Pioneer Natural Resources Company Annual Report 2012

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FY2012 Annual Report · Pioneer Natural Resources Company

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RESOURCE
RICH

2012 10-K AND ANNUAL REPORT

RESOURCE POTENTIAL BY ASSET
8 billion barrels oil equivalent (BOE)

2013 DRILLING CAPITAL BY ASSET
$2.75 billion

NORTHERN
HORIZONTAL
WOLFCAMP/
JO MILL

SOUTHERN
HORIZONTAL
WOLFCAMP

VERTICAL
SPRABERRY
20-AC DRILLING

VERTICAL
SPRABERRY 40-AC
DRILLING

EAGLE FORD SHALE

BARNETT SHALE

SPRABERRY
WATERFLOOD

OTHERS

NORTHERN
WOLFCAMP/
SPRABERRY

SOUTHERN
WOLFCAMP

EAGLE FORD SHALE

BARNETT SHALE

ALASKA

OTHER

OPERATING AREAS

Alaska

Rockies

Northern
Wolfcamp/
Spraberry

Southern
Wolfcamp

Mid-Continent

Barnett Shale

South Texas/
Eagle Ford Shale

Except for historical information contained herein, the statements in this document are forward-looking statements that are made pursuant to the Safe Harbor
Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer Natural Resources Company
are subject to a number of risks and uncertainties that may cause Pioneer’s actual results in future periods to differ materially from the forward-looking statements.
These risks and uncertainties are described in Items 1, 1A, 7 and 7A and on page 5 of Pioneer’s Form 10-K included with this report.

“Drillbit ﬁ nding and development cost per BOE” means the summation of exploration and development costs incurred divided by the summation of annual proved
reserves, on a BOE basis, attributable to technical revisions of previous estimates, discoveries and extensions and improved recovery. Consistent with industry
practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

“Reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, purchases of minerals-in-place,
discoveries and extensions and improved recovery divided by annual production of oil, natural gas liquids and gas, on a BOE basis.

Cautionary Note — In this report, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource” and “resource potential,” which
terms include quantities that may not meet the deﬁ nitions of “reserves” established by the U.S. Securities and Exchange Commission (“SEC”) and which the SEC
prohibits companies from including in SEC ﬁ lings. These estimates are by their nature subject to substantially greater risk of being recovered by Pioneer than are
proved reserves. You are urged to consider closely the disclosures in the Company’s periodic ﬁ lings with the SEC, which are available from the Company at the
address on the back cover of this report and the Company’s website at www.pxd.com.

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Scott D. Shefﬁeld

Chairman and CEO

FELLOW SHAREHOLDERS:

These are exciting times for U.S. oil and natural gas exploration and production.

In late 2012, the International Energy Agency announced that, according to its

forecast, the United States will overtake Saudi Arabia as the world’s largest oil

producer by 2020. The U.S. has already overtaken Russia as the world’s leading

GROSS WELLS
DRILLED

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natural gas producer. Even “resource rich,” the theme of this year’s annual report,

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seems to fall short in describing the landscape for U.S. oil and natural gas.

For those familiar with the U.S. oil business, the Bakken Shale in North Dakota

and Eagle Ford Shale in South Texas are well-known plays with high levels of

drilling activity and substantial reserve potential. During 2012, the Permian Basin

in West Texas took center stage with its multitude of stacked oil resources long

known to hold tremendous volumes of oil still trapped in tight rock.

Pioneer has a long history in the Midland Basin, a proliﬁc region within the

Permian Basin, and has been the most active driller in the Spraberry ﬁeld in

the Permian Basin for many years. The oil-rich Wolfcamp Shale lies below

the Spraberry formation, and during 2012, Pioneer successfully tested drilling and

completion technologies which conﬁrmed tremendous incremental recoverable

resources in multiple stacked Wolfcamp zones, in addition to the stacked resource

zones in the Spraberry formation. The wells Pioneer drilled in the Wolfcamp Shale

and Jo Mill intervals utilizing horizontal drilling and hydraulic fracturing technology

exceeded expectations and have revolutionized our approach to maximizing

the recovery of oil and liquids. Pioneer’s 900,000-acre legacy leasehold position

in the Permian Basin is even more resource rich than previously thought.

Through an extensive Midland Basin geologic analysis, based on data from

thousands of existing wells, our geoscience team has identiﬁed multiple

prospective horizontal targets throughout Pioneer’s Wolfcamp/Spraberry

leasehold position with an aggregate estimated resource potential of more than

2012 YEAR-END PROVED
RESERVES BY ASSET
1.1 billion BOE

SPRABERRY

BARNETT SHALE

SOUTH TEXAS/
EAGLE FORD SHALE

ALASKA

OTHER

ROCKIES

MID-CONTINENT

66% of proved reserves are oil and natural
gas liquids and 34% are natural gas

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7 billion barrels oil equivalent (BOE). The resources we are developing through

traditional vertical drilling in the Spraberry Trend represent approximately

35% of the estimated resource potential and include vertical well potential from

Wolfcamp and deeper intervals as well as from down-spacing. The remaining

65% of estimated resource potential relates to the additional potential

attributable to horizontal drilling.

STRONG RESULTS FOR 2012

During 2012, Pioneer was successful in appraising and initiating horizontal

development of the southern 200,000 acres of the Wolfcamp play, leading to

the signing of a joint interest transaction with a U.S. subsidiary of the Sinochem

Group, which will provide funding to accelerate horizontal development of this

acreage when the transaction closes. Pioneer also initiated horizontal drilling on

our northern acreage to appraise the potential of the horizontal Wolfcamp Shale

and other zones in this area, and early results are very encouraging.

In response to our increase in horizontal drilling, we reduced the number of rigs

drilling vertical Spraberry wells from 40 rigs at the beginning of 2012 to 20 rigs

at year end, drilling 631 vertical wells during the year. Two-thirds of the vertical

Spraberry wells were drilled to deeper zones to access additional reserves from

the Wolfcamp, Strawn, Atoka and Mississippian intervals.

Pioneer’s daily production from the Permian Basin increased approximately

45% from the prior year to 67,000 BOE per day (BOEPD), primarily as a result

of the vertical drilling program as production from horizontal drilling wasn’t

initiated until late in the year.

Strong oil prices during 2012 also supported solid returns on investment

for Pioneer’s oil and liquids-rich drilling programs in the Eagle Ford Shale,

the Barnett Shale Combo play in North Texas and on Alaska’s North Slope.

Companywide, Pioneer drilled 898 wells with 98% success.

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THE WELLS PIONEER
DRILLED IN THE LIQUIDS-
RICH WOLFCAMP SHALE
AND JO MILL INTERVALS
UTILIZING HORIZONTAL
DRILLING AND
HYDRAULIC FRACTURING
TECHNOLOGY EXCEEDED
EXPECTATIONS AND
HAVE REVOLUTIONIZED
OUR APPROACH
TO MAXIMIZING THE
RECOVERY OF OIL
AND LIQUIDS.

In the Eagle Ford Shale, Pioneer drilled 137 horizontal wells and more than

doubled the Company’s average daily production in the area to approximately

27,800 BOEPD. Strong well performance continues to drive production growth,

and based on public wellhead production data, on average, our wells are

performing well above the industry median for the Eagle Ford Shale.

Pioneer’s drilling program in the Eagle Ford Shale is focused on the area of

the play that holds oil and natural gas liquids, supporting strong returns on

investment. Our returns have also beneﬁted from the solid execution of our

gathering and midstream strategy, and at year end, we had 11 central gathering

plants operating with plans to have an additional plant on line by the end of 2013.

As our Eagle Ford Shale drilling program has progressed, we have utilized more

multi-well pad drilling, which is more efﬁcient and reduces costs. Our use of

lower-cost white sand rather than ceramic proppant to fracture stimulate wells

drilled in shallower areas of the ﬁeld has also signiﬁcantly reduced well costs, and

we are expanding this practice to deeper areas of the ﬁeld to further deﬁne its

performance limits, enhancing our economic returns.

During 2012, Pioneer drilled 57 wells in the Barnett Shale Combo play, a section

of the Barnett Shale that holds oil, natural gas liquids and natural gas. During

most of the year, we operated one rig in the play and increased average daily

production from 3,800 BOEPD to 7,300 BOEPD.

On the North Slope of Alaska, Pioneer continues to drill development wells from

our island drill site targeting the Nuiqsut and Torok intervals. Average daily

production was approximately 4,300 BOEPD during 2012. During the ﬁrst quarter

of 2012, we completed Pioneer’s ﬁrst successful mechanically diverted fracture

stimulation, and based on that success, we have drilled four more wells that we

plan to similarly stimulate during the current winter drilling season. In early 2012,

Pioneer drilled a successful onshore appraisal well to test the southern extent of

the Torok interval.

With persistently low natural gas prices, maximizing revenue and minimizing

costs were the primary activities of our Rockies, Mid-Continent and South

Texas Edwards Trend asset teams, which produce predominantly dry natural

gas. Continually optimizing operations and improving best practices in these

and other asset areas are essential to our continued success, both in terms

of ﬁnancially supporting Pioneer’s growth initiatives as well as responsibly

producing energy to meet our nation’s needs.

We continued to be among the top performers in our peer group in total

shareholder return in 2012. Over the past ﬁve years, Pioneer’s cumulative return

to shareholders was 121%, signiﬁcantly ahead of both of our benchmarks, the

S&P 500 Index and the S&P E&P Index. For the ﬁve-year period, the cumulative

return for the S&P 500 Index was 8%, and the S&P E&P Index was down 2%.

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Our successful 2012 drilling program, augmented by our integrated services

model, supported a 20% increase in annual cash ﬂow from operations to

$1.8 billion compared to 2011. Production from continuing operations grew

29% to average approximately 155,500 BOEPD. Pioneer reported earnings

attributable to common stockholders of $192 million, or $1.50 per diluted share.

Through the drillbit, Pioneer added proved reserves totaling 161 million BOE during

2012, from discoveries, extensions, improved recovery and technical revisions

of previous reserve estimates, replacing 264% of the Company’s full-year 2012

production at an average drillbit ﬁnding and development cost of $17.72 per BOE.

Pioneer’s year-end 2012 proved reserves totaled 1.086 billion BOE.

CONTINUING LIQUIDS-RICH FOCUS FOR 2013

WOLFCAMP/SPRABERRY
NET PRODUCTION
MBOEPD

We will again focus our capital program on our assets in Texas, holding

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substantial acreage in four of the most resource-rich oil and liquids plays in the

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state. As a result, we expect to deliver strong production growth again in 2013,

investing approximately $3 billion in drilling and other capital improvements.

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SOUTH TEXAS/EAGLE
FORD NET PRODUCTION
MBOEPD

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Pioneer’s successful 2012 horizontal Wolfcamp Shale drilling results in the

Spraberry Trend have led us to shift a signiﬁcant portion of our 2013 drilling

activity from vertical drilling to more capital-efﬁcient horizontal drilling. Pioneer’s

horizontal rig count is expected to rise by eight to an average of 11 rigs, and our

vertical rig count is expected to decline by 17 to an average of 15 rigs. Considering

the higher production rates from horizontal wells, despite the drop in the total rig

count, we expect a signiﬁcant increase in total production from the Wolfcamp/

Spraberry play.

In January 2013, Pioneer announced the signing of an agreement with a U.S.

subsidiary of the Sinochem Group to sell 40% of our interest in approximately

207,000 net acres in the southern portion of the Wolfcamp/Spraberry play for

$1.74 billion, accelerating the pace of developing the acreage while maintaining

operatorship. We expect to close the transaction during the second quarter of

2013, subject to governmental approval.

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We plan to run seven horizontal rigs and drill more than 80 wells in this

southern joint interest area during 2013 and increase the rig count by three

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rigs per year through 2015. The 2013 drilling program will continue to focus on

delineating acreage, optimizing completion techniques and testing multiple

Wolfcamp intervals, while the program in 2014 and beyond will primarily focus

on development drilling and accelerating production growth.

To the north, we plan to drill 30 to 40 wells to appraise the potential of the

multiple Wolfcamp Shale, Jo Mill and Spraberry Shale intervals within our existing

leasehold covering more than 600,000 gross acres. We are currently running one

rig and plan to expand to ﬁve rigs during 2013 to accelerate the appraisal and

delineation of these intervals.

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Pioneer’s vertical drilling program will also continue during 2013 but at a

reduced pace. We plan to run 15 vertical rigs and drill approximately 300 wells.

Approximately 90% of these wells will be deeper wells accessing the Wolfcamp,

Strawn, Atoka or Mississippian intervals.

In the Eagle Ford Shale, Pioneer plans to run ten rigs during 2013 and drill

approximately 130 horizontal wells, primarily in the liquids-rich area of the play.

The ability to drill more wells with fewer rigs reﬂects the success of our efforts to

control costs, further reduce drilling times and optimize completion techniques.

We expect that approximately 80% of our wells will be drilled from multi-well

pads to improve efﬁciency.

In the liquids-rich Barnett Shale Combo play, Pioneer is operating one rig and

plans to increase to two rigs during the second quarter. This two-rig drilling

program is designed to hold leases in the highest-return areas of our acreage

position, as identiﬁed by drilling data and petrophysical and seismic analysis.

Production from the play is expected to grow throughout 2013.

On the North Slope of Alaska, Pioneer is running two rigs. One rig continues to

drill development wells from our Oooguruk island facility targeting Nuiqsut and

Torok intervals, and a second rig is drilling the second onshore Torok well to

further appraise this interval. Following our ﬁrst successful mechanically diverted

hydraulic fracture stimulation on a Nuiqsut well in 2012, Pioneer is planning similar

stimulations for one Torok and three Nuiqsut wells in the current winter program.

In the Rockies, Mid-Continent and Edwards Trend, we plan to continue our

activities to maximize production as we continue to rely on these long-lived

natural gas assets to provide signiﬁcant cash ﬂow.

FOCUS ON ENVIRONMENTAL STEWARDSHIP

We continue to make signiﬁcant progress in efforts to assess and reduce

Pioneer’s impact on the environment. We are reducing fresh water use by utilizing

less water for hydraulic fracturing, working to understand the optimal use of

brackish water and evaluating the possible use of water that is produced in

THE ABILITY TO
DRILL MORE EAGLE
FORD WELLS WITH
FEWER RIGS REFLECTS
THE SUCCESS OF
OUR EFFORTS TO
CONTROL COSTS,
FURTHER REDUCE
DRILLING TIMES AND
OPTIMIZE COMPLETION
TECHNIQUES.

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association with oil and natural gas production. To support these efforts, we are

designing environmentally sound water treatment and distribution systems.

To reduce air emissions, we have developed a comprehensive understanding

of our emissions footprint, incorporating the use of advanced emissions

measurement technology in our ﬁeld operations. The detailed ﬁndings not only

provide the basis for air emission reporting but also have identiﬁed opportunities

for emission reductions through implementing effective best practices and

technological solutions.

We continue to expand our ﬂeet of lower-emission natural gas vehicles and

participate in industry programs for disclosing the components of hydraulic

fracturing ﬂuids. I am particularly pleased with Pioneer’s participation in industry

efforts to collaboratively evaluate our impact on air and water, sharing with

regulators what we’ve learned, as well as initiatives aimed at better educating and

informing the public about our industry and the safety of our operating practices.

OUR EMPLOYEES GIVE US CONFIDENCE IN THE FUTURE

We have welcomed many new employees to the Pioneer team over the past three

years as we increased drilling and development in the Eagle Ford Shale and the

Wolfcamp/Spraberry play. Our ability to deliver consistently strong results in the

midst of rapid growth requires focus, teamwork and commitment, and I want to

thank our employees for their tremendous performance during 2012.

Maintaining our respectful and responsible culture is also a top priority as we

accelerate activity levels. We appreciate employees’ commitment to upholding

our corporate values, supporting the communities where we live and work,

protecting the environment and maintaining a safe workplace. Based on

employee survey results, we were again deeply honored to be recognized as

a top company to work for in Dallas and as one of America’s top workplaces.

Pioneer is well positioned to post top-tier returns during 2013 as we build on the

strength of one of the best U.S. oil and liquids-rich asset portfolios in the industry

combined with our staff’s exceptional technological and operational expertise.

As always, we appreciate your support.

Scott D. Shefﬁeld

Chairman and CEO

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STOCK PERFORMANCE

The information included in the remainder of this document, including this “Stock Performance” section

of the 2012 Annual Report, is not a part of Pioneer’s Annual Report on Form 10-K for the ﬁscal year ended

December 31, 2012, and shall not be deemed to be “soliciting material” or to be “ﬁled” with the Securities and

Exchange Commission (SEC). Such information shall not be deemed to be incorporated by reference into

any ﬁling under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that

Pioneer speciﬁcally incorporates such information.

The following graph and chart compare Pioneer’s cumulative total stockholder return on common stock

during the ﬁve-year period ended December 31, 2012, with cumulative total return during the same period

for the Standard & Poor’s 500 Index (“S&P 500 Index”) and the Standard & Poor’s Oil & Gas Exploration

& Production Index (the “S&P E&P Index”), as prescribed by the SEC rules. The following graph and chart

show the value, at December 31 in each of 2008, 2009, 2010, 2011 and 2012 of $100 invested at December 31,

2007, and assumes the reinvestment of all dividends:

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN

AMONG PIONEER, THE S&P 500 INDEX AND THE S&P E&P INDEX (a)

$250

$200

$150

$100

$50

2007

2008

2009

2010

2011

2012

Year ended December 31,

2007

2008

2009

2010

2011

2012

Pioneer

$ 100.00

S&P 500 Index

$ 100.00

S&P E&P Index

$ 100.00

33.32

$ 99.52

$ 179.61

$ 185.30

$ 220.90

63.00

$ 79.67

60.97

$ 79.11

91.67

93.63

93.61

$ 108.59

94.51

97.51

(a) Assumes $100 invested at December 31, 2007, in stock or index, including reinvestment of dividends.

BOARD OF DIRECTORS

Scott D. Shefﬁeld
Chairman and
Chief Executive Ofﬁcer

Andrew F. Cates 3,4
Managing Member
Value Acquisition Fund

Thomas D. Arthur 2,4
Former President and CEO
Havatampa Incorporated

R. Hartwell Gardner 2,4
Retired Treasurer
Mobil Corporation

Edison C. Buchanan 3,4
Former Managing Director
Credit Suisse First Boston

Charles E. Ramsey, Jr. 1,2,4
Retired Energy Industry Executive

Frank A. Risch 2,4
Retired Vice President
and Treasurer
Exxon Mobil Corporation

J. Kenneth Thompson 3,4
President and CEO
Paciﬁc Star Energy LLC

Jim A. Watson 2,4
Senior Counsel
Carrington, Coleman,
Sloman & Blumenthal, L.L.P.

Committee Membership:

1 Lead Director

3 Compensation and

2 Audit Committee

Management Development
Committee

4 Nominating and Corporate

Governance Committee

OFFICERS

Scott D. Shefﬁeld
Chairman and
Chief Executive Ofﬁcer

Timothy L. Dove
President and
Chief Operating Ofﬁcer

Mark S. Berg
Executive Vice President
and General Counsel

Chris J. Cheatwood
Executive Vice President,
Business Development and
Geoscience

Richard P. Dealy
Executive Vice President and
Chief Financial Ofﬁcer

William F. Hannes
Executive Vice President,
Southern Wolfcamp Operations

Danny L. Kellum
Executive Vice President,
Permian Operations

Jay P. Still
Executive Vice President,
Domestic Operations

J.D. Hall
Vice President,
South Texas Operations

Frank E. Hopkins
Senior Vice President,
Investor Relations

Denny B. Bullard
Vice President,
Operations Services

John C. Distaso
Vice President, Marketing

Robert C. Hagens
Vice President, Land

Thomas C. Halbouty
Vice President,
Chief Information Ofﬁcer and
Chief Technology Ofﬁcer

Frank W. Hall
Vice President and
Chief Accounting Ofﬁcer

Mark H. Kleinman
Vice President,
Corporate Secretary and
Chief Compliance Ofﬁcer

Larry N. Paulsen
Vice President,
Administration and
Risk Management

Kenneth H. Shefﬁeld, Jr.
Vice President,
Corporate Engineering

Tom Spalding
Vice President, Geoscience

Susan A. Spratlen
Vice President,
Communication

Roger W. Wallace
Vice President,
Government Affairs

RESOURCE
RICH PIONEER NATURAL RESOURCES COMPANY

2012 FORM 10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

(cid:58)(cid:3)ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT

OF 1934
For the fiscal year ended December 31, 2012

(cid:133)(cid:3)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

(State or other jurisdiction of
incorporation or organization)

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

75-2702753

(I.R.S. Employer
Identification No.)

