill 55 wells in 2013 and incur capital expenditures of $185.0 million.

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 20 production wells and ten injection wells to develop this project. During the first quarter of 2012, the Company drilled the Nuna-1 exploration well from an onshore location to evaluate the productivity of the Torok formation and the feasibility of future development expansion. The Company flow-tested the well during April 2012 until

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production could no longer be transported along the ice road being utilized. During the first quarter of 2013, the Company re-entered and performed a second flow-test of the well at a facility-limited average rate of approximately 2,800 BOEPD. In addition, the Company drilled and logged a second appraisal well in the Torok formation to further evaluate its resource potential. The second appraisal well encountered a mechanical problem and could not be flow-tested before the end of the winter drilling season. The results of the flow-tests on the Nuna-1 well and the log data from the second Nuna well are both encouraging. The Company is currently conducting a front-end engineering design ("FEED") study to evaluate the potential for onshore production facilities to support the project.

The Company completed three Oooguruk development wells during the six months ended June 30, 2013, which were successful. The Company also successfully completed mechanically-diverted fracture stimulations of four wells from the Oooguruk island facilities during the first half of 2013. The remaining well is in the Torok interval. It encountered a mechanical problem requiring additional remediation, which is scheduled to occur in the second half of 2013. The Company plans to incur $190 million of capital expenditures in Alaska during 2013.

See Note F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information about the Company's exploration projects in Alaska.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $845.1 million and $1.6 billion, respectively, for the three and six months ended June 30, 2013, respectively, as compared to $641.7 million and $1.4 billion for the same respective periods in 2012.

The increase in oil and gas revenues during the three months ended June 30, 2013, as compared to the same period in 2012, is reflective of 22 percent, 28 percent and seven percent increases in daily oil, NGL and gas sales volumes, respectively, and three percent and 87 percent increases in reported average oil and gas prices, respectively. Partially offsetting the effects of these increases was a decline of 14 percent in reported average NGL prices. The increase in oil and gas revenues during the six months ended June 30, 2013, as compared to the same period in 2012, is reflective of 25 percent, 24 percent and six percent increases in daily oil, NGL and gas sales volumes, respectively, and a 53 percent increase in average reported gas prices. Partially offsetting the effects of these increases were declines of five percent and 21 percent in average reported oil and NGL prices, respectively.

The following table provides average daily sales volumes for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Oil (BBLs)	75,074	61,428	74,509	59,550
NGLs (BBLs)	34,415	26,960	33,706	27,222
Gas (MCF)	400,329	372,713	392,128	371,068
Total (BOE)	176,211	150,506	173,570	148,617

Average daily BOE sales volumes increased by 17 percent for both the three and six months ended June 30, 2013, as compared to the same respective periods in 2012, principally due to the Company's successful drilling programs.

Production for the three and six months ended June 30, 2013 was negatively impacted by gas processing capacity limitations in the Spraberry field as a result of wet gas production for the Company and other industry participants growing faster than anticipated. New Spraberry field gas processing facilities were completed and began processing gas in mid-April 2013, which eliminated the Spraberry gas processing capacity limitations. Production for the three months ended June 30, 2013 was negatively impacted by (i) ethane rejection during a portion of the second quarter as a result of low ethane prices, which made it economically preferable to leave the ethane in gas sales and (ii) the May 2013 sale of 40 percent of the Company's interest in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas. The gas processing capacity limitations and ethane rejection resulted in reduced recoveries of ethane, negatively impacting sales volumes by approximately 1,400 BOEPD and 2,000 BOEPD for the three and six months ended June 30, 2013, respectively. The May 2013 sale of 40 percent of the Company's interest in the southern Wolfcamp Shale joint venture area negatively impacted sales volumes by approximately 1,300 BOEPD and 700 BOEPD for the three and six months ended June 30, 2013, respectively.

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The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities. The following table provides the Company's average prices for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012 (a)		2013		2012 (a)
Oil (per BBL)	$	90.82	$	88.32	$	89.71	$	94.45
NGL (per BBL)	$	28.19	$	32.62	$	29.25	$	37.26
Gas (per MCF)	$	3.74	$	2.00	$	3.45	$	2.26
Total (per BOE)	$	52.71	$	46.86	$	51.98	$	50.31

____________________

(a)

For the three and six months ended June 30, 2012, the Company's average realized oil prices per BBL were $86.67 and $92.81, respectively, and the average realized total prices per BOE for the three and six months ended June 30, 2012 were $46.26 and $49.65, respectively. The average realized prices do not include the impact of transfers of the Company's deferred hedge losses, net from Accumulated Other Comprehensive Income from hedging activities ("AOCI-Hedging") and the amortization of deferred volumetric production payment ("VPP") revenue. 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 gains from AOCI-Hedging to oil revenue, representing all remaining AOCI-Hedging transfers to earnings. Amortization of deferred VPP revenue increased oil revenues by $10.4 million and $20.9 million during the three and six months ended June 30, 2012. As of December 31, 2012, all VPP production volumes had been delivered and there were no further obligations under VPP contracts or deferred revenue.

Interest and other income. Interest and other income for the three months ended June 30, 2013 was $1.2 million, as compared to a loss in interest and other income of $714 thousand for the same period in 2012. Interest and other income for the six months ended June 30, 2013 was $20.5 million, as compared to $21.2 million for the same period in 2012. The $1.9 million increase in interest and other income during the three months ended June 30, 2013, as compared to the same period in 2012, was primarily due to $6.4 million of Alaskan PPT credit recoveries during the second quarter of 2013 and a $1.4 million increase in equity in earnings of EFS Midstream, partially offset by a $6.1 million increase in losses from vertical integration services as a result of the Company not fully utilizing its vertical integration services capacity, and a $1.2 million decrease in interest income. The $720 thousand decrease in interest and other income during the six months ended June 30, 2013, as compared to the same period in 2012, was primarily due to a $19.8 million decrease in earnings from third-party vertical integration services, primarily due to under-utilized services capacity, partially offset by a $13.9 million increase in Alaskan PPT credit recoveries and a $4.5 million increase in equity in earnings of EFS Midstream. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding interest and other income.

Derivative gains, net. 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 months ended June 30, 2013, the Company recorded $144.4 million of net derivative gains on commodity price and interest rate derivatives, of which $110.4 million represented unrealized net gains and $34.0 million represented realized net gains. During the six months ended June 30, 2013, the Company recorded $102.2 million of net derivative gains on commodity price and interest rate derivatives, of which $14.5 million represented unrealized net gains and $87.7 million represented realized net gains. During the three and six months ended June 30, 2012, the Company recorded $275.8 million and $367.6 million of net derivative gains, respectively. Derivative gains and losses result from changes in the fair values of the Company's derivative contracts. See Notes D and E 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.

Gain on disposition of assets, net. The Company recorded net gains on the disposition of assets of $191.0 million and $215.4 million, respectively, during the three and six months ended June 30, 2013, as compared to $1.1 million and $44.7 million, respectively, for the same respective periods of 2012. In May 2013, the Company completed the sale of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas to Sinochem for net cash proceeds of $614.5 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of sale, resulting in a second quarter 2013 pretax gain of $180.9 million. The net gains for the three months ended June 30, 2013 are also associated with the sale of the Company's interest in certain unproved oil and gas properties in the Barnett Shale for net cash proceeds of $11.2 million, which resulted in a pretax gain of $8.3 million. The net gains for the six months ended June 30, 2013 also included the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38.1 million, which resulted in a pretax gain of $22.4 million. The net gain for the three months ended June 30, 2012 is primarily associated with sales of transportation equipment, while the

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net gain for the six months ended June 30, 2012 includes the first quarter sale of a portion of the Company's interest in an unproved oil and gas property in the Eagle Ford Shale field for net cash proceeds of $54.7 million, which resulted in a pretax gain of $42.6 million. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's gains and losses on the disposition of assets.