75039
(Zip Code)

Registrant's telephone number, including area code: (972) 444-9001
Securities registered pursuant to Section 12(b) of the Act:

Title of each class
Common Stock, par value $.01

Name of each exchange on which registered
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:58) No (cid:133)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:133) No (cid:58)

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 (cid:58) No (cid:133)

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 (cid:58) No (cid:133)

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. (cid:133)

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

Large accelerated filer (cid:58)(cid:3)

Accelerated filer

(cid:134)(cid:3)

Non-accelerated filer (cid:134) (Do not check if a smaller reporting company)(cid:3)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:133) No (cid:58)

Smaller reporting company (cid:134)(cid:3)

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by
reference to the price at which the common equity was last sold, or the average bid and asked price of such
common equity, as of the last business day of the registrant's most recently completed second fiscal quarter $ 10,710,105,448

Number of shares of Common Stock outstanding as of February 8, 2013

123,360,341

DOCUMENTS INCORPORATED BY REFERENCE:
(1) Portions of the Definitive Proxy Statement for the Company's 2013 Annual Meeting of Shareholders to be held during May 2013 are

incorporated into Part III of this report.

Table of Contents

Definitions of Certain Terms and Conventions Used Herein ..............................................................................................
Cautionary Statement Concerning Forward-Looking Statements .......................................................................................

PART I

Item 1. Business..............................................................................................................................................................
General ...........................................................................................................................................................
Available Information .....................................................................................................................................
Mission and Strategies ....................................................................................................................................
Business Activities..........................................................................................................................................
Marketing of Production .................................................................................................................................
Competition, Markets and Regulations...........................................................................................................
Item 1A. Risk Factors ........................................................................................................................................................
Item 1B. Unresolved Staff Comments ..............................................................................................................................
Properties............................................................................................................................................................
Item 2.
Reserve Estimation Procedures and Audits ....................................................................................................
Proved Reserves .............................................................................................................................................
Description of Properties ................................................................................................................................
Selected Oil and Gas Information ...................................................................................................................
Item 3. Legal Proceedings ..............................................................................................................................................
Item 4. Mine Safety Disclosures .....................................................................................................................................

PART II

Item 5.

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities ............................................................................................................................................................
Purchases of Equity Securities by the Issuer and Affiliated Purchasers .........................................................
Selected Financial Data ......................................................................................................................................
Item 6.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ..............................
Financial and Operating Performance ............................................................................................................
First Quarter 2013 Outlook .............................................................................................................................
2013 Capital Budget .......................................................................................................................................
Acquisitions ....................................................................................................................................................
Divestitures and Discontinued Operations ......................................................................................................
Results of Operations ......................................................................................................................................
Capital Commitments, Capital Resources and Liquidity ................................................................................
Critical Accounting Estimates ........................................................................................................................
New Accounting Pronouncements ..................................................................................................................
Item 7A. Quantitative and Qualitative Disclosures About Market Risk ...........................................................................
Quantitative Disclosures .................................................................................................................................
Qualitative Disclosures ...................................................................................................................................
Financial Statements and Supplementary Data ..................................................................................................
Index to Consolidated Financial Statements ...................................................................................................
Report of Independent Registered Public Accounting Firm ...........................................................................
Consolidated Financial Statements .................................................................................................................
Notes to Consolidated Financial Statements ...................................................................................................
Unaudited Supplementary Information...........................................................................................................
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure ............................
Item 9A. Controls and Procedures .....................................................................................................................................
Management's Report on Internal Control Over Financial Reporting ............................................................
Report of Independent Registered Public Accounting Firm ...........................................................................
Item 9B. Other Information ...............................................................................................................................................

Item 8.

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Table of Contents

PART III

Item 10. Directors, Executive Officers and Corporate Governance .................................................................................
Item 11. Executive Compensation ...................................................................................................................................
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Securities Authorized for Issuance Under Equity Compensation Plans .........................................................
Item 13. Certain Relationships and Related Transactions, and Director Independence ...................................................
Item 14. Principal Accounting Fees and Services ............................................................................................................

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PART IV

Item 15. Exhibits, Financial Statement Schedules ...........................................................................................................

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Definitions of Certain Terms and Conventions Used Herein

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Within this Report, the following terms and conventions have specific meanings:
"BBL" means a standard barrel containing 42 United States gallons.
"BCF" means one billion cubic feet.
"BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a
comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the
ratio of 6.0 MCF of gas to 1.0 BBL of oil or natural gas liquid.
"BOEPD" means BOE per day.
"BTU" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one
pound of water one degree Fahrenheit.
"CBM" means coal bed methane.
"Conway-posted price" means the daily average natural gas liquids components as priced in Oil Price Information
Services in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.
"DD&A" means depletion, depreciation and amortization.
"field fuel" means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a
sales point.
"GAAP" means accounting principles that are generally accepted in the United States of America.
"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.
"MBBL" means one thousand BBLs.
"MBOE" means one thousand BOEs.
"MCF" means one thousand cubic feet and is a measure of gas volume.
"MMBBL" means one million BBLs.
"MMBOE" means one million BOEs.
"MMBTU" means one million BTUs.
"MMCF" means one million cubic feet.
"Mont Belvieu-posted price" means the daily average natural gas liquids components as priced in Oil Price Information
Service in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.
"NGL" means natural gas liquid.
"NYMEX" means the New York Mercantile Exchange.
"NYSE" means the New York Stock Exchange.
"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.
"Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.
"Proved reserves" mean the quantities of oil and gas, which, by analysis of geosciences and engineering data, can be
estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs,
and under existing economic conditions, operating methods, and government regulations – prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of
whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must
have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid
contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be
continuous with it and to contain economically producible oil or gas on the basis of available 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 as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a
highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the
structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology
establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through
application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved
classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable
than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project
or program 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.
"SEC" means the United States Securities and Exchange Commission.
"Standardized Measure" means the after-tax present value of estimated future net cash flows of proved reserves,
determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the
determination of proved reserves and a ten percent discount rate.
"U.S." means United States.
"VPP" means volumetric production payment.
"WTI" means a light, sweet blend of oil produced from fields in western Texas.
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.

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this "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 the Company are intended to identify forward-looking statements, which are generally not
historical in nature. 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. 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 from the anticipated results described in the forward-
looking statements. See "Item 1. Business — Competition, Markets and Regulations," "Item 1A. Risk Factors," "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" for a description of various factors that could materially affect the ability of
Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place
undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to
publicly update these statements except as required by law.

PIONEER NATURAL RESOURCES COMPANY

PART I

ITEM 1.

BUSINESS

General

The Company is a large independent oil and gas exploration and production company with operations in the United
States. Pioneer is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is
conducted substantially through, its subsidiaries. Pioneer's common stock is listed and traded on the NYSE.

The Company is a Delaware corporation formed in 1997. The Company's executive offices are located at 5205 N.
O'Connor Blvd., Suite 200, Irving, Texas 75039. The Company's telephone number is (972) 444-9001. The Company maintains
other offices in Anchorage, Alaska; Denver, Colorado and Midland, Texas. At December 31, 2012, the Company had 3,667
employees, 2,484 of whom were employed in field and plant operations.

Available Information

Pioneer files or furnishes annual, quarterly and current reports, proxy statements and other documents with the SEC
under the Securities Exchange Act of 1934 (the "Exchange Act"). The public may read and copy any materials that Pioneer
files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain
information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an
Internet website that contains reports, proxy and information statements, and other information regarding issuers, including
Pioneer, that file electronically with the SEC. The public can obtain any documents that Pioneer files with the SEC at
http://www.sec.gov.

The Company also makes available free of charge through its internet website (www.pxd.com) its Annual Reports on
Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports
filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files
such material with, or furnishes it to, the SEC.

Mission and Strategies

The Company's mission is to enhance shareholder investment returns through strategies that maximize Pioneer's long-
term profitability and net asset value. The strategies employed to achieve this mission are predicated on maintaining financial
flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and
acquisitions. These strategies are anchored by the Company's interests in the long-lived Spraberry oil field; the liquid-rich
Eagle Ford Shale, Barnett Shale Combo, Hugoton and West Panhandle fields; and the Raton gas field; which together have an
estimated remaining productive life in excess of 40 years. Underlying these fields are 94 percent of the Company's proved oil
and gas reserves as of December 31, 2012.

Business Activities

The Company is an independent oil and gas exploration and production company. Pioneer's purpose is to competitively
and profitably explore for, develop and produce oil and gas reserves. In so doing, the Company sells homogenous oil, NGL and
gas units that, except for geographic and relatively minor quality differences, cannot be significantly differentiated from units
offered for sale by the Company's competitors. Competitive advantage is gained in the oil and gas exploration and development
industry by employing well-trained and experienced personnel who make prudent capital investment decisions based on
management direction, embrace technological innovation and are focused on price and cost management.

Petroleum industry. While oil and NGL prices generally improved from 2009 through 2011, during 2012, oil and NGL
production growth in the United States outpaced demand growth causing prices to become more volatile and decline during the
year. North American gas prices have remained volatile and have generally trended lower since 2009. The decline in North
American gas prices is primarily a result of growing gas supplies associated with discoveries of significant gas reserves in
United States shale plays, combined with the warmer than normal recent winters, which has resulted in gas storage levels being
at historically high levels, and minimal economic demand growth in the United States. Oil prices continue to be primarily
driven by world supply and demand fundamentals; however, recent increases in United States oil, NGL and gas production
volumes from the Permian Basin, Eagle Ford, Bakken and Marcellus areas have been met with lower demand, higher storage
levels and pipeline, gas plant and NGL fractionation infrastructure capacity limitations, which has led to a reduction in United
States NYMEX oil, NGL and gas prices compared to international prices for similar commodities, including Brent oil prices.

PIONEER NATURAL RESOURCES COMPANY

During 2010, 2011 and 2012, the economies in the United States and certain other countries stabilized with resulting
improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European
and Asian nations, continue to face economic struggles or slowing economic growth. While the outlook for a continued
worldwide economic recovery remains cautiously optimistic, it is still uncertain; therefore, the sustainability of the recovery in
worldwide demand for energy is difficult to predict. As a result, the Company believes it is likely that commodity prices will
continue to be volatile during 2013.

Significant factors that will affect 2013 commodity prices include: the ongoing effect of economic stimulus initiatives;
fiscal challenges facing the United States federal government and potential changes to the tax laws in the United States;
continuing economic struggles in European and Asian nations; political and economic developments in North Africa and the
Middle East; demand from Asian and European markets; the extent to which members of the Organization of Petroleum
Exporting Countries ("OPEC") and other oil exporting nations are able to manage oil supply through export quotas; and overall
North American NGL and gas supply and demand fundamentals.

Pioneer uses commodity derivative contracts to mitigate the effect of commodity price volatility on the Company's net
cash provided by operating activities and its net asset value. Although the Company has entered into commodity derivative
contracts for a large portion of its forecasted production through 2014, a sustained lower commodity price environment would
result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative
contracts on additional volumes in the future. As a result, the Company's internal cash flows would be reduced for affected
periods. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively
affect the Company's liquidity, financial position and future results of operations. See "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for information regarding the Company's open derivative positions as of December 31,
2012.

The Company. The Company's growth plan is anchored primarily by drilling in the Spraberry oil field located in West
Texas, the liquid-rich Eagle Ford Shale field located in South Texas, the liquid-rich Barnett Shale Combo field in North Texas
and, to a lesser extent, Alaska. Complementing these growth areas, the Company has oil and gas production activities and
development opportunities in the Raton gas field located in southern Colorado, the Hugoton gas and liquid field located in
southwest Kansas, the West Panhandle gas and liquid field located in the Texas Panhandle and the Edwards gas field located in
South Texas. Combined, these assets create a portfolio of resources and opportunities that are well balanced among oil, NGL
and gas, and that are also well balanced among long-lived, dependable production and lower-risk exploration and development
opportunities. The Company has a team of dedicated employees who represent the professional disciplines and sciences that the
Company believes are necessary to allow Pioneer to maximize the long-term profitability and net asset value inherent in its
physical assets.

The Company provides administrative, financial, legal and management support to subsidiaries that explore for, develop
and produce proved reserves. The Company's continuing operations are located in the United States, principally in the states of
Texas, Kansas, Colorado and Alaska.

Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGLs and gas
through development drilling, production enhancement activities and acquisitions of producing properties, while minimizing
the controllable costs associated with the production activities. For the year ended December 31, 2012, the Company's
production from continuing operations of 56.9 MMBOE, excluding field fuel usage, represented a 29 percent increase over
production from continuing operations during 2011. Production, price and cost information with respect to the Company's
properties for 2012, 2011 and 2010 is set forth in "Item 2. Properties — Selected Oil and Gas Information — Production, price
and cost data."

Development activities. The Company seeks to increase its oil and gas reserves, production and cash flow through
development drilling and by conducting other production enhancement activities, such as well recompletions. During the three
years ended December 31, 2012, the Company drilled 1,844 gross (1,655 net) development wells, 99 percent of which were
successfully completed as productive wells, at a total drilling cost (net to the Company's interest) of $4.0 billion.

The Company believes that its current property base provides a substantial inventory of prospects for future reserve,
production and cash flow growth. The Company's proved reserves as of December 31, 2012 include proved undeveloped
reserves and proved developed reserves that are behind pipe of 271.4 MMBBLs of oil, 103.0 MMBBLs of NGLs and 714.6 Bcf
of gas. The Company believes that its current portfolio of proved reserves provides attractive development opportunities for at
least the next five years. The timing of the development of these reserves will be dependent upon commodity prices, drilling
and operating costs and the Company's expected operating cash flows and financial condition.

PIONEER NATURAL RESOURCES COMPANY

Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a highly
skilled geoscience staff as well as acquiring a significant portfolio of lower-risk exploration opportunities that are expected to
be evaluated and tested over the next decade and beyond. Exploratory and extension drilling involve greater risks of dry holes
or failure to find commercial quantities of hydrocarbons than development drilling or enhanced recovery activities. See "Item
1A. Risk Factors — Exploration and development drilling may not result in commercially productive reserves" below.

Integrated services. The Company continues to expand its integrated services to control drilling and operating costs and
support the execution of its drilling program and operating activities. The Company has 15 owned vertical drilling rigs
operating in the Spraberry field, and at the end of 2012, had Company-owned fracture stimulation fleets totaling 300,000
horsepower supporting drilling operations in the Spraberry, Eagle Ford Shale and Barnett Shale Combo areas. During April
2012, the Company acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned
subsidiary, Oglebay Norton Industry Sands, LLC, for an aggregate purchase price of $297.1 million. The Company changed
the name of the Oglebay Norton Industrial Sands LLC to Premier Silica LLC ("Premier Silica") in April 2012. See Note C of
Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more
information about the acquisition of Premier Silica. 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.

Acquisition activities. The Company regularly seeks to acquire properties that complement its operations, provide
exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company
pursues strategic acquisitions that will allow the Company to expand into new geographical areas that provide future
exploration/exploitation opportunities. During 2012, 2011 and 2010, the Company spent $157.5 million, $131.9 million and
$181.6 million, respectively, to purchase primarily undeveloped acreage for future exploitation and exploration activities.

The Company periodically evaluates and pursues acquisition opportunities (including opportunities to acquire particular
oil and gas assets or entities owning oil and gas assets and opportunities to engage in mergers, consolidations or other business
combinations with such entities) and at any given time may be in various stages of evaluating such opportunities. Such stages
may take the form of internal financial analyses, oil and gas reserve analyses, due diligence, the submission of indications of
interest, preliminary negotiations, negotiation of letters of intent or negotiation of definitive agreements. The success of any
acquisition is uncertain and depends on a number of factors, some of which are outside the Company's control. See "Item 1A.
Risk Factors — The Company may be unable to make attractive acquisitions and any acquisition it completes is subject to
substantial risks that could adversely affect its business."

Asset divestitures and discontinued operations. The Company regularly reviews its asset base for the purpose of
identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and
create organizational and operational efficiencies. While the Company generally does not dispose of assets solely for the
purpose of reducing debt, such dispositions can have the result of furthering the Company's objective of increasing financial
flexibility through reduced debt levels.

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 for consideration of $1.7
billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, before normal closing adjustments, and will pay the
remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future drilling and facilities costs attributable to the
horizontal Wolfcamp Shale play. This transaction is expected to close during the second quarter of 2013, subject to
governmental and third party approvals.

During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest its net
assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell Pioneer South
Africa to an unaffiliated third party, 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 of the Company's South Africa subsidiaries. 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 pretax
gain of $28.6 million. The Company classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held
for sale in the accompanying consolidated balance sheet as of December 31, 2011 and (ii) Pioneer South Africa's results of
operations as income from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia
Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third
party for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2

PIONEER NATURAL RESOURCES COMPANY

million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia, prior to its sale, as discontinued
operations, net of tax, in the accompanying consolidated statements of operations.

The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase
capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"
for specific information regarding the Company's asset divestitures and discontinued operations, including the 2011 sale of
Pioneer Tunisia and 2012 sale of Pioneer South Africa.

Marketing of Production

General. Production from the Company's properties is marketed using methods that are consistent with industry
practices. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry,
such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing
supply and demand conditions. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional
discussion of operations and price risk.

Significant purchasers. During 2012, the Company's significant purchasers of oil, NGLs and gas were Plains Marketing
LP (26 percent), Enterprise Products Partners L.P. (15 percent) and Occidental Energy Marketing Inc. (14 percent). The
Company believes that the loss of a significant purchaser or an inability to secure adequate pipeline, gas plant and NGL
fractionation infrastructure in its key producing areas could have a material adverse effect on its ability to sell its oil, NGL and
gas production. See "Item 1A. Risk Factors" and Note L of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for more information about significant customer and infrastructure capacity
risks.

Derivative risk management activities. 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 utilizes commodity swap contracts to reduce price volatility on the
fuel that the Company's drilling rigs and fracture stimulation fleets consume. The Company accounts for its derivative contracts
using the mark-to-market ("MTM") method of accounting. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" for a description of the Company's derivative risk management activities, "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk," and Note E of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for information about the impact of commodity derivative
activities on oil, NGL and gas revenues and net derivative gains and losses during 2012, 2011 and 2010, as well as the
Company's open commodity derivative positions at December 31, 2012.

Competition, Markets and Regulations

Competition. The oil and gas industry is highly competitive. A large number of companies, including major integrated
and other independent companies, and individuals engage in the exploration for and development of oil and gas properties, and
there is a high degree of competition for oil and gas properties suitable for development or exploration. Acquisitions of oil and
gas properties have been an important element of the Company's growth. The Company intends to continue acquiring oil and
gas properties that complement its operations, provide exploration and development opportunities and potentially provide
superior returns on investment. The principal competitive factors in the acquisition of oil and gas properties include the staff
and data necessary to identify, evaluate and acquire such properties and the financial resources necessary to acquire and
develop the properties. Many of the Company's competitors are substantially larger and have financial and other resources
greater than those of the Company.

Markets. The Company's ability to produce and market oil, NGLs and gas profitably depends on numerous factors
beyond the Company's control. The effect of these factors cannot be accurately predicted or anticipated. Although the Company
cannot predict the occurrence of events that may affect these commodity prices or the degree to which these prices will be
affected, the prices for any commodity that the Company produces will generally approximate current market prices in the
geographic region of the production.