Oil and gas production costs. The Company recorded oil and gas production costs of $179.5 million and $348.6 million, respectively, during the three and six months ended June 30, 2013 as compared to $150.1 million and $281.9 million, respectively, during the same respective periods in 2012. 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, 2013 increased by two percent and six percent, respectively, as compared to the same respective periods in 2012. The increase in production costs per BOE during the three and six months ended June 30, 2013, as compared to the same respective periods in 2012, is primarily reflective of increases in (i) lease operating expenses due to inflation of field services costs, (ii) workover expenses related to workover activities in Alaska and (iii) third-party transportation charges due to a higher proportion of the Company' production coming from the Eagle Ford Shale area that is subject to transportation charges, offset by (iv) lower net natural gas plant charges resulting from increased gathering and processing revenues from processing third-party gas in Company-owned facilities.

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, 2013 and 2012:



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Lease operating expenses	$	8.20	$	8.07	$	8.27	$	7.89
Third-party transportation charges	1.57		1.29		1.62		1.27
Net natural gas plant charges	0.09		0.64		0.13		0.44
Workover costs	1.34		0.96		1.08		0.83
Total production costs	$	11.20	$	10.96	$	11.10	$	10.43

Production and ad valorem taxes. The Company's production and ad valorem taxes were $53.8 million and $108.1 million during the three and six months ended June 30, 2013, respectively, as compared to $44.5 million and $90.3 million, respectively, for the same respective periods in 2012. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices.

The following table provides the Company's production and ad valorem taxes per BOE for the three and six months ended June 30, 2013 and 2012:



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Production taxes	2.01		1.81		$	2.06	$	2.07
Ad valorem taxes	$	1.35	$	1.44	1.38		1.27
Total production and ad valorem taxes	$	3.36	$	3.25	$	3.44	$	3.34

Depletion, depreciation and amortization expense. The Company's DD&A expense was $249.6 million ($15.57 per BOE) and $480.4 million ($15.29 per BOE) for the three and six months ended June 30, 2013, respectively, as compared to $200.9 million ($14.67 per BOE) and $382.3 million ($14.14 per BOE), respectively, during the same respective periods in 2012. The increase in per BOE DD&A expense during the three and six months ended June 30, 2013, as compared to the same respective periods of 2012, is primarily due to increases in depletion expense on oil and gas properties.

Depletion expense on oil and gas properties was $14.89 and $14.62 per BOE during the three and six months ended June 30, 2013, respectively, as compared to $14.05 and $13.53 per BOE during the same respective periods in 2012. The six percent and eight percent increases in per BOE depletion expense during the three and six months ended June 30, 2013, respectively, as compared to the same respective periods in 2012, are primarily due to capital expenditures to develop proved undeveloped locations,

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primarily in the Spraberry and Eagle Ford Shale fields, partially offset by the impairment effects of reducing the carrying value of proved properties for the Barnett Shale field during 2012.

Impairment of oil and gas properties. The Company performs assessments of its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.

Management's Price Outlooks represent longer-term outlooks that are developed based on observable third-party futures price outlooks as of a measurement date. During the second quarter of 2012, declines in Management's Price Outlooks provided indications of possible impairment of the Company's dry gas properties in the Barnett Shale field in North Texas. As a result of management's assessments, during the second quarter of 2012, the Company recognized pretax noncash impairment charges of $444.9 million to reduce the carrying value of the Barnett Shale field.

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 Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.

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, 2013 and 2012 (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Geological and geophysical	$	19,531	$	24,391	$	39,154	$	50,426
Exploratory dry holes	2,309		1,409		10,043		28,286
Leasehold abandonments and other	2,133		11,378		2,403		11,753
	$	23,973	$	37,178	$	51,600	$	90,465