Securities regulations. Enterprises that sell securities in public markets are subject to regulatory oversight by agencies
such as the SEC and the NYSE. This regulatory oversight imposes on the Company the responsibility for establishing and
maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial
statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with
the rules and regulations of the SEC could subject the Company to litigation from public or private plaintiffs. Failure to comply

PIONEER NATURAL RESOURCES COMPANY

with the rules of the NYSE could result in the de-listing of the Company's common stock, which would have an adverse effect
on the market price and liquidity of the Company's common stock. Compliance with some of these rules and regulations is
costly, and regulations are subject to change or reinterpretation.

Environmental and occupational health and safety matters. The Company's operations are subject to stringent and
complex federal, state and local laws and regulations governing environmental protection, worker health and safety, and the
discharge of materials into the environment. These laws and regulations may, among other things:
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require the acquisition of various permits before drilling or other regulated activity commences;
enjoin some or all of the operations of facilities deemed in noncompliance with permits;
restrict the types, quantities and concentration of various substances that can be released into the environment in
connection with oil and gas drilling, production and transportation activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
impose specific criteria addressing worker protection; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits
and plug abandoned wells.

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These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise
be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and
consequently affects profitability. Additionally, the U.S. Congress, state legislatures and federal and state regulatory agencies
frequently revise environmental laws and regulations, and the trend in environmental regulation is to place more restrictions
and limitations on activities that may affect the environment. Any changes that result in more stringent and costly waste
handling, disposal and cleanup requirements for the oil and gas industry could have a significant effect on the Company's
operating costs.

The Company believes it is in substantial compliance with all existing environmental laws and regulations applicable to
the Company's current operations and that its continued compliance with existing requirements will not have a material adverse
effect on the Company's financial condition and results of operations. For example, the Company did not incur any material
capital expenditures for remediation or pollution control activities for the year ended December 31, 2012. Additionally, the
Company is not aware of any environmental issues or claims that will require material capital expenditures during 2013.
Nevertheless, accidental spills or releases may occur in the course of the Company's operations, and the Company cannot give
any assurance that it will not incur substantial costs and liabilities as a result of such spills or releases, including those relating
to claims for damage to property and persons. Moreover, the Company cannot give any assurance that the passage of more
stringent laws or regulations in the future will not have a negative effect on the Company's business, financial condition and
results of operations.

The following is a summary of some of the more significant laws and regulations to which the Company's business

operations are or may be subject.

Waste handling. The federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate
the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the
auspices of the federal Environmental Protection Agency (the "EPA"), the individual states administer some or all of the
provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters
and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated
under RCRA's non-hazardous waste provisions. It is possible that certain oil and gas exploration and production wastes now
classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase
in the Company's costs to manage and dispose of wastes, which could have a material adverse effect on the Company's results
of operations and financial position. Also, in the course of the Company's operations, it generates some amounts of ordinary
industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.

Wastes containing naturally occurring radioactive materials ("NORM") may also be generated in connection with the
Company's operations. NORM is subject primarily to individual state radiation control regulations. In addition, NORM
handling and management activities are governed by regulations promulgated by the Occupational Safety and Health
Administration ("OSHA"). These state and OSHA regulations impose certain requirements concerning worker protection; the
treatment, storage and disposal of NORM waste; the management of waste piles, containers and tanks containing NORM; as
well as restrictions on the uses of land with NORM contamination.

Comprehensive Environmental Response, Compensation, and Liability Act. The federal Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, and analogous state laws impose
joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be

PIONEER NATURAL RESOURCES COMPANY

responsible for the release of a hazardous substance into the environment. These persons include the current and past owner or
operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance
released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain
health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released into the environment.

The Company currently owns or leases numerous properties that have been used for oil and gas exploration and
production for many years. Although the Company believes it has used operating and waste disposal practices that were
standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on or
under the properties owned or leased by the Company, or on or under other locations, including off-site locations, where such
substances have been taken for recycling or disposal. In addition, some of the Company's properties have been operated by
previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were
not under the Company's control. Certain of these properties have had historical petroleum spills or releases. All of such
properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, the Company could be required to remove previously disposed substances and wastes, remediate
contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. If a surface spill
or release were to occur, the Company expects that it would be controlled, contained and remediated in accordance with the
applicable requirements of state oil and gas commissions and by using the Company's spill prevention, control and
countermeasure ("SPCC") plans or other spill or emergency contingency plans that it maintains in accordance with EPA
requirements.

Water discharges and use. The federal Clean Water Act (the "CWA") and analogous state laws impose restrictions and
strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of
the United States and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the
terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also
prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an
appropriately issued permit. SPCC planning requirements of federal laws require appropriate containment berms and similar
structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Federal
and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits
or other requirements of the CWA and analogous state laws and regulations.

The primary federal law imposing liability for oil spills is the Oil Pollution Act ("OPA"), which sets minimum standards
for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities and onshore facilities,
including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties,
including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as
well as a variety of public and private damages that may result from oil spills. If an oil spill subject to the requirements of OPA
were to occur at a Company property, the Company expects that it would be controlled, contained and remediated in
accordance with the applicable requirements of OPA and by using the Company's OPA spill response plan together with the
assistance of trained first responders and any oil spill response contractor that the Company would have been required to
engage pursuant to OPA to address such oil spills.

Operations associated with the Company's properties also produce wastewaters that are disposed via injection in
underground wells. These injection wells are regulated by the Safe Drinking Water Act (the "SDWA") and analogous state and
local laws. The underground injection well program under the SDWA requires permits from the EPA or analogous state agency
for the Company's disposal wells, establishes minimum standards for injection well operations, and restricts the types and
quantities of fluids that may be injected. Currently, the Company believes that disposal well operations on the Company's
properties comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to
obtain permits for new injection wells in the future may affect the Company's ability to dispose of produced waters and
ultimately increase the cost of the Company's operations. In addition, in response to recent seismic events near underground
injection wells used for the disposal of oil and gas-related wastewaters, federal and state agencies have begun investigating
whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of
such injection wells. The U.S. Geological Survey is advising the EPA regarding potential seismic hazards associated with these
types of underground injection wells. It is possible that federal or state agencies will seek to regulate more stringently the
underground injection of oil and gas wastewaters as a result of these events. Nevertheless, the Company is not aware of any
imminent actions by federal or state agencies that would affect its use or operation of underground injection wells.

The Company also routinely uses hydraulic fracturing techniques in the majority of its drilling and completion programs
in Texas, Colorado and elsewhere, where development of most of the Company's properties are dependent on the Company's
ability to hydraulically fracture the producing formations. The process involves the injection of water, sand and additives under

PIONEER NATURAL RESOURCES COMPANY

pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil
and gas commissions; however, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel
fuels under the SDWA Underground Injection Control Program and has published draft permitting guidance in May 2012
addressing the performance of such activities. In November 2011, the EPA announced its intent to develop and issue
regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used
in hydraulic fracturing, and the agency currently projects to issue an Advance Notice of Proposed Rulemaking in May 2013
that would seek public input on the design and scope of such disclosure regulations. In August 2012, the EPA published final
rules under the federal Clean Air Act ("CAA"), which became effective October 15, 2012, that, among other things, require
producers to reduce volatile organic compound emissions from certain subcategories of fractured and refractured gas wells for
which well completion operations are being conducted by routing flowback emissions to a gathering line or capturing and
combusting flowback emissions using a combustion device, such as a flare, until January 1, 2015 or performing reduced
emission completions, also known as "green completions," with or without combustion devices, on or after January 1, 2015. In
addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal regulation of
hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In the event that new
federal restrictions relating to the hydraulic-fracturing process are adopted in areas where the Company currently operates or in
the future plans to operate, the Company may incur additional costs to comply with such federal requirements that may be
significant in nature, become subject to additional permitting requirements and experience added delays or curtailment in the
pursuit of exploration, development or production activities.

Certain states in which the Company operates, including Colorado and Texas, have adopted, and other states are
considering adopting, regulations that could impose new or more stringent permitting, disclosure and well-construction
requirements on hydraulic fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the
Railroad Commission of Texas (the "TRRC") and the public of certain information regarding the components used in the
hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or
prohibit drilling in general or hydraulic fracturing in particular. The Company believes that it follows applicable standard
industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, in the
event state or local restrictions are adopted in areas where the Company is currently conducting, or in the future plans to
conduct operations, the Company may incur additional costs to comply with such requirements that may be significant in
nature, experience delays or curtailment in the pursuit of exploration, development or production activities, and be limited or
precluded in the drilling of wells or in the amounts that the Company is ultimately able to produce from its reserves.

Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of
hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide
review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of
hydraulic fracturing on drinking water and groundwater, with a first progress report released by the agency on December 21,
2012 and a final report expected to be available for public comments and peer review by 2014. Moreover, the EPA is
developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and
plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S.
Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These studies, or future studies,
depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic
fracturing under the SDWA or other regulatory mechanisms.

The water produced by the Company's CBM operations also may be subject to the laws of various states and regulatory
bodies regarding the ownership and use of water. For example, in connection with the Company's CBM operations in the Raton
Basin in Colorado, water is removed from coal seams to reduce pressure and allow the methane to be recovered. Historically,
these operations have been regulated by the state agency responsible for regulating oil and gas activity in the state. In a 2008
case brought by the owners of ranch land involving a CBM competitor in a different CBM basin in Colorado, the Colorado
Supreme Court held that water produced in connection with the CBM operations should be subject to state water-use
regulations administered by a different agency that regulates other uses of water in the state, including requirements to obtain
permits for diversion and use of surface and subsurface water, an evaluation of potential competing uses of the water, and a
possible requirement to provide mitigation water for other water users. The Colorado legislature and state agency adopted laws
and regulations in response to this ruling, but there continue to be litigation and uncertainty regarding permitting of produced
water withdrawn in connection with CBM activities. The Company's CBM or other oil and gas operations and the Company's
ability to expand its operations could be adversely affected, and these changes in regulation could ultimately increase the
Company's cost of doing business.

Air emissions. The CAA and comparable state laws regulate emissions of various air pollutants through air emissions
permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-
approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the
increase of existing air emissions; obtain or strictly comply with air permits containing various emissions and operational

PIONEER NATURAL RESOURCES COMPANY

limitations; or utilize specific emission control technologies to limit emissions of certain air pollutants. In addition, the EPA has
developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.
Moreover, states can impose air emissions limitations that are more stringent than the federal standards imposed by the EPA.
Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for noncompliance with air
permits or other requirements of the CAA and associated state laws and regulations.

Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for
controlling air emissions in regional non-attainment areas, may require the Company to incur future capital expenditures in
connection with the addition or modification of existing air emission control equipment and strategies for gas and oil
exploration and production operations. On August 16, 2012, the EPA published final rules under the CAA that subject oil and
gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards
and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, these final rules
require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and
refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low
reservoir pressure non-wildcat and non-delineation gas wells; and all "other" fractured and refractured gas wells. All three
subcategories of wells must route flowback emissions to a gathering line or capture and combust flowback emissions using a
combustion device, such as a flare, after October 15, 2012. However, the "other" wells must use reduced emission
completions, also known as "green completions, " with or without combustion devices, on or after January 1, 2015. These
regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating
compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013. The
Company is currently reviewing this new rule and assessing its potential effects on its operations. Compliance with these
requirements could increase the Company's costs of development and production, which costs could be significant.

In addition, in response to reported concerns about high concentrations of benzene in the air near certain drilling sites
and gas processing facilities in the Barnett Shale area, the Texas Commission on Environmental Quality (the "TCEQ") adopted
new air emissions limitations and permitting requirements for oil and gas facilities in the state, which are applicable to facilities
located in the Barnett Shale area. These new requirements could increase the cost and time associated with drilling wells in the
Barnett Shale. The agency's investigations could lead to additional, more stringent air permitting requirements, increased
regulation, and possible enforcement actions against producers, including Pioneer, in the Barnett Shale area. Any adoption of
laws, regulations, orders or other legally enforceable mandates governing gas drilling and operating activities in the Barnett
Shale or other areas of Texas that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new
wells for any extended period of time could increase the Company's costs or reduce its production, which could have a material
adverse effect on the Company's results of operations and cash flows.

Some gas and oil production facilities may be included within the categories of hazardous air pollutant sources, which
are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity
to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions.

Endangered species. The federal Endangered Species Act (the "ESA") and analogous state laws regulate activities that
could have an adverse effect on threatened or endangered species. Some of the Company's operations are conducted in areas
where protected species or their habitats are known to exist. In these areas, the Company may be obligated to develop and
implement plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited
from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when the
Company's operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a
complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect
on a protected species. The presence of a protected species in areas where the Company performs activities could result in
increased costs or limitations on the Company's ability to perform operations and thus have an adverse effect on the Company's
business.

As a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S.
Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA and issue
decisions with respect to the 250 candidate species before completion of the agency's 2017 fiscal year. The designation of
previously unprotected species as threatened or endangered in areas where the Company operates could cause the Company to
incur increased costs arising from species protection measures or could result in limitations on the Company's exploration and
production activities that could have an adverse effect on the Company's ability to develop and produce its proved reserves.

Occupational health and safety. The Company's operations are subject to the requirements of OSHA and comparable
state statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The
OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar
state statues require that the Company organize or disclose information about hazardous materials used or produced in the

PIONEER NATURAL RESOURCES COMPANY

Company's operations. In addition, the Company's sand mining operations are subject to the Federal Mine Safety and Health
Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent
health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of
personnel, operating procedures, operating equipment and other matters. The Company believes that it is in substantial
compliance with these applicable standards and with OSHA and comparable requirements.

Global warming and climate change. In December 2009, the EPA officially published its findings that emissions of
carbon dioxide, methane and other "greenhouse gases" ("GHGs") present an endangerment to public health and the
environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and
other climatic changes. Based on these findings, the EPA adopted regulations under the CAA in 2010 establishing Title V and
Prevention of Significant Deterioration permitting requirements for large sources of GHGs. The Company could become
subject to these permitting requirements and be required to install "best available control technology" to limit emissions of
GHGs from any new or significantly modified facilities that the Company may seek to construct in the future if they would
otherwise emit large volumes of GHGs. The EPA has also adopted rules requiring the reporting of GHG emissions on an
annual basis from specified GHG emission sources in the United States, including certain oil and gas production facilities,
which includes certain of the Company's facilities. The Company is monitoring GHG emissions from its operations in
accordance with these GHG emissions reporting rules and believes its monitoring activities are in substantial compliance with
applicable reporting obligations.

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been
significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the
absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed
at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG
emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If
the U.S. Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a
carbon tax, which could impose additional direct costs on the Company's operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG
emissions would affect the Company's business, any such future laws and regulations could require the Company to incur
increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or
comply with new regulatory or reporting requirements including the imposition of a carbon tax. Any such legislation or
regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce
the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions
of GHGs could have an adverse effect on the Company's business, financial condition and results of operations.

Some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate
changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other
climatic events. If any such effects were to occur, they could have an adverse effect on the Company's financial condition and
results of operations.

Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous federal, state and local
authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Also, numerous federal and state departments and agencies are authorized by statute to issue
rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties
for failure to comply. Although the regulatory burden on the oil and gas industry may increase the Company's cost of doing
business by increasing the cost of production, these burdens generally do not affect the Company any differently or to any
greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of
production.

Development and production. Development and production operations are subject to various types of regulation at
federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds
in connection with various types of activities and filing reports concerning operations. Most states, and some counties and
municipalities, in which the Company operates also regulate one or more of the following:
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the location of wells;
the method of drilling and casing wells;
the method and ability to fracture stimulate wells;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to surface owners and other third parties.

PIONEER NATURAL RESOURCES COMPANY

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas
properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary
pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may
reduce the Company's interest in the unitized properties. In addition, state conservation laws establish maximum rates of
production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the
ratability of production. These laws and regulations may limit the amount of oil and gas the Company can produce from the
Company's wells or limit the number of wells or the locations at which the Company can drill. Moreover, each state generally
imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States
do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do
so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from the
Company's wells, negatively affect the economics of production from these wells, or limit the number of locations the
Company can drill.

Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales
of gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. Intrastate gas pipeline
transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies. The
interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates
for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission
("FERC"). FERC endeavors to make gas transportation more accessible to gas buyers and sellers on an open-access and non-
discriminatory basis.

Pursuant to the Energy Policy Act of 2005 ("EPAct 2005") it is unlawful for "any entity," including producers such as
the Company, that are otherwise not subject to FERC's jurisdiction under the Natural Gas Act (the "NGA") to use any
deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of
transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC's rules
implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of
FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or
indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to
make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that
operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties up to $1.0
million per day per violation of the NGA and the Natural Gas Policy Act of 1978. The anti-manipulation rule applies to
activities of entities not otherwise subject to FERC's jurisdiction to the extent the activities are conducted "in connection with"
gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under
Order 704 (defined below).

In December 2007, FERC issued a final rule on the annual gas transaction reporting requirements, as amended by
subsequent orders on rehearing ("Order 704"). Under Order 704, any market participant, including a producer such as the
Company, that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBTUs of physical gas in the
previous calendar year must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form
No. 552 contains aggregate volumes of gas purchased or sold at wholesale in the prior calendar year to the extent such
transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting
entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 is intended
to increase the transparency of the wholesale gas markets and to assist FERC in monitoring those markets and in detecting
market manipulation.

Additional proposals and proceedings that might affect the gas industry are considered from time to time by the U.S.
Congress, FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might
become effective or their effect, if any, on its operations. The Company does not believe that it will be affected by any action
taken in a materially different way than other gas producers, gatherers and marketers with which it competes.

Gas gathering. Section 1(b) of the NGA exempts gas gathering facilities from FERC's jurisdiction. The Company
believes that its gathering facilities meet the traditional tests FERC has used to establish a pipeline system's status as a non-
jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities.
Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the
subject of litigation from time to time, so the classification and regulation of some of the Company's gathering facilities may be
subject to change based on future determinations by FERC and the courts. Thus, the Company cannot guarantee that the
jurisdictional status of its gas gathering facilities will remain unchanged.

While the Company owns or operates some gas gathering facilities, the Company also depends on gathering facilities
owned and operated by third parties to gather production from its properties, and therefore the Company is affected by the rates

PIONEER NATURAL RESOURCES COMPANY

charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates
charged for gathering services, the Company also may be affected by these changes. Accordingly, the Company does not
anticipate that the Company would be affected any differently than similarly situated gas producers.

Regulation of transportation and sale of oil and NGLs. The liquids industry is also extensively regulated by numerous
federal, state and local authorities. In a number of instances, the ability to transport and sell such products on interstate
pipelines is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the
Interstate Commerce Act (the "ICA"). The Company does not believe these regulations affect it any differently than other
producers.

The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as
the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of
service on interstate common carrier pipelines be "just and reasonable." Such pipelines must also provide jurisdictional service
in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing
rates and terms and conditions of service before FERC.

Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology,
under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-
year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index
for finished goods plus 2.65 percent. This adjustment is subject to review every five years. Under FERC's regulations, a
liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by
using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual
costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids
transportation rates may result in lower revenue and cash flows for the Company.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers
in an equitable manner in the event there are nominations in excess of capacity. Therefore, new shippers or increased volume
by existing shippers may reduce the capacity available to the Company. Any prolonged interruption in the operation or
curtailment of available capacity of the pipelines that the Company relies upon for liquids transportation could have a material
adverse effect on its business, financial condition, results of operations and cash flows. However, the Company believes that
access to liquids pipeline transportation services generally will be available to it to the same extent as to its similarly-situated
competitors.

Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for
intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline
rates, varies from state to state. The Company believes that the regulation of liquids pipeline transportation rates will not affect
its operations in any way that is materially different from the effects on its similarly-situated competitors.

In November 2009, the Federal Trade Commission ("FTC") issued regulations pursuant to the Energy Independence and
Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil
penalties of up to $1.0 million per violation per day. In July 2010, the U.S. Congress passed the Dodd-Frank Wall Street
Reform and Consumer Protection Act, which incorporated an expansion of the authority of the Commodity Futures Trading
Commission ("CFTC") to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to
oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FERC and the FTC as described
above. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject
violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation.