The Company's geological and geophysical costs decreased by $4.9 million and $11.3 million during the three and six months ended June 30, 2013, respectively, as compared to the same respective periods in 2012, primarily as a result of decreased seismic and seismic interpretation expenditures supportive of drilling activities in the Spraberry field. During the three months ended June 30, 2013, the Company's exploratory dry holes increased by $900 thousand, as compared to the same period in 2012, primarily due to dry hole provisions associated with exploration wells drilled in the Barnett Shale field in 2013. During the six months ended June 30, 2013, the Company's exploratory dry holes decreased by $18.2 million, as compared to the same period in 2012, primarily due to dry hole provisions of $20.2 million related to an unsuccessful exploration well in Alaska that was drilled during the first quarter of 2012. The Company's unproved acreage abandonments for the three and six months ended June 30, 2013 decreased by $9.2 million and $9.4 million, respectively, as compared to the same respective periods in 2012, due to decreased abandonments associated with the Raton area, the South Texas Austin Chalk field and the Spraberry field.

During the six months ended June 30, 2013, the Company drilled and evaluated 113 exploration/extension wells, 107 of which were successfully completed as discoveries. During the same period in 2012, the Company drilled and evaluated 98 exploration/extension wells, 92 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and six months ended June 30, 2013 was $66.7 million and $130.4 million, respectively, as compared to $55.0 million and $118.0 million, respectively, for the same respective periods in 2012. The increase in general and administrative expense for the three months ended June 30, 2013, as compared to the same period in 2012, is primarily due to a $10.7 million increase in compensation expenses related to staffing increases in support of the Company's capital expansion initiatives. The increase in general and administrative expense for the six months ended June 30, 2013, as compared to the same period in 2012, is primarily attributable to an increase of $19.3 million in compensation expenses related to staffing increases in support of the Company's capital expansion initiatives, partially offset by decreases in benefits and legal expenses of $2.6 million and $1.8 million, respectively.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $3.2 million and $6.3 million for the three and six months ended June 30, 2013, respectively, as compared to $2.4 million and $4.9 million during the same respective periods in 2012. See Note I of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

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Interest expense. Interest expense was $42.8 million and $93.5 million for the three and six months ended June 30, 2013, respectively, as compared to $49.0 million and $95.9 million, respectively, during the same respective periods in 2012. The weighted average interest rates on the Company's indebtedness for the three and six months ended June 30, 2013, including the effects of capitalized interest, were 6.1 percent and 6.0 percent, respectively, as compared to 6.2 percent and 6.8 percent, respectively, for the same respective periods in 2012. Interest expense decreased by $6.2 million and $2.4 million during the three and six months ended June 30, 2013, respectively, as compared to the same respective periods in 2012. The decrease in interest expense during the three months ended June 30, 2013, as compared to the same period of 2012, was primarily due to a decrease in debt, related to repayment of amounts outstanding under the Credit Facility and conversions of Convertible Senior Notes and a decrease of $4.2 million in noncash amortization of financing fees and debt issuance discounts. The decrease in interest expense during the six months ended June 30, 2013, as compared to the six months ended June 30, 2012, was primarily due to a decrease in debt, related to repayment of amounts outstanding under the Credit Facility and conversions of Convertible Senior Notes, and a decrease of $9.2 million in noncash amortization of financing fees, debt issuance discounts and deferred hedge losses, partially offset by an increase in cash interest expense paid on senior notes of $5.7 million. See Note G of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding conversions of the Company's Convertible Senior Notes during the first six months of 2013.

Other expense. Other expense for the three and six months ended June 30, 2013 was $18.7 million and $40.1 million, respectively, as compared to $30.7 million and $54.3 million, respectively, for the same respective periods in 2012. The decrease in other expense for the three months ended June 30, 2013, as compared to the same period in 2012, is primarily attributable to a $9.0 million decrease in rig contract termination fees. The decrease in other expense for the six months ended June 30, 2013, as compared to the same period in 2012, is primarily attributable to a $7.9 million decrease in rig contract termination fees, a $5.0 million decrease in inventory valuation charges and a $2.3 million decrease in charges recorded associated with contracted rig rates that exceeded market rig rates that are not chargeable to joint operations and idle rig and fracture stimulation equipment charges. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision. The Company recorded an income tax provision from continuing operations of $192.0 million and $251.4 million for the three and six months ended June 30, 2013, respectively, as compared to an income tax benefit 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. The Company's effective tax rates, excluding net income attributable to noncontrolling interests, for the three and six months ended June 30, 2013 were each 36 percent. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.