Energy commodity prices. Sales prices of gas, oil, condensate and NGLs are not currently regulated and are made at
market prices. Although prices of these energy commodities are currently unregulated, the U.S. Congress historically has been
active in their regulation. The Company cannot predict whether new legislation to regulate oil and gas, or the prices charged for
these commodities might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the various
state legislatures and what effect, if any, the proposals might have on the Company's operations.

Transportation of hazardous materials. The federal Department of Transportation has adopted regulations requiring that
certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation
of hazardous materials. The Company does not believe that these requirements will have an adverse effect on the Company or
its operations. The Company cannot provide any assurance that the security plans required under these regulations would
protect against all security risks and prevent an attack or other incident related to the Company's transportation of hazardous
materials.

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PIONEER NATURAL RESOURCES COMPANY

ITEM 1A. RISK FACTORS

The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is
a summary of some of the material risks relating to the Company's business activities. Other risks are described in "Item 1.
Business — Competition, Markets and Regulations" and "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk." These risks are not the only risks facing the Company. The Company's business could also be affected by additional
risks and uncertainties not currently known to the Company or that it currently deems to be immaterial. If any of these risks
actually occurs, it could materially harm the Company's business, financial condition or results of operations and impair the
Company's ability to implement business plans or complete development activities as scheduled. In that case, the market price
of the Company's common stock could decline.

The prices of oil, NGL and gas are highly volatile. A sustained decline in these commodity prices could adversely affect the
Company's financial condition and results of operations.

The Company's revenues, profitability, cash flow and future rate of growth are highly dependent on commodity prices.
Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGL and
gas, market uncertainty and a variety of additional factors that are beyond the Company's control, such as:

domestic and worldwide supply of and demand for oil, NGL and gas;
inventory levels at Cushing, Oklahoma, the benchmark for WTI oil prices;
gas inventory levels in the United States;

overall domestic and global political and economic conditions;
actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
the effect of liquefied natural gas deliveries to and exports from the United States;
technological advances affecting energy consumption and energy supply;
domestic and foreign governmental regulations and taxation;
the effect of energy conservation efforts;
the proximity, capacity, cost and availability of pipelines and other transportation facilities; and
the price and availability of alternative fuels.

In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For
example, during 2012, oil prices fluctuated from a high of $109.77 per BBL in February to a low of $77.69 per BBL in June,
while gas prices fluctuated from a low of $1.91 per MCF in April to a high of $3.90 per MCF in November. During 2011, oil
prices fluctuated from a high $113.93 per BBL in April to a low of $75.67 per BBL in October, while gas prices fluctuated
from a high of $4.85 per MCF in June to a low of $2.99 per MCF in December. The Company makes price assumptions that
are used for planning purposes, and a significant portion of the Company's cash outlays, including rent, salaries and
noncancellable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations
on which these commitments were based, the Company's financial results are likely to be adversely and disproportionately
affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated
decreases in commodity prices.

Significant or extended price declines could also adversely affect the amount of oil, NGL and gas that the Company can
produce economically. A reduction in production could result in a shortfall in expected cash flows and require the Company to
reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively affect the Company's
ability to replace its production and its future rate of growth.

The Company could experience periods of higher costs if commodity prices rise. These increases could reduce the
Company's profitability, cash flow and ability to complete development activities as planned.

Historically, the Company's capital and operating costs have risen during periods of increasing oil, NGL and gas prices.
These cost increases result from a variety of factors beyond the Company's control, such as increases in the cost of electricity,
steel and other raw materials that the Company and its vendors rely upon; increased demand for labor, services and materials as
drilling activity increases; and increased taxes. Increased levels of drilling activity in the oil and gas industry in recent periods
have led to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in the
Company's revenue, thereby negatively impacting the Company's profitability, cash flow and ability to complete development
activities as scheduled and on budget. This impact may be magnified to the extent that the Company's ability to participate in
the commodity price increases is limited by its derivative risk management activities.

PIONEER NATURAL RESOURCES COMPANY

The Company's derivative risk management activities could result in financial losses.

To achieve more predictable cash flow and to manage the Company's exposure to fluctuations in the prices of oil, NGL
and gas, the Company's strategy is to enter into derivative arrangements covering a portion of its oil, NGL and gas production.
These derivative arrangements are subject to MTM accounting treatment, and the changes in fair market value of the contracts
are reported in the Company's statements of operations each quarter, which may result in significant unrealized net gains or
losses. These derivative contracts may also expose the Company to risk of financial loss in certain circumstances, including
when:

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production is less than the contracted derivative volumes;
the counterparty to the derivative contract defaults on its contract obligations; or
the derivative contracts limit the benefit the Company would otherwise receive from increases in commodity prices.

On the other hand, failure to protect against declines in commodity prices exposes the Company to reduced liquidity

when prices decline.

The failure by counterparties to the Company's derivative risk management activities to perform their obligations could
have a material adverse effect on the Company's results of operations.

The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the
financial terms of such transactions. If any of these counterparties were to default on its obligations under the Company's
derivative arrangements, such a default could have a material adverse effect on the Company's results of operations, and could
result in a larger percentage of the Company's future production being subject to commodity price changes.

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

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

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unexpected drilling conditions;
unexpected pressure or irregularities in formations;
equipment failures or accidents;
fracture stimulation accidents or failures;
adverse weather conditions;
restricted access to land for drilling or laying pipelines; and
access to, and the cost and availability of, the equipment, services and personnel required to complete the
Company's drilling, completion and operating activities.

The Company's future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse
effect on the Company's future results of operations and financial condition. While all drilling, whether developmental,
extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to
find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and
abandonment expense in 2013.

Future price declines could result in a reduction in the carrying value of the Company's proved oil and gas properties,
which could adversely affect the Company's results of operations.

Declines in commodity prices may result in the Company having to make substantial downward adjustments to its
estimated proved reserves. If this occurs, or if the Company's estimates of production or economic factors change, accounting
rules may require the Company to impair, as a noncash charge to earnings, the carrying value of the Company's oil and gas
properties. The Company is required to perform impairment tests on proved oil and gas properties whenever events or changes
in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate
a reduction of the estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying
value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved
properties to their fair value. For example, during 2012 and 2011, the Company recognized impairment charges of $532.6
million and $354.4 million, respectively, due to the impairment of the Company's Barnett Shale field and Edwards and Austin
Chalk gas fields in South Texas, primarily due to declines in gas prices and downward adjustments to the economically
recoverable resource potential. The Company may incur impairment charges in the future, which could materially affect the
Company's results of operations in the period incurred.

PIONEER NATURAL RESOURCES COMPANY

The Company periodically evaluates its unproved oil and gas properties and could be required to recognize noncash charges
in the earnings of future periods.

At December 31, 2012, the Company carried unproved property costs of $231.6 million. GAAP requires periodic
evaluation of these costs on a project-by-project basis. These evaluations are affected by the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion of the leases, and contracts and permits
appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully
recover the cost invested in each project, the Company will recognize noncash charges in the earnings of future periods.

The Company periodically evaluates its goodwill for impairment and could be required to recognize noncash charges in the
earnings of future periods.

At December 31, 2012, the Company carried goodwill of $298.1 million. Goodwill is tested for impairment annually
during the third quarter using a July 1 assessment date, and also whenever facts or circumstances indicate that the carrying
value of the Company's goodwill may be impaired, requiring an estimate of the fair values of the reporting unit's assets and
liabilities. Those assessments may be affected by (a) additional reserve adjustments both positive and negative, (b) results of
drilling activities, (c) management's outlook for commodity prices and costs and expenses, (d) changes in the Company's
market capitalization, (e) changes in the Company's weighted average cost of capital and (f) changes in income taxes. If the fair
value of the reporting unit's net assets is not sufficient to fully support the goodwill balance in the future, the Company will
reduce the carrying value of goodwill for the impaired value, with a corresponding noncash charge to earnings in the period in
which goodwill is determined to be impaired.

The Company may be unable to make attractive acquisitions, and any acquisition it completes is subject to substantial risks
that could adversely affect its business.

Acquisitions of producing oil and gas properties have from time to time contributed to the Company's growth. The
Company's growth following the full development of its existing property base could be impeded if it is unable to acquire
additional oil and gas reserves on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive,
which can increase the cost of, or cause the Company to refrain from, completing acquisitions. The success of any acquisition
will depend on a number of factors and involves potential risks, including among other things:

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the inability to estimate accurately the costs to develop the reserves, the recoverable volumes of reserves, rates of
future production and future net cash flows attainable from the reserves;
the assumption of unknown liabilities, losses or costs for which the Company is not indemnified or for which the
indemnity the Company receives is inadequate;
the validity of assumptions about costs, including synergies;
the effect on the Company's liquidity or financial leverage of using available cash or debt to finance acquisitions;
the diversion of management's attention from other business concerns; and
an inability to hire, train or retain qualified personnel to manage and operate the Company's growing business and
assets.

All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable
return on investment. Even though the Company performs a review of the properties it seeks to acquire that it believes is
consistent with industry practices, such reviews are often limited in scope. As a result, among other risks, the Company's initial
estimates of reserves may be subject to revision following an acquisition, which may materially and adversely affect the desired
benefits of the acquisition.

The Company's ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond its control,
and in certain cases the Company may be required to retain liabilities for certain matters.

From time to time, the Company sells an interest in a strategic asset for the purpose of assisting or accelerating the
asset's development. In addition, the Company regularly reviews its property base for the purpose of identifying nonstrategic
assets, the disposition of which would increase capital resources available for other activities and create organizational and
operational efficiencies. Various factors could materially affect the ability of the Company to dispose of such interests or
nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third
parties (as is the case with respect to the Company's southern Wolfcamp joint interest transaction) and the availability of
purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to the Company.
For example, during the fourth quarter of 2012, the Company was unable to dispose of its Barnett Shale assets under acceptable
terms. Consequently, the Company no longer expects to dispose of the Barnett Shale assets during 2013 and has reclassified
the Barnett Shale assets to held for use and their historical results of operations to continuing operations. See "Item 7.

PIONEER NATURAL RESOURCES COMPANY

Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note C of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information about
the Barnett Shale disposition plans.

Sellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained

liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material.
Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other
credit support provided prior to the sale of the divested assets. As a result, after a divestiture, the Company may remain
secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these
obligations.

The Company's gas processing operations are subject to operational risks, which could result in significant damages and
the loss of revenue.

As of December 31, 2012, the Company owned interests in four gas processing plants and ten treating facilities. The
Company is the operator of two of the gas processing plants and all ten of the treating facilities. There are significant risks
associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens.
Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic
gases, which could result in significant damage claims in addition to interrupting a revenue source.

The Company's operations involve many operational risks, some of which could result in unforeseen interruptions to the
Company's operations and substantial losses to the Company for which the Company may not be adequately insured.

The Company's operations, including well stimulation and completion activities, such as hydraulic fracturing, are subject

to all the risks normally incident to the oil and gas development and production business, including:

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blowouts, cratering, explosions and fires;
adverse weather effects;
environmental hazards, such as gas leaks, oil spills, pipeline and vessel ruptures, encountering NORM, and
unauthorized discharges of toxic gases, brine, well stimulation and completion fluids or other pollutants into the
surface and subsurface environment;
high costs, shortages or delivery delays of equipment, labor or other services or water for hydraulic fracturing;
facility or equipment malfunctions, failures or accidents;
title problems;
pipe or cement failures or casing collapses;
compliance with environmental and other governmental requirements;
lost or damaged oilfield workover and service tools;
unusual or unexpected geological formations or pressure or irregularities in formations; and
natural disasters.

The Company's overall exposure to operational risks may increase as its drilling activity expands and as it seeks to
directly provide drilling, fracture stimulation and other services internally. Any of these risks could result in substantial losses
to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up
responsibilities, regulatory investigations and penalties and suspension of operations.

The Company is not fully insured against certain of the risks described above, either because such insurance is not
available or because of the high premium costs and deductibles associated with obtaining such insurance. Additionally, the
Company relies to a large extent on facilities owned and operated by third-parties, and damage to or destruction of those third-
party facilities could affect the ability of the Company to produce, transport and sell its hydrocarbons.

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

The Company has identified drilling locations and prospects for future drilling opportunities, including development,
exploratory and infill drilling and enhanced recovery activities. These drilling locations and prospects represent a significant
part of the Company's future drilling plans. For example, the Company's proved reserves as of December 31, 2012 include
proved undeveloped reserves and proved developed reserves that are behind pipe of 271.4 MMBBLs of oil, 103.0 MMBBLs of
NGLs and 714.6 BCF of gas. The Company's ability to drill and develop these locations depends on a number of factors,
including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties,

PIONEER NATURAL RESOURCES COMPANY

commodity prices, costs, access to and availability of equipment, services and personnel and drilling results. Because of these
uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in
the realization of proved reserves or meet the Company's expectations for success. As such, the Company's actual drilling and
enhanced recovery activities may materially differ from the Company's current expectations, which could have a significant
adverse effect on the Company's proved reserves, financial condition and results of operations.

The Company may not be able to obtain access to pipelines and storage facilities, gas gathering systems and other
transportation, processing, fractionation and refining facilities to market its oil, NGL and gas production; the Company
relies on a limited number of purchasers for a majority of its products.

The marketing of oil, NGL and gas production depends in large part on the availability, proximity and capacity of
pipelines and storage facilities, gas gathering systems and other transportation, processing, fractionation and refining facilities,
as well as the existence of adequate markets. If there were insufficient capacity available on these systems, if these systems
were unavailable to the Company, or if access to these systems were to become commercially unreasonable, the price offered
for the Company's production could be significantly depressed, or the Company could be forced to shut in some production or
delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its
own facility. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in
order to store, process, transport, fractionate and sell its oil, NGL and gas production. The Company's plans to develop and sell
its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide
sufficient transportation, storage or processing and fractionation facilities to the Company, especially in areas of planned
expansion where such facilities do not currently exist.

To the extent that the Company enters into transportation contracts with gas pipelines that are subject to FERC
regulation, the Company is subject to FERC requirements related to use of such capacity. Any failure on the Company's part to
comply with FERC's regulations and policies or with an interstate pipeline's tariff could result in the imposition of civil and
criminal penalties.

A limited number of companies purchase a majority of the Company's oil, NGLs and gas. The loss of a significant

purchaser could have a material adverse effect on the Company's ability to sell its production.

The nature of the Company's assets and production operations exposes it to significant costs and liabilities with respect to
environmental and occupational safety matters.

The oil and gas business involves the production, handling, sale and disposal of environmentally sensitive materials and
is subject to environmental hazards, such as oil spills, produced water spills, gas leaks, pipeline and vessel ruptures and
unauthorized discharges of substances or gases, that could expose the Company to substantial liability due to pollution and
other environmental damage. Pollution and similar environmental risks generally are not fully insurable either because such
insurance is not available or because of the high premium costs and deductible associated with obtaining such insurance. A
variety of federal, state and local laws and regulations govern the environmental aspects of the oil and gas business.
Noncompliance with these laws and regulations may subject the Company to administrative, civil or criminal penalties,
remedial cleanups, and natural resource damages or other liabilities, and compliance with these laws and regulations may
increase the cost of the Company's operations. Such laws and regulations may also affect the costs of acquisitions. See "Item 1.
Business — Competition, Markets and Regulations — Environmental and occupational health and safety matters" above for
additional discussion related to environmental risks.

Environmental laws and regulations are subject to amendment or replacement by more stringent laws and regulations
and no assurance can be given that continued compliance with existing or future environmental laws and regulations will not
result in a curtailment of production or processing activities, result in a material increase in the costs of production,
development, exploration or processing operations or adversely affect the Company's future operations and financial condition.

The Company could incur significant costs and liabilities in responding to contamination that occurs at its properties or as
a result of its operations.

There is inherent risk of incurring significant environmental costs and liabilities in operations upon the Company's
properties due to its handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to
its operations, and as a result of historical operations and waste disposal practices by prior owners and operators. The
Company currently owns, leases or operates properties that for many years have been used for oil and gas exploration and
production activities, and petroleum hydrocarbons, hazardous substances and wastes have been released on or under such
properties and could be released during future operations. Joint and several strict liabilities may be incurred in connection with
such releases of petroleum hydrocarbons and wastes on, under or from the Company's properties. Private parties, including
lessors of properties on which the Company operates and the owners or operators of properties adjacent to the Company's

PIONEER NATURAL RESOURCES COMPANY

operations and facilities where the Company's petroleum hydrocarbons or wastes are taken for reclamation or disposal, may
also have the right to pursue legal actions to enforce compliance as well as seek damages for noncompliance with
environmental laws and regulations or for personal injury or property damage. The Company may not be able to recover some
or any of these costs from insurance or other sources of indemnity.

The Company's credit facilities and debt instruments have substantial restrictions and financial covenants that may restrict
its business and financing activities.

The Company is a borrower under fixed rate senior notes, convertible senior notes and credit facilities. The terms of the
Company's borrowings under the senior notes, convertible senior notes and the credit facilities specify scheduled debt
repayments and require the Company to comply with certain associated covenants and restrictions. The Company's ability to
comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other things, factors
outside the Company's direct control, such as commodity prices and interest rates. See Note G of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the
Company's outstanding debt as of December 31, 2012 and the terms associated therewith.

The Company's ability to obtain additional financing is also affected by the Company's debt credit ratings and

competition for available debt financing.

The Company faces significant competition, and many of its competitors have resources in excess of the Company's
available resources.

The oil and gas industry is highly competitive. The Company competes with a large number of companies, producers

and operators in a number of areas such as:

seeking to acquire oil and gas properties suitable for development or exploration;

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• marketing oil, NGL and gas production; and
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seeking to acquire the equipment and expertise, including trained personnel, necessary to evaluate, operate and
develop properties.

Many of the Company's competitors are larger and have substantially greater financial and other resources than the

Company. See "Item 1. Business — Competition, Markets and Regulations" for additional discussion regarding competition.

The Company is subject to regulations that may cause it to incur substantial costs.

The Company's business is regulated by a variety of federal, state and local laws and regulations. For instance, in
connection with the Company's CBM operations in the Raton Basin in Colorado, the Colorado Supreme Court affirmed a state
water court holding that water produced in connection with CBM operations should be subject to state water-use regulations,
including regulations requiring permits for diversion and use of surface and subsurface water, an evaluation of potential
competing permits, possible uses of the water and a possible requirement to provide augmentation water supplies for water
rights owners with more senior rights. There can be no assurance that present or future regulations will not adversely affect the
Company's business and operations, including that the Company may be required to suspend drilling operations or shut in
production pending compliance. See "Item 1. Business — Competition, Markets and Regulations" for additional discussion
regarding government regulation.

The Company's sales of oil, gas, NGLs or other energy commodities, and any derivative activities related to such energy
commodities, expose the Company to potential regulatory risks.

FERC, the FTC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy
commodities markets relevant to the Company's business. These agencies have imposed broad regulations prohibiting fraud
and manipulation of such markets. With regard to the Company's physical sales of oil, gas, NGLs or other energy commodities,
and any derivative activities related to these energy commodities, the Company is required to observe the market-related
regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations,
as interpreted and enforced, could materially and adversely affect the Company's business results of operations and financial
condition.

Estimates of proved reserves and future net cash flows are not precise. The actual quantities and net cash flows of the
Company's proved reserves may prove to be lower than estimated.

Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. The
estimates of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which
may ultimately prove to be inaccurate.

PIONEER NATURAL RESOURCES COMPANY

Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend
upon a number of variable factors and assumptions, including the following:

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historical production from the area compared with production from other producing areas;
the quality and quantity of available data;
the interpretation of that data;
the assumed effects of regulations by governmental agencies;
assumptions concerning future commodity prices; and
assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs,
transportation costs and workover and remedial costs.

Because all proved reserve estimates are to some degree subjective, each of the following items may differ materially

from those assumed in estimating proved reserves:

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the quantities of oil and gas that are ultimately recovered;
the production costs incurred to recover the reserves;
the amount and timing of future development expenditures; and
future commodity prices.