Income/loss from discontinued operations, net of tax. The Company reported nil and a loss of $465 thousand from discontinued operations, net of tax, for the three and six months ended June 30, 2013, respectively, as compared to income from discontinued operations, net of tax, of $12.0 million and $22.7 million, respectively, for the same respective periods in 2012. The decrease in earnings from discontinued operations is primarily the result of completing the sale of Pioneer South Africa during the third quarter of 2012. See Note C of the Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to the noncontrolling interests for the three and six months ended June 30, 2013 was $14.2 million and $22.3 million, respectively, as compared to $30.9 million and $37.2 million, respectively, for the same respective periods of 2012. The $16.7 million and $14.9 million decreases in income attributable to noncontrolling interests for the three and six months ended June 30, 2013, respectively, as compared to the same respective periods in 2012, are primarily due to decreases in Pioneer Southwest's mark-to-market derivative gains, higher production costs and higher depletion expense, partially offset by increased revenues.

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, cash and cash equivalents on hand, proceeds from the sale of joint interests and nonstrategic assets or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2013 is focused on oil and liquids-rich-gas drilling activities with total expenditures of $3.0 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), consisting of $2.75 billion for drilling operations, including budgeted land capital for existing assets, and $240 million for buildings and vertical integration additions. Based on results for the six months ended June 30, 2013 and Management's Price Outlook, the Company expects its cash flows from operating activities, cash and cash equivalents on hand,

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proceeds from asset sales and/or joint ventures and availability under its Credit Facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2013.

Investing activities. Investing activities used $813.7 million of cash during the six months ended June 30, 2013, as compared to $1.8 billion of cash used in investing activities during the six months ended June 30, 2012. The $1.0 billion decrease in cash used in investing activities for the six months ending June 30, 2013, as compared to the six months ended June 30, 2012, is primarily due to (i) a $612.1 million increase in proceeds from the disposition of assets, including $614.5 million of net cash proceeds, including normal closing adjustments, from the sale of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas, (ii) a $296.0 million decrease in payments for acquisitions due to the acquisition of Premier Silica during 2012, (iii) a $63.6 million decrease in additions to other assets and other property and equipment and (iv) a $36.6 million decrease in additions to oil and gas properties. During the six months ended June 30, 2013, the Company's expenditures for investing activities were funded by net cash provided by operating activities and a portion of the proceeds from the February issuance of 10.35 million shares of the Company's common stock.

Dividends/distributions. During February of both 2013 and 2012, 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 2013 and April 2013, the Pioneer Southwest board of directors (the "Pioneer Southwest Board") declared quarterly distributions of $0.52 per limited partner unit, compared to the quarterly distribution of $0.51 and $0.52 per limited partner unit declared in January 2012 and April 2012, respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $17.7 million and $17.5 million during the six months ended June 30, 2013 and 2012, respectively. During July 2013, the Pioneer Southwest Board declared a quarterly distribution of $0.52 per limited partner unit for unitholders of record on August 2, 2013, payable August 9, 2013.

On May 7, 2013, the Company delivered a proposal to the chairman of the Conflicts Committee (the "Conflicts Committee") of the General Partner to acquire all of the outstanding common units of Pioneer Southwest held by unitholders other than Pioneer or its subsidiaries for consideration of .2234 of a share of common stock of Pioneer for each outstanding common unit of Pioneer Southwest held by such unitholders in a transaction to be structured as a merger of Pioneer Southwest with a wholly-owned subsidiary of Pioneer. The Company's proposal was made based on the assumption that Pioneer Southwest would declare and pay the distribution for the period April 1, 2013 to June 30, 2013 (which was declared in July 2013 and is to be paid on August 9, 2013, to unitholders of record on August 2, 2013) and then suspend future common unit distributions pending the execution of a definitive agreement and the consummation of a transaction. The consummation of the transaction contemplated by the Pioneer Southwest Merger Proposal is subject to approval of the Company's Board, approval of the Conflicts Committee and the Board of Directors of the General Partner and the negotiation of a definitive agreement. There can be no assurance that a definitive agreement will be executed or that any transaction will be approved or consummated. See "Recent Developments" for additional information regarding this proposal.

Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments (including commitments to pay day rates for drilling rigs), capital funding obligations, derivative obligations, firm transportation and fractionation commitments, minimum annual gathering, treating and transportation commitments and other liabilities (including postretirement benefit obligations). From time-to-time, the Company enters into arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of June 30, 2013, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) operating lease agreements, (ii) drilling commitments, (iii) firm transportation and fractionation commitments, (iv) open purchase commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates and gathering, treating, fractionation and transportation commitments on uncertain volumes of future throughput. 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, 2012, the material changes in the Company's contractual obligations include a $903.9 million decrease in the principal balances of outstanding long-term debt and a $14.5 million increase in the Company's derivative net assets.

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, 2013, these contracts represented net assets of $323.1 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, 2013. See Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative

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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 cash and cash equivalents, net cash provided by operating activities, proceeds from sales of joint interests and nonstrategic assets and proceeds from financing activities (principally borrowings under the Company's Credit Facility or issuances of debt or equity securities). If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, and/or fund a portion of its capital expenditures using availability under its Credit Facility, issue debt or equity securities or obtain capital from other sources, such as through the sale of joint interests or nonstrategic assets.

Operating activities. Net cash provided by operating activities during the six months ended June 30, 2013 was $935.9 million, as compared to $925.4 million during the same period of 2012. The increase in net cash provided by operating activities for the six months ended June 30, 2013, as compared to the six months ended June 30, 2012, is primarily due to an increase in oil and gas sales, partially offset by a decrease in realized derivative gains.

Asset divestitures. In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for total consideration of $1.8 billion, including normal closing adjustments. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $614.5 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale. Sinochem will pay the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play.

During the six months ended June 30, 2013, the Company completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for $38.1 million of net cash proceeds, which resulted in a pretax gain of $22.4 million, and a sale of its interest in certain unproved oil and gas properties in the Barnett Shale for net cash proceeds of $11.2 million, which resulted in a pretax gain of $8.3 million.

Financing activities. Net cash provided by financing activities during the six months ended June 30, 2013 was $344.1 million, as compared to net cash provided by financing activities of $676.9 million during the six months ended 2012. The decrease in net cash provided from financing activities during the six months ended June 30, 2013, as compared to the same period of 2012, was primarily the result of (i) an increase in net principal payments on long-term debt of $1.6 billion, partially offset by (ii) the Company's completion of an offering of 10.35 million shares of its common stock in February 2013 at a per-share price, after underwriting and offering expenses, of $123.76 for a total of $1.3 billion of realized net proceeds.

During December 2012 and March 2013, respectively, the Company's stock price met the price threshold that causes the Convertible Senior Notes to be convertible for the three months ended March 31, 2013 and June 30, 2013, respectively, at the option of the holders 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 Convertible Senior Notes were issued. In addition, on April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479.1 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479.1 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock during the six months ended June 30, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $845 thousand in principal and interest to redeem all Convertible Senior Notes that remained outstanding.

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, 2013, the Company had no outstanding borrowings under its Credit Facility and was in compliance with all of its debt covenants. The Company had cash on hand of $695.6 million and $1.5 billion of unused borrowing capacity as of June 30, 2013. 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 the sale of joint interests or nonstrategic assets. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal operating cash flows, cash on hand, proceeds from sales of joint

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interests or nonstrategic assets and available capacity under the Company's Credit Facility will be adequate to fund 2013 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 increase the interest rates that the Company incurs on credit facility borrowings and could negatively impact the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. The Company is rated as investment grade by three credit rating agencies.