Furthermore, different reserve engineers may make different estimates of proved reserves and cash flows based on the
same available data. The Company's actual production, revenues and expenditures with respect to proved reserves will likely be
different from estimates, and the differences may be material.

As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on average prices
preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially
higher or lower. Actual future net cash flows also will be affected by factors such as:

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the amount and timing of actual production;
levels of future capital spending;
increases or decreases in the supply of or demand for oil, NGLs and gas; and
changes in governmental regulations or taxation.

Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies
subject to the rules and regulations of the SEC. In general, it requires the use of commodity prices that are based upon a 12-
month unweighted average, as well as operating and development costs being incurred at the end of the reporting period.
Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of
seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to
produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be
materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor,
which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the
most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or
the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows or Standardized Measure in this
Report should not be construed as accurate estimates of the current market value of the Company's proved reserves.

The Company's actual production could differ materially from its forecasts.

From time to time, the Company provides forecasts of expected quantities of future oil and gas production. These
forecasts are based on a number of estimates, including expectations of production from existing wells and the outcome of
future drilling activity. Should these estimates prove inaccurate, actual production could be adversely affected. In addition, the
Company's forecasts assume that none of the risks associated with the Company's oil and gas operations summarized in this
"Item 1A. Risk Factors" occur, such as facility or equipment malfunctions, adverse weather effects, or downturns in commodity
prices or significant increases in costs, which could make certain drilling activities or production uneconomical.

A subsidiary of the Company acts as the general partner of a publicly-traded limited partnership. As such, the subsidiary's
operations may involve a greater risk of liability than ordinary business operations.

A subsidiary of the Company acts as the general partner of Pioneer Southwest, a publicly-traded limited partnership
formed by the Company to own, develop and acquire oil and gas assets in its area of operations. As general partner, the
subsidiary may be deemed to have undertaken fiduciary obligations to Pioneer Southwest.

PIONEER NATURAL RESOURCES COMPANY

Activities determined to involve fiduciary obligations to others typically involve a higher standard of conduct than
ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interest is
found to exist. Any such liability may be material.

The tax treatment of Pioneer Southwest depends on its status as a partnership for federal income tax purposes as well as its
not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (the
"IRS") were to treat Pioneer Southwest as a corporation for federal income tax purposes or Pioneer Southwest becomes
subject to a material amount of entity-level taxation for state tax purposes, then the value of the Company's investment in
Pioneer Southwest would be substantially reduced.

The Company currently owns a 52.4 percent limited partner interest and a 0.1 percent general partner interest in Pioneer
Southwest. The value of the Company's investment in Pioneer Southwest depends largely on its being treated as a partnership
for federal income tax purposes. A publicly traded partnership may be treated as a corporation for United States federal income
tax purposes unless 90 percent or more of its gross income for every year is "qualifying income" under section 7704 of the
Internal Revenue Code of 1986, as amended. Pioneer Southwest has not requested and does not plan to request a ruling from
the IRS with respect to its treatment as a partnership for federal income tax purposes.

A change in Pioneer Southwest's business could cause it to be treated as a corporation for federal income tax purposes.
In addition, a change in current law may cause Pioneer Southwest to be treated as a corporation for such purposes. For
example, members of U.S. Congress have from time to time considered substantive changes to the existing federal income tax
laws that would affect the tax treatment of certain publicly traded partnerships. Moreover, because of widespread state budget
deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state
income, franchise or other forms of taxation. If Pioneer Southwest were subject to federal income tax as a corporation or any
state were to impose a tax upon Pioneer Southwest, its cash available to pay distributions would be reduced. Therefore,
treatment of Pioneer Southwest as a corporation would result in a material reduction in the anticipated cash flow and after-tax
return to Pioneer Southwest's unitholders, including the Company, and would likely cause a substantial reduction in the value
of the Company's investment in Pioneer Southwest.

Pioneer Southwest's partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a
manner that subjects it to taxation as a corporation or otherwise subjects it to entity-level taxation for federal, state or local
income tax purposes, the minimum quarterly distribution and the target distribution amounts may be adjusted to reflect the
effect of that law on Pioneer Southwest.

The Company's business could be negatively affected by security threats, including cybersecurity threats, and other
disruptions.

As an oil and gas producer, the Company faces various security threats, including cybersecurity threats to gain
unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the Company's
facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from
terrorist acts. The potential for such security threats has subjected the Company's operations to increased risks that could have a
material adverse effect on the Company's business. In particular, the Company's implementation of various procedures and
controls to monitor and mitigate security threats and to increase security for the Company's information, facilities and
infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and
controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they
could lead to losses of sensitive information, critical infrastructure or capabilities essential to the Company's operations and
could have a material adverse effect on the Company's reputation, financial position, results of operations or cash flows.
Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software,
attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions
in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These
events could damage the Company's reputation and lead to financial losses from remedial actions, loss of business or potential
liability.

A failure by purchasers of the Company's production to perform their obligations to the Company could require the
Company to recognize a pre-tax charge in earnings and have a material adverse effect on the Company's results of
operation.

While the credit and equity markets have improved during 2010, 2011 and 2012, the economic outlook for 2013 remains
uncertain. The Company relies on a limited number of purchasers to purchase a majority of its products. To the extent that
purchasers of the Company's production rely on access to the credit or equity markets to fund their operations, there is a risk
that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the
credit or equity markets for an extended period of time. If for any reason the Company were to determine that it was probable

PIONEER NATURAL RESOURCES COMPANY

that some or all of the accounts receivable from any one or more of the purchasers of the Company's production were
uncollectible, the Company would recognize a pre-tax charge in the earnings of that period for the probable loss.

Declining general economic, business or industry conditions could have a material adverse effect on the Company's results
of operations.

Concerns over the worldwide economic outlook, geopolitical issues, the availability and cost of credit and the U.S.
mortgage and real estate markets have contributed to increased volatility and diminished expectations for the global economy.
These factors, combined with volatile commodity prices, declining business and consumer confidence and increased
unemployment resulted in a worldwide recession. While the worldwide economic outlook seems to be improving, concerns
about global economic growth or government debt in Europe or the United States could have a significant adverse effect on
global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate,
demand for petroleum products could diminish, which could depress the prices at which the Company could sell its oil, NGLs
and gas and ultimately decrease the Company's net revenue and profitability.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may
be eliminated as a result of future legislation.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws,
including elimination of certain key U.S. federal income tax incentives currently available to oil and gas companies. Such tax
legislation changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas
properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the
deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and
geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such
changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws
could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and
development, and any such change could negatively affect the value of an investment in the Company's common stock and
defer planned capital expenditures if such changes accelerated the payment of taxes.

The adoption of climate change legislation by the U.S. Congress or regulation by the EPA could result in increased
operating costs and reduced demand for the oil, NGLs and gas the Company produces.

In December 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to public
health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's
atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations under the CAA in 2010
establishing Title V and Prevention of Significant Deterioration permitting requirements for large sources of GHGs. The
Company could become subject to these permitting requirements and be required to install "best available control technology"
to limit emissions of GHGs from any new or significantly modified facilities that the Company may seek to construct in the
future if they would otherwise emit large volumes of GHGs. The EPA has also adopted rules requiring the reporting of GHG
emissions on an annual basis from specified GHG emission sources in the United States, including certain oil and gas
production facilities, which include certain of the Company's facilities. The Company is monitoring GHG emissions from its
operations in accordance with these GHG emissions reporting rules and believes that its monitoring activities are in substantial
compliance with applicable reporting obligations.

While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been
significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the
absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed
at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG
emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If the
U.S. Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon
tax, which could impose additional direct costs on the Company's operations.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address
GHG emissions would affect the Company's business, any such future laws and regulations could require the Company to incur
increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or
comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Any such legislation or
regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and gas, which could reduce
the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions
of GHGs could have an adverse effect on the Company's business, financial condition and results of operations. Also, some
scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that
have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic

PIONEER NATURAL RESOURCES COMPANY

events. If any such effects were to occur, they could have an adverse effect on the Company's financial condition and results of
operations. See "Item 1. Business – Competition, Markets and Regulations - Environmental and occupational health and safety
matters - Global warming and climate change" for additional discussion relating to global warming and climate change.

The enactment of derivatives legislation could have an adverse effect on the Company's ability to use derivative instruments
to reduce the effect of commodity price, interest rate and other risks associated with its business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") enacted on July 21, 2010, established
federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate
in that market. The Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Act. In its
rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in
the major energy markets and for swaps that are their economic equivalents. Certain bona fide derivative transactions would be
exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of
Colombia in September 2012, although the CFTC has stated that it will appeal the District Court's decision. The CFTC also
has finalized other regulations, including critical rulemakings on the definition of "swap", "security-based swap", "swap dealer"
and "major swap participant." The Act and the CFTC rules also will require the Company, in connection with certain derivative
activities, to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such
requirements). In addition, new regulations may require the Company to comply with margin requirements although these
regulations are not finalized and their application to the Company is uncertain at this time. Other regulations also remain to be
finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is
not possible at this time to predict with certainty the full effects of the Act and the CFTC rules on the Company and the timing
of such effects. The Act also may require the counterparties to the Company's derivative instruments to spin off some of their
derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new
regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral,
which could adversely affect the Company's available liquidity), materially alter the terms of derivative contracts, reduce the
availability of derivatives to protect against risks the Company encounters, reduce the Company's ability to monetize or
restructure its existing derivative contracts, and increase the Company's exposure to less creditworthy counterparties. If the
Company reduces its use of derivatives as a result of the Act and regulations implementing the Act, the Company's results of
operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company's
ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and gas
prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas.
The Company's revenues could therefore be adversely affected if a consequence of the Act and implementing regulations is to
lower commodity prices. Any of these consequences could have a material adverse effect on the Company, its financial
condition and its results of operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental
reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect
the Company's production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from
tight formations. The Company routinely utilizes hydraulic fracturing techniques in the majority of its drilling and completion
programs. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to
stimulate oil and gas production. The process is typically regulated by state oil and gas commissions; however, the EPA has
asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the SDWA's Underground Injection
Control Program and published draft permitting guidance in May 2012 addressing the performance of such activities. In
November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to
require companies to disclose information regarding the chemicals used in hydraulic fracturing, and the agency currently
projects to issue an Advance Notice of Proposed Rulemaking in May 2013 that would seek public input on the design and
scope of such disclosure regulations. In August 2012, the EPA published final rules under the CAA, which became effective
October 15, 2012, that, among other things, require producers to reduce volatile organic compound emissions from certain
subcategories of fractured and refractured gas wells for which well completion operations are being conducted by routing
flowback emissions to a gathering line or capturing and combusting flowback emissions using a combustion device, such as a
flare, until January 1, 2015 or performing reduced emission completions, also known as "green completions," with or without
combustion devices, on or after January 1, 2015. In addition, the U.S. Congress, from time to time, has considered adopting
legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in
the hydraulic-fracturing process. In the event that a new federal level of legal restrictions relating to the hydraulic-fracturing
process is adopted in areas where the Company currently or in the future plans to operate, the Company may incur additional
costs to comply with such federal requirements that may be significant in nature, become subject to additional permitting
requirements and experience added delays or curtailment in the pursuit of exploration, development or production activities.

PIONEER NATURAL RESOURCES COMPANY

Certain states in which the Company operates, including Colorado and Texas have adopted, and other states are
considering adopting, regulations that could impose new or more stringent permitting, disclosure, and well-construction
requirements on hydraulic-fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the
TRRC and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to
state laws, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing
in particular. The Company believes that it follows applicable standard industry practices and legal requirements for
groundwater protection in its hydraulic fracturing activities. Nonetheless, in the event state or local restrictions are adopted in
areas where the Company is currently conducting, or in the future plan to conduct operations, the Company may incur
additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the
pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in
the amounts that the Company is ultimately able to produce from its reserves.

Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of
hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide
review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of
hydraulic fracturing on drinking water and groundwater, with a first progress released by the agency on December 21, 2012 and
a final report expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent
limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose
these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of
the Interior, are evaluating various other aspects of hydraulic fracturing. These studies, or future studies, depending on their
degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the
SDWA or other regulatory mechanisms. See "Item 1. Business - Competition, Markets and Regulations - Environmental and
occupational health and safety matters" above for additional discussion related to environmental risks associated with the
Company's hydraulic fracturing activities.

Provisions of the Company's charter documents and Delaware law may inhibit a takeover, which could limit the price
investors might be willing to pay in the future for the Company's common stock.

Provisions in the Company's certificate of incorporation and bylaws may have the effect of delaying or preventing an
acquisition of the Company or a merger in which the Company is not the surviving company and may otherwise prevent or
slow changes in the Company's board of directors and management. In addition, because the Company is incorporated in
Delaware, it is governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could
discourage an acquisition of the Company or other change in control transaction and thereby negatively affect the price that
investors might be willing to pay in the future for the Company's common stock.

The Company is growing production in areas of high industry activity, which may affect its ability to obtain the personnel,
equipment, services, resources and facilities access needed to complete its development activities as planned or result in
increased costs.

The Company's operations and drilling activity are concentrated in areas in which industry activity has increased rapidly,
particularly in the Spraberry field in West Texas and the Eagle Ford Shale play in South Texas. As a result, demand for
personnel, equipment, power, services and resources, as well as access to transportation, processing and refining facilities in
these areas, has increased, as have the costs for those items. In addition, hydraulic fracturing and other operations require
significant quantities of water, which supply may be affected by drought conditions. Any delay or inability to secure the
personnel, equipment, power, services, resources and facilities access necessary for the Company to complete its planned
development activities, including the result of any changes in laws or regulations applicable to the Company's operations
relating to water usage, could result in oil and gas production volumes being below the Company's forecasted volumes. In
addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect
on the Company's profitability.

Laws and regulations pertaining to threatened and endangered species could delay or restrict the Company's operations and
cause it to incur substantial costs.

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their
habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, the
CWA and CERCLA. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it
believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could
result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and
gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government
entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for
harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous

PIONEER NATURAL RESOURCES COMPANY

substances or other regulated materials, and, in some cases, may seek criminal penalties. Moreover, as a result of a settlement
approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is
required to consider listing more than 250 species as endangered or threatened under the ESA before completion of the
agency's 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the
Company conducts operations could cause the Company to incur increased costs arising from species protection measures or
could result in limitations on its exploration and production activities that could have an adverse effect on the Company's
ability to develop and produce reserves.

The Company's sand mining operations are subject to operating risks that are often beyond the Company's control, and
such risks may not be covered by insurance.

Ownership of industrial sand mining operations are subject to risks, many of which are beyond the Company's control.

These risks include:

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unusual or unexpected geological formations or pressures;
cave-ins, pit wall failures or rock falls;
unanticipated ground, grade or water conditions;
inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;
environmental hazards, such as unauthorized spills, releases and discharges of wastes, vessel ruptures, and emission
of unpermitted levels of pollutants;
changes in laws and regulations;
inability to acquire or maintain necessary permits or mining or water rights;
restrictions on blasting operations;
inability to obtain necessary production equipment or replacement parts;
reduction in the amount of water available for processing;
technical difficulties or failures;
labor disputes;
late delivery of supplies;
fires, explosions or other accidents; and
facility shutdowns in response to environmental regulatory actions.

Any of these risks could result in damage to, or destruction of, the Company's mining properties or production facilities,
personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Not all of these risks
are insurable, and the Company's insurance coverage contains limits, deductibles, exclusions and endorsements. The
Company's insurance coverage may not be sufficient to meet its needs in the event of loss and any such loss may have a
material adverse effect on the Company.

The Company's estimates of sand reserves and resource deposits are imprecise and actual reserves could be less than
estimated.

The Company bases its sand reserve and resource estimates on engineering, economic and geological data assembled
and analyzed by engineers and geologists, which are reviewed by outside firms. However, commercial sand reserve estimates
are necessarily imprecise and depend to some extent on statistical inferences drawn from available drilling data, which may
prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of commercial sand reserves
and costs to mine recoverable reserves, including many factors beyond the Company's control. Estimates of economically
recoverable commercial sand reserves necessarily depend on a number of factors and assumptions, all of which may vary
considerably from actual results, such as:

•

geological and mining conditions or effects from prior mining that may not be fully identified by available data or
that may differ from experience;
assumptions concerning future prices of commercial sand products, operating costs, mining technology
improvements, development costs and reclamation costs; and
assumptions concerning future effects of regulation, including the issuance of required permits and taxes by
governmental agencies.

PIONEER NATURAL RESOURCES COMPANY

The Company's sand mining operations are subject to extensive environmental and occupational health and safety
regulations that impose significant costs and potential liabilities.

The Company's sand mining operations are subject to a variety of federal, state and local environmental requirements
affecting the mining and mineral processing industry, including, among others, those relating to employee health and safety,
environmental permitting and licensing, air emissions and water discharges, GHG emissions, water pollution, waste
management and disposal, remediation of soil and groundwater contamination, land use restrictions, reclamation and
restoration of properties, hazardous materials and natural resources. Some environmental laws impose substantial penalties for
noncompliance, and others, such as the CERCLA, impose strict, retroactive and joint and several liability for the remediation of
releases of hazardous substances. Failure to properly handle, transport, store or dispose of hazardous materials or otherwise
conduct the Company's sand mining operations in compliance with environmental laws could expose the Company to liability
for governmental penalties, cleanup costs and civil or criminal liability associated with releases of such materials into the
environment, damages to property or natural resources and other damages, as well as potentially impair the Company's ability
to conduct its sand mining operations. In addition, environmental laws and regulations are subject to amendment, replacement
or interpretation by more stringent and comprehensive legal requirements. The Company's continued compliance with existing
or future laws and regulations could restrict the Company's ability to expand its facilities or extract mineral deposits or could
require the Company to acquire costly equipment or to incur other significant expenses in connection with its sand mining
operations, which restrictions or costs could have a material adverse effect on the Company's sand mining operations.

Any failure by the Company to comply with applicable environmental laws and regulations in connection with its sand

mining operations may cause governmental authorities to take actions that could adversely affect the Company, including:

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•

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issuance of administrative, civil and criminal penalties;
denial, modification or revocation of permits or other authorizations;
imposition of injunctive obligations or other limitations on the Company's operations, including cessation of
operations; and
requirements to perform site investigatory, remedial or other corrective actions.

In addition to environmental regulation, the Company's sand mining operations are subject to laws and regulations
relating to worker health and safety, including such matters as human exposure to crystalline silica dust. Several federal and
state regulatory authorities, including the U.S. Mining Safety and Health Administration, may continue to propose changes in
their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls
and personal protective equipment.

The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, which imposes
stringent health and safety standards on numerous aspects of the Company's sand mining operations.

The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by
the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on
numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures,
operating equipment and other matters. The Company's failure to comply with such standards, or changes in such standards or
the interpretation or enforcement thereof, could have a material adverse effect on the Company's sand mining operations or
otherwise impose significant restrictions on the Company's ability to conduct mineral extraction and processing operations.

The Company's sand mining operations are subject to extensive other regulations that impose significant costs and
liabilities.

In addition to the environmental and occupational health and safety regulation discussed above, the Company's sand
mining operations are also subject to extensive governmental regulation on matters such as permitting and licensing
requirements, reclamation and restoration of mining properties after mining is completed, and the effects that mining have on
groundwater quality and availability. Also, the Company's sand mining operations require numerous governmental,
environmental, mining and other permits, water rights and approvals authorizing operations at each sand mining facility.

In order to obtain permits and renewals of permits in the future for its sand mining operations, the Company may be
required to prepare and present data to governmental authorities pertaining to the effect that any such activities may have on the
environment. Obtaining or renewing required permits may be delayed or prevented due to opposition by neighboring property
owners, members of the public or other third parties and other factors beyond the Company's control. A decision by a
governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or
substantially modify an existing permit or approval, could have a material adverse effect on the Company's sand mining

PIONEER NATURAL RESOURCES COMPANY

operations at the affected facility. Current or future regulations could have a material adverse effect on the Company's sand
mining operations and the Company may not be able to renew or obtain permits in the future.

The Company's sand mining operations entail silica-related health issues and litigation that could have a material adverse
effect on the Company.

The inhalation of respirable crystalline silica dust is associated with the lung disease silicosis. There is evidence of an
association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases,
including immune system disorders, such as scleroderma. These health risks have been, and may continue to be, a significant
issue confronting the commercial sand industry. The actual or perceived health risks of mining, processing and handling sand
could materially and adversely affect the Company through the threat of product liability or employee lawsuits and increased
scrutiny by federal, state and local regulatory authorities.

Premier Silica is named as a defendant, usually among many defendants, in numerous products liability lawsuits brought
by or on behalf of current or former employees of Premier Silica's customers alleging damages caused by silica exposure. As of
December 31, 2012, Premier Silica was the subject of approximately 2,500 silica exposure claims, the great majority of which
have been inactive for many years due to the plaintiffs' failure to meet specific legal requirements to advance their claims.
Almost all of the claims pending against Premier Silica arise out of the alleged use of Premier Silica's sand products in
foundries or as an abrasive blast media and have been filed in the states of Texas, Louisiana, Florida and West Virginia,
although some cases have been brought in many other jurisdictions over the years.

It is possible that Premier Silica will continue to have silica-related products liability claims filed against it, including
claims that allege silica exposure for periods for which there is not insurance coverage. Any pending or future claims or
inadequacies of insurance coverage or indemnification from the seller could have a material adverse effect on the Company's
results of operations.

The Company's pending sale of 40 percent of its acreage in the horizontal Wolfcamp Shale play in the southern portion of
the Spraberry field is contingent upon the satisfaction of certain conditions and may not be consummated on the terms or
timeline contemplated and may not achieve the intended results.

In January 2013, the Company agreed to sell 40 percent of its interest in 207,000 net acres leased by the Company in the
horizontal Wolfcamp Shale play in the southern portion of the Spraberry field to Sinochem, an unaffiliated third party, for
consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to Pioneer, before normal closing
adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of the Company's portion of future drilling and
facilities costs attributable to the horizontal Wolfcamp Shale play. The Company expects this transaction to close during the
second quarter of 2013. However, the parties' obligations to consummate this transaction are conditioned upon the satisfaction
or waiver of certain closing conditions, including governmental and third party approvals. If these conditions are not satisfied
or waived, the acquisition will not be consummated. If the closing of the transaction is substantially delayed or does not occur
at all, the Company may not realize the anticipated benefits of the transaction fully or at all. Further, if the transaction is not
completed, the Company would need to reevaluate its capital expenditure budget and reduce its activities or obtain funding
from other sources.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Reserve Estimation Procedures and Audits

The information included in this Report about the Company's proved reserves as of December 31, 2012, 2011 and 2010
is based on evaluations prepared by the Company's engineers and (i) audited by Netherland, Sewell & Associates, Inc.
("NSAI"), with respect to the Company's major properties for all periods, and (ii) with respect to the Company's Oooguruk field
properties in Alaska, audited by Ryder Scott Company, L.P. ("RSC"), as of December 31, 2012. The Company has no oil and
gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure of probable or
possible reserves. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information regarding the sale of the Company's share holdings in Pioneer Tunisia during February
2011 and the Company's sale of Pioneer South Africa in August 2012.

PIONEER NATURAL RESOURCES COMPANY

Reserve estimation procedures. The Company has established internal controls over reserve estimation processes and
procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and
GAAP requirements. These controls include oversight of the reserves estimation reporting processes by Pioneer's Worldwide
Reserves Group (the "WWR"), and annual external audits of substantial portions of the Company's proved reserves by NSAI
and RSC.

Individual asset teams are responsible for the day-to-day management of the oil and gas activities in each of the
Company's Permian Basin, Rockies, Mid-Continent, South Texas, Barnett Shale and Alaska asset areas (the "Asset Teams").
The Company's Asset Teams are each staffed with reservoir engineers and geoscientists who prepare reserve estimates at the
end of each calendar quarter for the assets that they manage, using reservoir engineering information technology. There is
shared oversight of the Asset Teams' reservoir engineers by the Asset Teams' managers and the Director of the WWR, each of
whom is in turn subject to direct or indirect oversight by the Company's management committee ("MC"). The Company's MC
is comprised of its Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and other Executive Vice
Presidents. The Asset Teams' reserve estimates are reviewed by the asset team reservoir engineers before being submitted to the
WWR for further review.

The reserve estimates are summarized in reserve reconciliations that quantify reserve changes since the previous year
end as revisions of previous estimates, purchases of minerals-in-place, improved recovery, extensions and discoveries,
production and sales of minerals-in-place. All reserve estimates, material assumptions and inputs used in reserve estimates and
significant changes in reserve estimates are reviewed for engineering and financial appropriateness and compliance with SEC
and GAAP standards by the WWR, in consultation with the Company's accounting and financial management personnel.
Annually, the MC reviews the reserve estimates and any differences with the reserve auditors (for the portion of the reserves
audited by NSAI and RSC) on a consolidated basis before these estimates are approved. The engineers and geoscientists who
participate in the reserve estimation and disclosure process periodically attend training provided by external consultants and/or
through internal Pioneer programs. Additionally, the WWR has prepared and maintains written policies and guidelines for the
Asset Teams to reference on reserve estimation and preparation to promote objectivity in the preparation of the Company's
reserve estimates and SEC and GAAP compliance in the reserve estimation and reporting process.

Proved reserves audits. The proved reserve audits performed by NSAI for 2012, 2011 and 2010, and by RSC for 2012, in
the aggregate represented 95 percent, 90 percent and 90 percent of the Company's 2012, 2011 and 2010 proved reserves,
respectively; and, 99 percent, 91 percent and 79 percent of the Company's 2012, 2011 and 2010 associated pre-tax present
value of proved reserves discounted at ten percent, respectively.

NSAI and RSC follow the general principles set forth in the "Standards Pertaining to the Estimating and Auditing of Oil
and Gas Reserve Information" promulgated by the Society of Petroleum Engineers (the "SPE"). A reserve audit as defined by
the SPE is not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:
•

A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to
whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with the 2007
SPE publication entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information."
The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot
be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of
verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies,
procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an
opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.
The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed
in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the
reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own
estimates of reserve information for the audited properties.

•

In conjunction with the audit of the Company's proved reserves and associated pre-tax present value discounted at ten
percent, Pioneer provided to NSAI and RSC its external and internal engineering and geoscience technical data and analyses.
Following the reserve auditors' review of that data, they had the option of honoring Pioneer's interpretations, or making their
own interpretations. No data was withheld from NSAI or RSC. The reserve auditors accepted without independent verification
the accuracy and completeness of the historical information and data furnished by Pioneer with respect to ownership interest,
oil and gas production, well test data, commodity prices, operating and development costs, and any agreements relating to
current and future operations of the properties and sales of production. However, if in the course of their evaluations something
came to their attention that brought into question the validity or sufficiency of any such information or data, the reserve
auditors did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had
independently verified such information or data.

PIONEER NATURAL RESOURCES COMPANY

In the course of their evaluations, NSAI and RSC prepared, for all of the audited properties, their own estimates of the
Company's proved reserves and the pre-tax present values of such reserves discounted at ten percent. The reserve auditors
reviewed their audit differences with the Company, and, in a number of cases, held meetings with the Company to review
additional reserves work performed by the Company's technical teams and any updated performance data related to the proved
reserve differences. Such data was incorporated, as appropriate, by both parties into the proved reserve estimates. The reserve
auditors' estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax present
value of such reserves discounted at ten percent did not differ from Pioneer's estimates by more than ten percent in the
aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of the Company's estimates
were greater than those of the reserve auditors and some were less than the estimates of the reserve auditors. When such
differences do not exceed ten percent in the aggregate and NSAI and RSC are satisfied that the proved reserves and pre-tax
present values of such reserves discounted at ten percent are reasonable and that their audit objectives have been met, NSAI
and RSC will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit of
continuing such analyses by the Company and the reserve auditors. At the conclusion of the audit process, it was the opinions
of NSAI and RSC, as set forth in their audit letters, which are included as exhibits to this Report, that Pioneer's estimates of the
Company's proved oil and gas reserves and associated pre-tax present values discounted at ten percent are, in the aggregate,
reasonable and have been prepared in accordance with the "Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information" promulgated by the SPE.

See "Item 1A. Risk Factors," "Critical Accounting Estimates" in "Item 7. Management's Discussion and Analysis and
Results of Operations" and "Item 8. Financial Statements and Supplementary Data" for additional discussions regarding proved
reserves and their related cash flows.

Qualifications of reserves preparers and auditors. The WWR is staffed by petroleum engineers with extensive industry
experience and is managed by the Director of the WWR, the technical person that is primarily responsible for overseeing the
Company's reserves estimates. These individuals meet the professional qualifications of reserves estimators and reserves
auditors as defined by the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,"
promulgated by the SPE. The WWR Director's qualifications include 35 years of experience as a petroleum engineer, with 28
years focused on reserves reporting for independent oil and gas companies, including Pioneer. His educational background
includes an undergraduate degree in Chemical Engineering and a Masters of Business Administration degree in Finance. He is
also a Chartered Financial Analyst Charterholder.

NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and
government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board
of Professional Engineers Registration No. F-2699. The technical person primarily responsible for auditing the Company's
reserves estimates has been a practicing consulting petroleum engineer at NSAI since 1983 and has over 34 years of practical
experience in petroleum engineering, including over 32 years of experience in the estimation and evaluation of proved reserves.
He graduated with a Bachelor of Science degree in Chemical Engineering in 1978 and meets or exceeds the education, training
and experience requirements set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information" promulgated by the board of directors of the SPE.

RSC provides worldwide petroleum property analysis services for energy clients, financial organizations and
government agencies. RSC was founded in 1937 and performs consulting petroleum engineering services under Texas Board of
Professional Engineers Registration No. F-1580. The technical person primarily responsible for auditing the Company's
reserves estimates has been a practicing consulting petroleum engineer at RSC since 2000 and has over 28 years of practical
experience in petroleum engineering. He graduated with a Bachelor of Science degree in Petroleum Engineering and a Master
of Business Administration degree and meets or exceeds the education, training and experience requirements set forth in the
"Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the board of
directors of the SPE.

Technologies used in reserves estimates. Proved undeveloped reserves include those reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for
completion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development
areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of
economic producibility. Undrilled locations may be classified as having undeveloped proved reserves only if an ability and
intent has been established to drill the reserves within five years, unless specific circumstances justify a longer time period.

In the context of reserves estimations, reasonable certainty means a high degree of confidence that the quantities will be
recovered and reliable technology means a grouping of one or more technologies (including computational methods) that has
been field-tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the
formation being evaluated or in an analogous formation. In estimating proved reserves, the Company uses several different

PIONEER NATURAL RESOURCES COMPANY

traditional methods such as performance-based methods, volumetric-based methods and analogy with similar properties. In
addition, the Company utilizes additional technical analysis such as seismic interpretation, wireline formation tests, geophysical
logs and core data to provide incremental support for more complex reservoirs. Information from this incremental support is
combined with the traditional technologies outlined above to enhance the certainty of the Company's reserve estimates.

Proved Reserves

As of December 31, 2012, the Company's oil and gas proved reserves are located entirely in the United States. Less
than one percent of proved reserves as of December 31, 2011 were associated with discontinued operations in South Africa and
three percent of proved reserves as of December 31, 2010 were associated with discontinued operations in South Africa and
Tunisia. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional details of the Company's discontinued operations. The following table provides
information regarding the Company's proved reserves and Standardized Measure as of December 31, 2012, 2011 and 2010:

Summary of Oil and Gas Reserves as of Fiscal Year-End
Based on Average Fiscal-Year Prices

Reserve Volumes

Oil
(MBBLs)

NGLs
(MBBLs)

Gas
(MMCF) (a)

Total (MBOE)

Standardized
Measure
(in thousands)

December 31, 2012:

Developed ..................................
Undeveloped ..............................
Total Proved ...................................

230,700
256,138
486,838

134,637
97,939
232,576

1,605,209
592,271
2,197,480

632,872
452,789
1,085,661

58% $ 5,010,779
42%
1,342,619
100% $ 6,353,398

December 31, 2011:
Developed ..................................
Undeveloped ..............................
Total Proved ...................................

December 31, 2010:
Developed ..........................................
Undeveloped.......................................
Total Proved ...................................

190,206
239,799
430,005

120,405
90,630
211,035

1,853,363
677,675
2,531,038

619,506
443,375
1,062,881

58% $ 5,494,007
42% $ 2,319,016
100% $ 7,813,023

172,816
207,993
380,809

108,785
75,433
184,218

1,775,611
898,911
2,674,522

577,537
433,244
1,010,781

57% $ 4,065,879
43% $ 1,346,130
100% $ 5,412,009

______________________
(a)

The gas reserves contain 280,344 MMCF, 301,123 MMCF and 303,748 MMCF of gas that will be produced and used as
field fuel (primarily for compressors) before the gas is delivered to a sales point, for December 31, 2012, 2011 and 2010,
respectively.

See the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements and Supplementary

Data" for additional details of the estimated quantities of the Company's proved reserves.

Description of Properties

Approximately 78 percent of the Company's proved reserves at December 31, 2012 are located in the Spraberry field in
the Permian Basin area, the Hugoton and West Panhandle fields in the Mid-Continent area and the Raton field in the Rocky
Mountains area. These fields generate substantial operating cash flow, which provides funding for the Company's development
and exploration activities in the Spraberry field, Eagle Ford Shale play, Barnett Shale Combo play and Alaska.

PIONEER NATURAL RESOURCES COMPANY

The following tables summarize the Company's development and exploration/extension drilling activities during 2012:

Beginning Wells
In Progress

Wells
Spud

Development Drilling
Successful
Wells

Unsuccessful
Wells

Ending Wells
In Progress

Permian Basin ...............................................
Raton Basin ...................................................
Barnett Shale .................................................
Alaska ............................................................
Total ..............................................................

161
5
—
1
167

633
—
4
5
642

649
4
4
2
659

9
1
—
—
10

136
—
—
4
140

Exploration/Extension Drilling

Beginning Wells
In Progress

Wells
Spud

Successful
Wells

Unsuccessful
Wells

Ending
Wells In
Progress

Permian Basin ...............................................
Mid-Continent ...............................................
South Texas—Eagle Ford Shale ....................
Barnett Shale .................................................
Alaska ............................................................
Total ..............................................................

—
5
39
26
1
71

50
—
130
36
2
218

33
—
137
53
—
223

—
5
—
—
1
6

17
—
32
9
2
60

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during

2012:

Permian Basin .................................................................
Mid-Continent .................................................................
Raton Basin .....................................................................
Barnett Shale ...................................................................
South Texas—Eagle Ford Shale ......................................
South Texas—Edwards and Austin Chalk ......................
Alaska ..............................................................................
Other ................................................................................
Total ................................................................................
_____________________

Oil (BBLs)

44,042
3,175
—
1,210
9,871
75
4,269
3
62,645

NGLs (BBLs)
12,623
7,102
—
2,756
7,332
1
—
2
29,816

Gas (MCF) (a)
61,922
46,192
149,787
20,085
63,338
36,945
—
100
378,369

Total (BOE)

66,985
17,976
24,965
7,314
27,759
6,233
4,269
21
155,522

(a) Gas production excludes gas produced and used as field fuel.

PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the Company's costs incurred by asset area during 2012:

Property
Acquisition Costs

Proved

Unproved

Exploration
Costs

Development
Costs
(in thousands)

Asset
Retirement
Obligations

Total

4,755
Permian Basin ............................................. $
—
Mid-Continent .............................................
—
Raton Basin .................................................
—
South Texas—Eagle Ford Shale ..................
—
South Texas—Edwards and Austin Chalk ..
12,114
Barnett Shale ...............................................
—
Alaska ..........................................................
Other ............................................................
69
Total ............................................................ $ 16,938
____________________
(a)

$ 70,558
4,211
—
12,194
130
12,288
106
41,028
$ 140,515

$ 441,127
4,136
8,111
229,364
4,534
200,376
73,475
3,505
$ 964,628

$ 1,603,688
17,884
7,467
9,476
5,434
60,606
120,246 (a)

10
$ 1,824,811

$ 36,221
529
16,254
1,461
1,502
(317 )
3,241

(19 )

$ 58,872

$ 2,156,349
26,760
31,832
252,495
11,600
285,067
197,068
44,593
$ 3,005,764

Includes $8.5 million of capitalized interest associated with the Oooguruk development project.

Permian Basin

Spraberry field. The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. According
to the Energy Information Administration, the Spraberry field is the second largest oil field in the United States. The field is
approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and
the gas produced is casinghead gas with an average energy content of 1,400 BTU. The oil and gas are produced primarily from
four formations, the upper and lower Spraberry, the Dean and the Wolfcamp, at depths ranging from 6,700 feet to 11,300 feet.
In addition, the Company is drilling deeper to the Strawn, Atoka and Mississippian intervals with positive results.

The Company believes the Spraberry field offers excellent opportunities to grow oil and gas production because of the
numerous undeveloped drilling locations, many of which are reflected in the Company's proved undeveloped reserves. The
Spraberry field has the ability to improve incremental recovery rates through infill and deeper formation drilling, waterflood
projects and horizontal drilling in certain formations while containing operating expenses and drilling costs through economies
of scale and vertical integration of field services.

During 2012, the Company drilled 691 wells in the Spraberry field and its total acreage position now approximates
827,000 gross acres (707,000 net acres). The Company currently has 24 rigs operating in the Spraberry field, of which 15 are
drilling vertical wells and nine are drilling horizontal Wolfcamp Shale wells. During 2013, the Company expects to drill
approximately 290 vertical wells and 120 horizontal wells, with the horizontal wells being principally in the Wolfcamp Shale
horizon. Excluding the southern Wolfcamp joint interest area, the Company expects to incur $1.2 billion of drilling capital in
the Spraberry field during 2013.

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

The Company believes it also has significant horizontal potential within the northern portion of its acreage in the play.
During the fourth quarter of 2012, the Company initiated horizontal Wolfcamp drilling activities to delineate the northern part
of its Spraberry acreage position by drilling in Midland County. During 2013, the Company plans to also test the Wolfcamp
Shale potential in Martin County and possibly Gaines County. Wells drilled in these areas 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 expects to utilize four horizontal
rigs in its northern acreage during 2013 to delineate the area's resource potential.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval. This
deeper drilling includes the Strawn, Atoka and Mississippian intervals. Production from these deeper intervals contributed to
the Company's production growth during 2012. The 2013 drilling program reflects 90 percent of the wells being deepened

PIONEER NATURAL RESOURCES COMPANY

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, that 40 percent to 50 percent of its acreage position is prospective for the Atoka interval
and that the Mississippian interval is prospective in 20 percent of the Company's Spraberry acreage.

In the Spraberry interval, during 2012, the Company drilled two successful horizontal Jo Mill wells with lateral lengths
of 2,628 and 2,178 feet. The Company is continuing to analyze the results of the two wells and plans to drill additional
horizontal Jo Mill wells in 2013.

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 $1.7 billion. At closing Sinochem will pay $522.0 million in cash to Pioneer, before
normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's portion of future
drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to close during the
second quarter of 2013, subject to governmental and third party approvals.

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. To the extent the joint interest partner elects to participate in any vertical wells that are drilled in the joint
interest area after the December 1, 2012 effective date, the joint interest partner will receive its share of production and costs
from the Wolfcamp and deeper horizons based on the anticipated reserve contribution from the Wolfcamp and deeper intervals
relative to anticipated reserves from all completed intervals. Pioneer's and the joint interest owner's participation in vertical
wells will be based on each party's interest without any drilling carry being applied. Pioneer will retain 100 percent of its
vertical production in the joint interest area for wells drilled before the December 1, 2012 effective date.