Book capitalization and current ratio. The Company's net book capitalization at June 30, 2013 was $9.8 billion, consisting of $695.6 million of cash and cash equivalents, debt of $2.8 billion and equity of $7.6 billion. The Company's net debt to net book capitalization was 22 percent and 37 percent at June 30, 2013 and December 31, 2012, respectively. The change was primarily a result of the increase in cash and cash equivalents of $466.2 million and a decrease in long-term debt of $897.8 million during the first six months of 2013. The Company's ratio of current assets to current liabilities increased to 1.45 to 1.00 at June 30, 2013, as compared to 1.02 to 1.00 at December 31, 2012, primarily due to the above noted increase in cash and cash equivalents. Increases in the Company's liquidity resulted from the February 2013 sale of 10.35 million shares of common stock and the May 2013 completion of the Wolfcamp joint venture with Sinochem.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2012. 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, 2012.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company's potential exposure to market risks. The term "market risks," insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. None of the Company's market risk sensitive instruments are entered into for speculative purposes.

The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during the six months ending June 30, 2013:



	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2012	$	318,377		$	(9,724	)	$	308,653
Changes in contract fair value	91,996			10,206			102,202
Contract maturities	(87,231		)	—			(87,231		)
Contract terminations	—			(482		)	(482		)
Fair value of contracts outstanding as of June 30, 2013	$	323,142		$	—		$	323,142

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, 2013 and that are sensitive to changes in interest rates. The table presents debt 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, 2013. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on July 30, 2013.



	Six Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at June 30,
	2013			2014			2015			2016			2017			Thereafter (a)			Total		2013
	(dollars in thousands)
Total Debt:
Fixed rate principal maturities (b)	$	—		$	—		$	—		$	455,385		$	485,100		$	1,749,500		$	2,689,985	$	(3,028,692	)
Weighted average interest rate	6.15		%	6.15		%	6.15		%	6.17		%	6.11		%	6.28		%
Variable rate principal maturities:
Pioneer Southwest Credit Facility	$	—		$	—		$	—		$	—		$	176,000		$	—		$	176,000	$	(169,216	)
Weighted average interest rate	1.93		%	2.10		%	2.64		%	3.47		%	3.56		%

____________________


(a)	During the period from July 1, 2013 to July 30, 2013, the Company entered into interest rate derivative contracts whereby the Company will receive a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.21 percent on a notional amount of $175 million through July 15, 2022.


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

Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of June 30, 2013. 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 E 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,
	2013			2014			2015			2016		2013 (a)
												(in thousands)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (b)	74,250			69,000			32,000			2,000		$	213,841
Weighted average ceiling price per BBL	$	120.11		$	114.05		$	103.23		$	94.75
Weighted average floor price per BBL	$	92.21		$	93.70		$	93.13		$	85.00
Weighted average short put price per BBL	$	74.44		$	77.61		$	78.13		$	70.00
Swap contracts (b)	3,000			—			—			—		$	(7,748	)
Weighted average fixed price per BBL	$	81.02		$	—		$	—		$	—
Average forward NYMEX oil prices (c)	$	101.90		$	95.13		$	89.28		$	85.59
Rollfactor swap contracts (b)	6,000			15,000			—			—		$	(1,687	)
Weighted average fixed price per BBL (d)	$	0.43		$	0.38		$	—		$	—
Average forward rollfactor prices (c)	$	1.28		$	0.85		$	—		$	—
Cushing to LLS index swap contracts	1,500			—			—			—		$	736
Weighted average fixed price per BBL	$	8.53		$	—		$	—		$	—
Average forward basis differential prices (e)	$	5.37		$	—		$	—		$	—
NGL Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (f)	1,064			1,000			—			—		$	3,817
Weighted average ceiling price per BBL	$	105.28		$	109.50		$	—		$	—
Weighted average floor price per BBL	$	89.30		$	95.00		$	—		$	—
Weighted average short put price per BBL	$	75.20		$	80.00		$	—		$	—
Average forward NGL prices (g)	$	87.85		$	82.57		$	—		$	—
Collar contracts (h)	2,500			3,000			—			—		$	1,130
Weighted average ceiling price per BBL	$	12.68		$	13.72		$	—		$	—
Weighted average floor price per BBL	$	10.50		$	10.78		$	—		$	—
Average forward NGL prices (g)	$	10.59		$	11.10		$	—		$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts	—			115,000			285,000			20,000		$	23,039
Weighted average ceiling price per MMBTU	$	—		$	4.70		$	5.07		$	5.36
Weighted average floor price per MMBTU	$	—		$	4.00		$	4.00		$	4.00
Weighted average short put price per MMBTU	$	—		$	3.00		$	3.00		$	3.00
Collar contracts	152,500			—			—			—		$	37,774
Weighted average ceiling price per MMBTU	$	6.22		$	—		$	—		$	—
Weighted average floor price per MMBTU	$	4.98		$	—		$	—		$	—
Swap contracts	169,185			175,000			20,000			—		$	52,584
Weighted average fixed price per MMBTU	$	5.07		$	4.02		$	4.31		$	—
Average forward NYMEX gas prices (c)	$	3.54		$	3.85		$	4.07		$	4.21
Basis swap contracts	162,500			45,082			30,000			—		$	(344	)
Weighted average fixed price per MMBTU	$	(0.22	)	$	(0.18	)	$	(0.18	)	$	—
Average forward basis differential prices (i)	$	(0.12	)	$	(0.25	)	$	(0.30	)	$	—