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 drilling rigs and has five
Company-owned vertical fracture stimulation fleets totaling 100,000 horsepower and two Company-owned horizontal fracture
stimulation fleets totaling 70,000 horsepower currently operating in the Spraberry field. To support its growing operations, the
Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks,
hot oilers, blowout preventers, construction equipment and fishing tools. In addition, in early April 2012, the Company
completed the acquisition of Premier Silica, which is expected to supply the Company's growing brown sand requirements for
proppant that will be used for fracture stimulating wells in the vertical Spraberry and horizontal Wolfcamp Shale plays.

Mid-Continent

Hugoton field. The Hugoton field in southwest Kansas is one of the largest producing gas fields in the continental
United States. The gas is produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000
feet. The Company's Hugoton properties are located on 268,000 gross acres (235,000 net acres), covering approximately 400
square miles. The Company has working interests in approximately 1,220 wells in the Hugoton field, approximately 1,000 of
which it operates.

The Company operates substantially all of the gathering and processing facilities, including the Satanta plant, which
processes the production from the Hugoton field. In January 2011, the Company sold a 49 percent interest in the Satanta plant
to an unaffiliated third party for the third party's commitment to dedicate gas volumes to the Satanta plant. This agreement has
increased the Satanta plant's processing volumes and is expected to increase its economic longevity. The Company is also
exploring opportunities to process other gas production in the Hugoton area at the Satanta plant. By maintaining operatorship of
the gathering and processing facilities, the Company is able to control the production, gathering, processing and sale of its
Hugoton field gas and NGL production.

West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas. These stable, long-
lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no
greater than 3,500 feet. The Company's gas has an average energy content of 1,365 BTU and is produced from approximately
867 wells on more than 333,000 gross acres (312,000 net acres) covering over 375 square miles. The Company controls 100
percent of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is
operated at or below vacuum conditions, Pioneer continually works to improve compressor and gathering system efficiency.

Raton Basin

The Raton Basin properties are located in the southeast portion of Colorado. The Company owns 212,000 gross acres
(186,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton

PIONEER NATURAL RESOURCES COMPANY

formations from approximately 2,300 wells. The Company owns the majority of the well servicing and fracture stimulation
equipment that it utilizes in the Raton field, allowing it to control costs and insure availability.

South Texas Eagle Ford Shale and Edwards

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

The Company completed 137 horizontal Eagle Ford Shale wells during 2012, all of which were successful, with average
lateral lengths of 5,700 feet and, on average, 13-stage fracture stimulations. The Company plans to incur $575 million of
drilling capital and utilize 10 drilling rigs in 2013 to drill 134 wells. The Company plans to primarily use two Pioneer-owned
fracture stimulation fleets during 2013.

The Company has also been testing the use of 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 is continuing to monitor the performance of these wells and expects that greater than 50 percent of its 2013
drilling program will use lower-cost white sand proppant.

During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction,
the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and
gas properties to an unaffiliated third party for $212.0 million of cash proceeds. Under the terms of the transaction, the
purchaser also paid 75 percent (representing $886.8 million) of the Company's defined exploration, drilling and completion
costs attributable to the Eagle Ford Shale assets during the period from June 2010 through December 2012. As of December
31, 2012, the purchaser's obligation has been satisfied. The Company also sold a 49.9 percent member interest in EFS
Midstream LLC ("EFS Midstream"), an entity formed by the Company to own and operate gas and liquids gathering, treating
and transportation assets in the Eagle Ford Shale play, to the purchaser for $46.4 million of cash proceeds and deferred a $46.2
million associated net gain. The Company does not have voting control of EFS Midstream and does not consolidate its
financial statements.

EFS Midstream is obligated to construct midstream assets in the Eagle Ford Shale area. Construction of the midstream
assets is continuing, with the majority of the construction expected to be completed by the end of 2013. Eleven of the 13
planned central gathering plants were completed as of December 31, 2012. EFS Midstream is providing gathering, treating and
transportation services for the Company during a 20-year contractual term. During 2011, EFS Midstream entered into a $300
million, five-year revolving credit facility that is being used to fund infrastructure investments that exceed its operating cash
flows.

Barnett Shale

The Company has accumulated 93,000 gross acres in the liquid-rich Barnett Shale Combo area in North Texas. In
addition, the Company has acquired approximately 340 square miles of proprietary 3-D seismic covering its acreage, which it
is using to high-grade future drilling location selections. The Company's total lease holdings in the Barnett Shale play now
approximate 149,000 gross acres (114,000 net acres).

During the first half of 2012, the Company had two drilling rigs and one Pioneer-owned fracture stimulation fleet

operating in the field. During August 2012, the Company reduced to one drilling rig as a result of lower NGL and gas prices.
The Company drilled 57 Barnett Shale Combo wells during 2012.

During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the Barnett Shale field in
North Texas, retained a capital markets advisor and actively solicited offers from interested purchasers of the Barnett Shale
field assets. Those efforts were unsuccessful in attracting binding offers under acceptable terms to the Company. Since the
Company was unable to dispose of its Barnett Shale assets under acceptable terms, in December 2012, the Company decided to
retain the assets; therefore, as of December 31, 2012, the Barnett Shale assets and liabilities no longer qualified as held for sale
or discontinued operations.

During 2013, the Company plans to increase from one drilling rig to two drilling rigs early in the second quarter. The

Company expects to drill 55 wells in 2013 and incur capital expenditures of $185.0 million.

PIONEER NATURAL RESOURCES COMPANY

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 18 production wells and ten injection wells to develop this project. During the first quarter
of 2012, the Company drilled an exploration well which was drilled from an onshore location to further evaluate the
productivity of the Torok formation and the feasibility of future development expansion. The Company flow tested the well
during April 2012 until production could no longer be transported along the ice road being utilized. The well had a gross initial
production rate of approximately 2,000 barrels of oil per day. The well will be production tested again this winter pending
permanent onshore production facilities, for which an onshore development front-end engineering design (FEED) study has
been initiated. In September 2012, the Company entered into a contract for a drilling rig that is currently drilling a second
onshore well in the Torok formation to further appraise its resource potential.

During the first quarter of 2012, the Company also completed its first successful mechanically diverted fracture
stimulation of a Nuiqsut interval well from the Oooguruk development facilities. Gross initial production from the test was at a
rate of 4,000 barrels of oil per day. Based on the success of this fracture stimulation, the Company plans to fracture stimulate
four new wells this winter using a similar completion design.

During 2013, the Company expects to incur capital expenditures of $190.0 million in Alaska to continue development
with a one rig program at Oooguruk, mechanically fracture stimulate four wells this winter on the island drill site and to
complete the other appraisal well in the Torok formation from the onshore drilling location.

International

During 2012, the Company's international operations were entirely located in offshore South Africa and during 2011, the
Company's international operations were located in Tunisia and offshore South Africa. During August 2012 and February
2011, the Company completed the sale of Pioneer South Africa and Pioneer Tunisia, respectively, to different unaffiliated third
parties. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information regarding the sale of Pioneer South Africa and Pioneer Tunisia. As a result of these sales,
the Company no longer has operations outside the United States.

Selected Oil and Gas Information

The following tables set forth selected oil and gas information for the Company as of and for each of the years ended
December 31, 2012, 2011 and 2010. Because of normal production declines, increased or decreased drilling activities and the
effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative
of future results.

Production, price and cost data. The price that the Company receives for the oil and gas it produces is largely a function
of market supply and demand. Demand is affected by general economic conditions, weather and other seasonal conditions,
including hurricanes and tropical storms. Over or under supply of oil or gas can result in substantial price volatility.
Historically, commodity prices have been volatile and the Company expects that volatility to continue in the future. A
substantial or extended decline in oil or gas prices or poor drilling results could have a material adverse effect on the
Company's financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically
produced and the Company's ability to access capital markets.

The following tables set forth production, price and cost data with respect to the Company's properties for 2012, 2011
and 2010. These amounts represent the Company's historical results from operations without making pro forma adjustments for
any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not
match the reserve volume tables in the "Unaudited Supplementary Information" section included in "Item 8. Financial
Statements and Supplementary Data" because field fuel volumes are included in the reserve volume tables.

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA

Year Ended December 31, 2012

Spraberry
Field

United States
Raton
Field

Total

South Africa

Total

Production information:
Annual sales volumes:

Oil (MBBLs) ................................................................
NGLs (MBBLs) ............................................................
Gas (MMCF) ................................................................
Total (MBOE) ..............................................................

Average daily sales volumes:

Oil (BBLs) ....................................................................
NGLs (BBLs) ...............................................................
Gas (MCF)....................................................................
Total (BOE) ..................................................................

Average prices, including hedge results and
amortization of deferred VPP revenue (a):

Oil (per BBL) ............................................................... $
NGL (per BBL) ............................................................ $
Gas (per MCF) ............................................................. $
Revenue (per BOE) ...................................................... $

Average prices, excluding hedge results and
amortization of deferred VPP revenue (a):

Production costs:

Lease operating .......................................................... $
Third-party transportation charges ............................. $
Net natural gas plant/gathering .................................. $
Workover ................................................................... $
Total ........................................................................... $

Production and ad valorem taxes:

Ad valorem ................................................................ $
Production .................................................................. $
Total ........................................................................... $
Depletion expense ....................................................... $

16,096
4,451
21,345
24,104

43,978
12,160
58,319
65,858

—
—
54,822
9,137

—
—
149,787
24,965

22,928
10,913
138,483
56,921

62,645
29,816
378,369
155,522

157
—
3,784
787

428
—
10,340
2,151

23,085
10,913
142,267
57,708

63,073
29,816
388,709
157,673

90.57
32.23
2.58
68.72

87.95
32.23
2.58
66.97

$
$
$
$

$
11.34
0.17
$
(0.49 ) $
$
1.71
$
12.73

1.78
3.47
5.25
15.58

$
$
$
$

—
—
2.41
14.48

6.47
3.12
1.82
—
11.41

0.17
0.11
0.28
19.52

$
$
$
$

$
$
$
$
$

$
$
$
$

90.89
33.75
2.60
49.40

$ 108.62
—
$
8.50
$
62.48
$

89.19
33.75
2.60
48.71

$ 108.62
—
$
8.50
$
62.48
$

8.53
1.31
0.47
0.85
11.16

1.26
2.04
3.30
13.61

$
$
$
$
$

$
$
$
$

2.86
—
—
—
2.86

—
—
—
—

$
$
$
$

$
$
$
$
$

$
$
$
$

91.01
33.75
2.75
49.57

89.32
33.75
2.75
48.90

8.46
1.29
0.47
0.84
11.06

1.24
2.01
3.25
13.42

____________________
(a)

The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its
hedging activities at a field level. As of December 31, 2012, the Company has no further obligation to deliver oil under
the VPP obligation.

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)

Production information:
Annual sales volumes:

Oil (MBBLs) ...........................................
NGLs (MBBLs) .......................................
Gas (MMCF) ...........................................
Total (MBOE) .........................................

Average daily sales volumes:

Oil (BBLs) ...............................................
NGLs (BBLs) ..........................................
Gas (MCF)...............................................
Total (BOE) .............................................
Average prices, including hedge results
and amortization of deferred VPP
revenue (a):

Oil (per BBL) .......................................... $
NGL (per BBL) ....................................... $
Gas (per MCF) ........................................ $
Revenue (per BOE) ................................. $

Average prices, excluding hedge results
and amortization of deferred VPP
revenue (a):

Average costs (per BOE):

Production costs:

Lease operating ..................................... $
Third-party transportation charges ........ $
Net natural gas plant/gathering ............. $
Workover .............................................. $
Total ...................................................... $

Production and ad valorem taxes:

Ad valorem ........................................... $
Production ............................................. $
Total ...................................................... $
Depletion expense .................................. $

Year Ended December 31, 2011

Spraberry
Field

United States
Raton
Field

Total

South Africa

Tunisia

Total

10,011
3,844
15,899
16,505

27,428
10,530
43,559
45,218

—
—
58,601
9,767

—
—
160,550
26,758

14,825
8,208
125,516
43,953

40,618
22,487
343,879
120,418

193
—
7,508
1,445

530
—
20,570
3,958

201
—
181
229

547
—
496
630

15,219
8,208
133,205
45,627

41,695
22,487
364,945
125,006

95.93
42.38
3.44
71.37

91.44
42.38
3.44
68.65

$
$
$
$

10.40
$
$
—
(1.45) $
$
1.74
$
10.69

1.73
3.87
5.60
11.41

$
$
$
$

—
—
3.81
22.86

6.49
3.01
2.15
—
11.65

0.41
0.31
0.72
14.46

$
$
$
$

$
$
$
$
$

$
$
$
$

96.60
46.27
3.84
52.19

$ 108.14
—
$
7.62
$
54.09
$

91.35
46.27
3.84
50.42

$ 108.14
—
$
7.62
$
54.09
$

8.08
1.12
0.15
0.82
10.17

1.24
2.11
3.35
12.55

$
$
$
$
$

$
$
$
$

2.35
—
—
—
2.35

—
—
—
29.00

$
$
$
$

$
$
$
$
$

$
$
$
$

99.03
—
13.04
96.29

$
$
$
$

7.61
1.91

$
$
— $
(0.27) $
$
9.25

—
—
—
—

$
$
$
$

96.78
46.27
4.07
52.48

91.67
46.27
4.07
50.77

7.90
1.22
0.14
0.78
10.04

1.20
2.04
3.24
13.01

_____________________
(a)

The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its
hedging activities at a field level.

PIONEER NATURAL RESOURCES COMPANY

PRODUCTION, PRICE AND COST DATA - (Continued)

Year Ended December 31, 2010

Spraberry
Field

United States
Raton
Field

Total

South Africa

Tunisia

Total

Production information:
Annual sales volumes:

Average daily sales volumes:

Average prices, excluding hedge results
and amortization of deferred VPP
revenue (a):

Average costs (per BOE):

Production costs:

Production and ad valorem taxes:

6,314
3,725
14,242
12,413

17,300
10,206
39,020
34,009

—
—
62,311
10,385

—
—
170,716
28,453

10,297
7,203
122,369
37,895

28,211
19,736
335,256
103,823

225
—
10,862
2,035

616
—
29,760
5,576

91.53
33.11
3.41
60.40

77.24
33.11
3.41
53.14

$
$
$
$

11.40
$
$
—
(1.66) $
$
1.88
$
11.62

2.30
3.53
5.83
9.02

$
$
$
$

—
—
4.20
25.19

6.11
2.35
1.93
0.07
10.46

0.46
0.52
0.98
14.39

$
$
$
$

$
$
$
$
$

$
$
$
$

90.56
38.14
4.18
45.34

74.21
37.12
4.15
40.61

7.74
0.87
0.08
0.92
9.61

1.49
1.47
2.96
12.40

$
$
$
$

$
$
$
$
$

$
$
$
$

78.07
—
6.20
41.74

0.68
—
—
—
0.68

—
—
—
36.50

$
$
$
$

$
$
$
$
$

$
$
$
$

1,781
—
1,040
1,954

4,880
—
2,849
5,355

78.42
—
11.25
77.46

4.98
1.50
—
0.36
6.84

—
—
—
12.07

12,303
7,203
134,271
41,885

33,707
19,736
367,865
114,754

88.57
38.14
4.40
46.67

74.89
37.12
4.37
42.39

7.28
0.86
0.08
0.85
9.07

1.35
1.33
2.68
13.56

$
$
$
$

$
$
$
$
$

$
$
$
$

____________________
(a)

The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its
hedging activities at a field level.

PIONEER NATURAL RESOURCES COMPANY

Productive wells. Productive wells consist of producing wells and wells capable of production, including shut-in wells
and gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.
One or more completions in the same well bore are counted as one well. Any well in which one of the multiple completions is
an oil completion is classified as an oil well. As of December 31, 2012, the Company owned interests in two gross wells
containing multiple completions.

The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of

December 31, 2012, 2011 and 2010:

PRODUCTIVE WELLS

December 31, 2012 ....................................
December 31, 2011 ....................................
December 31, 2010 ....................................

Gross Productive Wells
Gas
5,306
5,004
4,842

Oil
6,703
6,111
5,566

Total
12,009
11,115
10,408

Net Productive Wells
Gas
4,755
4,505
4,350

Oil
5,960
5,525
4,779

Total
10,715
10,030
9,129

Leasehold acreage. The following table sets forth information about the Company's developed, undeveloped and royalty

leasehold acreage as of December 31, 2012:

LEASEHOLD ACREAGE

Onshore.........................................................
Offshore ........................................................

Developed Acreage

Undeveloped Acreage

Gross Acres
1,690,423
—
1,690,423

Net Acres
1,437,950
—
1,437,950

Gross Acres
1,492,469
—
1,492,469

Net Acres

997,269
—
997,269

Royalty Acreage
307,301
5,000
312,301

The following table sets forth the expiration dates of the leases on the Company's gross and net undeveloped acres as of

December 31, 2012:

2013 ..........................................................................................................................................
2014 ..........................................................................................................................................
2015 ..........................................................................................................................................
2016 ..........................................................................................................................................
2017 ..........................................................................................................................................
Thereafter .................................................................................................................................
Total .................................................................................................................................

_____________________
(a) Acres expiring are based on contractual lease maturities.

Acres Expiring (a)

Gross
153,898
195,783
181,666
780,814
147,048
33,260
1,492,469

Net
103,907
137,503
129,027
494,264
102,838
29,730
997,269

PIONEER NATURAL RESOURCES COMPANY

Drilling and other exploratory and development activities. The following table sets forth the number of gross and net
wells drilled by the Company during 2012, 2011 and 2010 that were productive or dry holes. This information should not be
considered indicative of future performance, nor should it be assumed that there was any correlation between the number of
productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells
compared to the costs of dry holes.

DRILLING ACTIVITIES

Gross Wells
Year Ended December 31,

Net Wells
Year Ended December 31,

2012

2011

2010

2012

2011

2010

Productive wells:

Development .................................................
Exploratory ...................................................

659
223

725
167

436
39

595
144

661
115

380
24

Dry holes:

Development .................................................
Exploratory ...................................................
Total .................................................................
Success ratio (a) ...............................................
______________________
(a) Represents the ratio of those wells that were successfully completed as producing wells or wells capable of producing to

10
6
898
98 %

3
3
481
99 %

10
1
787
99%

6
6
751
98%

11
1
904
99 %

3
1
408
99 %

total wells drilled and evaluated.

Present activities. The following table sets forth information about the Company's wells that were in process of being

drilled as of December 31, 2012:

Development .....................................................................................................................................
Exploratory ........................................................................................................................................
Total ..................................................................................................................................................

Gross Wells
140
60
200

Net Wells

130
42
172

ITEM 3.

LEGAL PROCEEDINGS

The Company is party to various proceedings and claims incidental to its business. While many of these matters involve
inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such
proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or
on its liquidity, capital resources or future annual results of operations. See Note J of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding legal
proceedings involving the Company.

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, as amended by the Mine Improvement and New Emergency Response Act of
2006. 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
Annual Report filed on Form 10-K.

PIONEER NATURAL RESOURCES COMPANY

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND

ISSUER PURCHASES OF EQUITY SECURITIES

The Company's common stock is listed and traded on the NYSE under the symbol "PXD." The Company's board of
directors (the "Board") declared dividends to the holders of the Company's common stock of $.04 per share during each of the
first and third quarters of the years ended December 31, 2012 and 2011. The Board intends to consider the payment of
dividends to the holders of the Company's common stock in the future. The declaration and payment of future dividends,
however, will be at the discretion of the Board and will depend on, among other things, the Company's earnings, financial
condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of
dividends and other considerations that the Board deems relevant.

The following table sets forth quarterly high and low prices of the Company's common stock and dividends declared per

share for the years ended December 31, 2012 and 2011:

Year ended December 31, 2012

Fourth quarter...................................................................................................... $
Third quarter ....................................................................................................... $
Second quarter .................................................................................................... $
First quarter ......................................................................................................... $

Year ended December 31, 2011

High

Low

Dividends
Declared
Per Share

110.67
115.69
117.05
119.19

97.10
99.64
106.07
104.29

$
$
$
$

99.75
82.18
77.41
90.26

58.63
65.73
82.41
85.90

$
$
$
$

—
0.04
—
0.04

On February 8, 2013, the last reported sales price of the Company's common stock, as reported in the NYSE composite

transactions, was $128.97 per share.