___________________

(a)

In accordance with Financial Accounting Standards Board Accounting Standards Codification ("ASC") 210-20 and ASC 815-10, the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements classifications.

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(b)


(c)	The average forward NYMEX oil and gas prices are based on July 30, 2013 market quotes.


(d)	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.


(e)	The average forward basis differential prices are based on July 30, 2013 market quotes for basis differentials between Cushing WTI and Louisiana Light Sweet crude ("LLS").


(f)	Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(g)	Forward component NGL prices are derived from active-market NGL component price quotes as of July 30, 2013.


(h)	Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.


(i)	The average forward basis differential prices are based on July 30, 2013 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

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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, 2013 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the information set forth in this Report, you should carefully consider the risks discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 2012, 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," which risks could materially affect the Company's business, financial condition or future results. Except as set forth below, there has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K.

The proposal by the Company to the chairman of the Conflicts Committee of the General Partner to acquire all of the outstanding common units of the Pioneer Southwest held by unitholders other than Pioneer or its subsidiaries may not result in the execution of a definitive agreement or the approval or consummation of a transaction.

On May 7, 2013, the Company delivered a proposal to the chairman of the Conflicts Committee of the General Partner to acquire all of the outstanding common units of the Pioneer Southwest held by unitholders other than Pioneer or its subsidiaries for consideration of .2234 of a share of common stock of Pioneer for each outstanding common unit of the Pioneer Southwest held by such unitholders in a transaction to be structured as a merger of the Pioneer Southwest with a wholly-owned subsidiary of Pioneer. The consummation of the transaction contemplated by the Pioneer Southwest Merger Proposal is subject to approval by the Company's Board of Directors, approval of the Conflicts Committee and the Board of Directors of the General Partner and the negotiation of a definitive agreement. There can be no assurance that a definitive agreement will be executed or that any transaction will be approved or consummated.

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, 2013:



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 2013	3,357	$	122.91	—
May 2013	—	$	—	—
June 2013	—	$	—	—
Total	3,357	$	122.91	—	$	—

____________________


(a)	Consists of shares purchased from each employee 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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Item 6. Exhibits

Exhibits



Exhibit Number		Description

12.1	(a) —	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.

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

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

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

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

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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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 5, 2013	By:	/s/ RICHARD P. DEALY
		Richard P. Dealy
		Executive Vice President and Chief Financial Officer

Date: August 5, 2013	By:	/s/ FRANK W. HALL
		Frank W. Hall
		Vice President and Chief Accounting Officer

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Exhibit Index



Exhibit Number		Description


12.1	(a) —	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.

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

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

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

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

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.