As of February 8, 2013, the Company's common stock was held by 14,429 holders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of its common stock during the three months ended December

31, 2012:

Total Number of
Shares (or Units)
Purchased (a)

Average Price
Paid per Share
(or Unit)

Period
October 2012 ....................................................
November 2012 ................................................
December 2012 ................................................
Total .................................................................
______________________
(a) Consists of shares withheld to satisfy tax withholding on employees' share-based awards.

532
—
64,373
64,905

104.40
—
102.41
102.43

$
$
$
$

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

—
—
—
—

—

PIONEER NATURAL RESOURCES COMPANY

ITEM 6.

SELECTED FINANCIAL DATA

The following selected consolidated financial data of the Company as of and for each of the five years ended December
31, 2012 should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Item 8. Financial Statements and Supplementary Data."

Statements of Operations Data:

2012

Year Ended December 31,
2011
2009
2010
(in millions, except per share data)

2008

Oil and gas revenues (a)...................................................... $ 2,811.7
Total revenues (b) ............................................................... $ 3,228.3
Total costs and expenses (c) ............................................... $ 2,948.3
187.7
Income (loss) from continuing operations .......................... $
55.1
192.3

Income from discontinued operations, net of tax (d) .......... $

Net income (loss) attributable to common stockholders ........ $

$ 2,294.1
$ 2,751.5
$ 2,095.1
458.8
$
423.2
834.5

$ 1,718.3
$ 2,381.7
$ 1,600.1
511.9
$
134.1
605.2

$ 1,402.4
$ 1,290.4
$ 1,515.6
$

(142.0) $
99.7
(52.1) $

$ 1,893.4
$ 1,920.1
$ 1,675.3
144.8
86.8
210.0

Income (loss) from continuing operations attributable to
common stockholders per share:

Basic ................................................................................. $

Diluted .............................................................................. $

1.10
1.07

3.45
3.39

4.00
3.96

(1.33) $

1.02
1.02

Net income (loss) attributable to common stockholders
per share:

Basic ................................................................................. $

Diluted .............................................................................. $

Dividends declared per share .............................................. $

1.54
1.50
0.08

7.01
6.88
0.08

5.14
5.08
0.08

(0.46) $

(0.46) $
0.08

1.76
1.76
0.30

Balance Sheet Data (as of December 31):

Total assets ......................................................................... $ 13,069.0
Long-term obligations ........................................................ $ 6,166.9
Total stockholders' equity ................................................... $ 5,867.3

$ 11,447.2
$ 4,726.5
$ 5,651.1

$ 9,679.1
$ 4,683.9
$ 4,226.0

$ 8,867.3
$ 4,653.0
$ 3,643.0

$ 9,161.8
$ 4,787.2
$ 3,679.6

______________________
(a)

(b)

The Company's oil and gas revenues for 2012, as compared to those of 2011, increased by $517.6 million (or 23 percent)
due to increases in oil, NGL, and gas sales volumes. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" for discussions about oil and gas revenues and factors impacting the comparability
of such revenues.
The Company recognized $330.3 million of net derivative gains in its total revenues for 2012, including $65.4 million of
noncash MTM losses, as compared to $392.8 million of net derivative gains during 2011, including $225.5 million of
noncash MTM gains. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Notes B and E of
Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
information about the Company's derivative contracts and associated accounting methods. The Company also recognized
$138.9 million of net hurricane activity gains during 2010, primarily associated with East Cameron 322 insurance
recoveries, and $17.3 million of net hurricane activity charges during 2009. See Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the
East Cameron 322 reclamation and abandonment project.

(c) During 2012, the Company recorded $604.4 million of pretax noncash impairment and abandonment charges to reduce
the carrying value of its Barnett Shale field assets. During 2011, the Company recorded an impairment charge of $354.4
million related to its Edwards and Austin Chalk net assets in South Texas. See Note D of Notes to the Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary Data." During 2009 and 2008, the
Company recorded impairment charges of $21.1 million and $89.8 million, respectively, to reduce its Uinta/Piceance
field's carrying value.

(d) During December 2011, the Company committed to a plan to divest Pioneer South Africa and in August 2012, the
Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, resulting in a pretax gain of
$28.6 million. During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011
completed the sale of the Company's share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of

PIONEER NATURAL RESOURCES COMPANY

$802.5 million, excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. During 2010, the
Company received $35.3 million of interest on excess royalties paid during the period from January 1, 2003 through
December 31, 2005 on oil and gas production from its deepwater Gulf of Mexico properties, which were sold in 2006.
During 2009, the Company recorded $119.3 million of pretax income for the recovery of the excess royalties previously
mentioned and a $17.5 million pretax gain, primarily from the sale of substantially all of its Gulf of Mexico shelf
properties. The results of operations of these properties, and certain other properties sold during the periods presented
are classified as discontinued operations in accordance with GAAP. See Note C of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the
Company's discontinued operations.

PIONEER NATURAL RESOURCES COMPANY

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF

OPERATIONS

Financial and Operating Performance

Pioneer's financial and operating performance for 2012 included the following highlights:
•

Earnings attributable to common stockholders was $192.3 million ($1.50 per diluted share) for the year ended December
31, 2012, as compared to $834.5 million ($6.88 per diluted share) in 2011. The decrease in earnings attributable to
common stockholders is primarily due to:

•

•
•

•

a $368.0 million decrease in income from discontinued operations, net of associated income taxes, primarily
attributable to a $645.2 million pretax gain on the sale of Pioneer Tunisia during February 2011;
a $231.9 million increase in DD&A, primarily due to a 29 percent increase in sales volumes;
a $188.5 million increase in oil and gas production costs, primarily due to increases in lease operating expenses as
a result of higher sales volumes and inflation of oilfield service costs;
a $178.2 million increase in impairment provisions related to a $532.6 million impairment in the Barnett Shale
field associated with reductions in management's commodity price outlook (see Note D of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Results of
Operations" below) compared to a $354.4 million impairment related to Edwards and Austin Chalk net assets in
South Texas in 2011;
an $85.0 million increase in exploration and abandonments expense, primarily due to impairment of unproved gas
prospects in the Barnett Shale field;
a $62.5 million decrease in net derivative gains, primarily due to reduced interest rate derivative gains during
2012; and
a $55.1 million increase in general and administrative expenses due to increases in compensation expense related
to a 16 percent increase in office employees supporting the Company's capital expansion initiatives, partially
offset by
a $517.6 million increase in oil and gas revenues as a result of increased sales volumes, partially offset by lower
average sales prices; and
a $105.3 million decrease in income tax provision.

Daily sales volumes from continuing operations increased on a BOE basis by 29 percent to 155,522 BOEPD during
2012, as compared to 120,418 BOEPD during 2011, primarily due to the success of the Company's drilling programs;
Average reported oil, NGL and gas prices from continuing operations decreased during 2012 to $90.89 per BBL, $33.75
per BBL and $2.60 per MCF, respectively, as compared to respective average reported prices of $96.60 per BBL, $46.27
per BBL and $3.84 per MCF during 2011;
Average oil and gas production costs per BOE from continuing operations increased during 2012 to $11.16 as compared
to per BOE costs of $10.17 during 2011, primarily due to increases in lease operating expenses, third party
transportation charges and net natural gas plant charges. The increase in lease operating expenses is primarily due to an
increase in salt water disposal costs (principally comprised of water hauling fees) during 2012. The increase in third-
party transportation costs is primarily due to gathering, treating and transportation costs associated with increasing sales
volumes in the Eagle Ford Shale field. Net natural gas plant charges increased primarily as a result of lower gas and
NGL prices being realized on third-party volumes that are retained as processing fees in Company-owned facilities. See
"Results of Operations" below for more information about changes in production costs;
Net cash provided by operating activities increased by $307.9 million, or 20 percent, to $1.8 billion for 2012, as
compared to $1.5 billion during 2011, primarily due to the increases in oil and gas sales volumes and realized derivative
gains;
During April 2012, the Company acquired 100 percent of the share capital of Industrial Sands Holding Company and its
wholly-owned subsidiary, Premier Silica. Premier Silica's core business is the operation of mines and processing
facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the
fracture stimulation of oil and gas wells in the United States. The aggregate purchase price of Premier Silica was
$297.1 million and was funded from available cash and borrowings under the Company's credit facility;
During May 2012, the Company was rated investment grade by a second credit rating agency after having been similarly
rated investment grade by another credit rating agency during 2011;
During the December 2012, the Company entered into the First Amendment to Second Amended and Restated 5-Year
Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that increased the Company's
borrowing capacity under the Credit Facility to $1.5 billion and extended its maturity to December 2017;

•

PIONEER NATURAL RESOURCES COMPANY

•

Long-term debt increased by $1.2 billion and the Company's cash and cash equivalents decreased by $308.1 million
during 2012; and
As of December 31, 2012, the Company's net debt to book capitalization was 37 percent, as compared to 26 percent as of
December 31, 2011.

During the first quarter of 2013, the following significant events occurred:

•

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 $1.7 billion. At closing, Sinochem will pay $522.0 million in cash to
Pioneer, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's
portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is
expected to close during the second quarter of 2013, subject to governmental and third party approvals.
In January and February 2013, holders of $240.6 million principal amount of the Company's 2.875% Convertible Senior
Notes due 2038 (the "Convertible Senior Notes") exercised their right to convert their Convertible Senior Notes into cash
and shares of the Company's common stock. In general, upon conversion of a Convertible Senior Note, the holder will
receive cash equal to the principal amount of the Convertible Senior Note and shares of the Company's common stock
for the Convertible Senior Note's conversion value in excess of the principal amount. See Note G of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional
information about the Convertible Senior Notes.

First Quarter 2013 Outlook

Based on current estimates, the Company expects that first quarter 2013 production will average 165,000 to 170,000

BOEPD.

First quarter 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 prices for oil and gas. DD&A expense is expected to
average $13.50 to $15.50 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and
administrative expense is expected to be $60 million to $65 million. Interest expense is expected to be $53 million to $58
million, and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is
expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries' net income, excluding noncash derivative MTM adjustments, is

expected to be $8 million to $11 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company's first quarter effective income tax rate is expected to range from 35 percent to 40 percent, assuming
current capital spending plans and no significant derivative MTM changes in the Company's derivative position. Cash income
taxes are expected to be $2 million to $7 million and are primarily attributable to state taxes.

2013 Capital Budget

Pioneer's capital program for 2013 totals $3.0 billion, consisting of $2.75 billion for drilling operations, including
budgeted land capital for existing assets, and $240 million for other property, plant and equipment. The 2013 budget excludes
acquisitions, asset retirement obligations, capitalized interest and geological and geophysical general and administrative
expense and assumes the aforementioned sale of a 40 percent interest in 207,000 net acres leased by the Company in the
horizontal Wolfcamp Shale play in the southern portion of the Spraberry field will close on or about June 1, 2013.

The 2013 drilling capital of $2.75 billion continues to be focused on oil- and liquids-rich drilling, with 81 percent of the
capital allocated to the Spraberry field, including the horizontal Wolfcamp Shale play, and the Eagle Ford Shale play.
Following is a breakdown of the forecasted spending by asset area:
•

Spraberry field - $1.65 billion, including (i) $425 million for drilling and facilities capital in the southern Wolfcamp joint
interest area, (ii) $400 million of horizontal appraisal drilling capital associated with the Company's planned two-year $1
billion appraisal program for its northern Wolfcamp/Spraberry acreage, (iii) $625 million for vertical drilling and (iv)
$200 million of infrastructure additions and automation projects;
Eagle Ford Shale – $575 million;
Barnett Shale Combo play – $185 million;

•
•

PIONEER NATURAL RESOURCES COMPANY

•
•

•
•
•

Alaska – $190 million; and
Other spending – $150 million, including land capital for existing assets.

Pioneer's budgeted expenditures for other property, plant and equipment in 2013 include:

Buildings and other facilities – $145 million;
Brady sand mine expansion – $70 million; and
Vertical integration capital – $25 million.

The 2013 capital budget is expected to be funded from a combination of cash and cash equivalents, operating cash flow,
borrowings under the Credit Facility, proceeds from the sale of joint interests or nonstrategic assets, and issuances of debt or
equity securities.

Acquisitions

During 2012, 2011 and 2010, the Company spent $157.5 million, $131.9 million and $181.6 million, respectively, to
acquire primarily undeveloped acreage for future exploitation and exploration activities. The 2012 acquisitions primarily
increased the Company's acreage positions in the West Texas Spraberry field. The 2011 and 2010 acquisitions primarily
increased the Company's acreage positions in the South Texas Eagle Ford Shale play, Barnett Shale play and West Texas
Spraberry field. Additionally, in 2012 the Company acquired Premier Silica for $297.1 million. See Note C of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional
information about the Company's acquisitions.

Divestitures and Discontinued Operations

Barnett Shale. During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the
Barnett Shale field in North Texas. In connection therewith, the Company classified its (i) Barnett Shale assets and liabilities
as discontinued operations held for sale in the Company's consolidated balance sheet as of September 30, 2012, and (ii) Barnett
Shale results of operations as income or loss from discontinued operations, net of tax, in the consolidated statements of
operations for the three and nine months ended September 30, 2012 and 2011.

The Company retained a capital markets advisor during the third quarter of 2012 and actively solicited offers from
interested purchasers of the Barnett Shale field assets. Those efforts were unsuccessful in attracting binding offers under
acceptable terms to the Company. Since the Company was unable to dispose of its Barnett Shale field assets under acceptable
terms, in December 2012, the Company decided to retain the assets; therefore, the Barnett Shale assets and liabilities no longer
qualified as held for sale or discontinued operations. Accordingly, all amounts related to the Barnett Shale that were previously
reported as (i) discontinued operations held for sale were reclassified to continuing operations at December 31, 2012, (ii)
results from the Barnett Shale operations were recorded to continuing operations for the quarter ended December 31, 2012 and
results included in discontinued operations were reclassified to income from continuing operations for the nine months ended
September 30, 2012, and (iii) amounts in periods prior to 2012 that were reflected in discontinued operations were reclassified
to continuing operations. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional information about the Company's discontinued operations.

Pioneer South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a
process to divest Pioneer South Africa. The assets and liabilities of Pioneer South Africa are classified as discontinued
operations held for sale in the Company's accompanying consolidated balance sheet as of December 31, 2011. During the first
quarter of 2012, the Company agreed to sell Pioneer South Africa to an unaffiliated third party, 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 of
the Company's South Africa subsidiaries. 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 pretax gain of $28.6 million. Pioneer South Africa's historical results
of operations, and the related gain recorded on the disposition of Pioneer South Africa, are reported as discontinued operations,
net of tax in the Company's accompanying consolidated statements of operations.

Pioneer Tunisia. During December 2010, the Company committed to a plan to sell Pioneer Tunisia. In February 2011
the Company sold its share holdings in Pioneer Tunisia for cash proceeds of $802.5 million, excluding cash and cash
equivalents sold, resulting in a pretax gain of $645.2 million. Pioneer Tunisia's historical results of operations, and the related
gain recorded on the disposition of Pioneer Tunisia, are reported as discontinued operations, net of tax in the Company's
accompanying consolidated statements of operations.

PIONEER NATURAL RESOURCES COMPANY

Eagle Ford Shale. In June 2010, the Company entered into an Eagle Ford Shale joint venture. Associated therewith, the
Company sold 45 percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for
$212.0 million of cash proceeds. Under the terms of the transaction, the purchaser also paid 75 percent (representing $886.8
million) of the Company's defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during
the period from June 2010 through December 2012.

Uinta/Piceance. During the first half of 2010, the Company sold certain proved and unproved oil and gas properties in
the Uinta/Piceance area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement
obligations, resulting in a pretax gain of $17.3 million.

Results of Operations

Oil and gas revenues. Oil and gas revenues from continuing operations totaled $2.8 billion, $2.3 billion and $1.7 billion

during 2012, 2011 and 2010, respectively.

The increase in 2012 oil and gas revenues relative to 2011 is reflective of 54 percent, 33 percent and 10 percent increases
in oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases were declines of
six percent, 27 percent and 32 percent in average reported oil, NGL and gas prices, respectively.

The increase in 2011 oil and gas revenues relative to 2010 is reflective of seven percent and 21 percent increases in
average reported oil and NGL prices, respectively and 44 percent, 14 percent and three percent increases in oil, NGL, and gas
sales volumes, respectively. These increases were partially offset by an eight percent decrease in average reported gas prices.

The following table provides average daily sales volumes from continuing operations for 2012, 2011 and 2010:

Oil (BBLs) .......................................................................................................................
NGLs (BBLs) ..................................................................................................................
Gas (MCF) ......................................................................................................................
Total (BOE) .....................................................................................................................

Year Ended December 31,
2011
40,618
22,487
343,879
120,418

2012
62,645
29,816
378,369
155,522

2010
28,211
19,736
335,256
103,823

Average daily BOE sales volumes in 2012 and 2011 increased by 29 percent and 16 percent, respectively, as compared
to the daily sales volumes in the respective prior years, principally due to the Company's successful drilling programs and
declines in scheduled VPP deliveries. Oil volumes delivered under the Company's VPPs decreased by six percent and 45
percent, respectively, during 2012 and 2011. All VPP production volumes have been delivered as of December 31, 2012 and
there are no further obligations under the VPP contracts.

Production growth for 2012, as compared to 2011, 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. The gas processing capacity limitations resulted in reduced recoveries of ethane, negatively impacting average
2012 sales volumes by approximately 1,450 BOEPD. New Spraberry field gas processing facilities are being built and are
expected to be on production in April of 2013.

PIONEER NATURAL RESOURCES COMPANY

The following table provides average daily sales volumes from discontinued operations by geographic area and in total

during 2012, 2011 and 2010:

Oil (BBLs):

South Africa .................................................................................................................
Tunisia .........................................................................................................................
Worldwide ...................................................................................................................

Gas (MCF):

Total (BOE):

Year Ended December 31,
2011

2012

2010

428
—
428

10,340
—
10,340

2,151
—
2,151

530
547
1,077

20,570
496
21,066

3,958
630
4,588

616
4,880
5,496

29,760
2,849
32,609

5,576
5,355
10,931

In South Africa, sales volumes in 2012 declined by 46 percent from 2011 primarily due to the sale of Pioneer South

Africa during August 2012 compared to a full year of production in 2011.

The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities
adjusted for transfers of the Company's deferred hedge gains and losses from the effective portions of the discontinued deferred
hedges included in accumulated other comprehensive income (loss) – net deferred hedge gains (losses), net of tax ("AOCI –
Hedging") and the amortization of deferred VPP revenue. See "Derivative activities" and "Deferred revenue" discussion below
for additional information regarding the Company's cash flow hedging activities and the amortization of deferred VPP revenue.

The following table provides average reported prices from continuing operations (including deferred hedge gains and
losses and the amortization of deferred VPP revenue) and average realized prices from continuing operations (excluding
deferred hedge gains and losses and the amortization of deferred VPP revenue) for 2012, 2011 and 2010:

Year Ended December 31,
2011

2012

2010

Average reported prices:
Oil (per BBL) .................................................................................................................. $
NGL (per BBL) ............................................................................................................... $
Gas (per MCF) ................................................................................................................ $
Total (per BOE) ............................................................................................................... $
Average realized prices:
Oil (per BBL) .................................................................................................................. $
NGL (per BBL) ............................................................................................................... $
Gas (per MCF) ................................................................................................................ $
Total (per BOE) ............................................................................................................... $

90.89
33.75
2.60
49.40

89.19
33.75
2.60
48.71

$
$
$
$

96.60
46.27
3.84
52.19

91.35
46.27
3.84
50.42

$
$
$
$

90.56
38.14
4.18
45.34

74.21
37.12
4.15
40.61

Derivative activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short
puts in order to (i) reduce the effect of price volatility on the commodities the Company produces, 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. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing
derivative contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge
accounting were recorded as a component of AOCI – Hedging in the equity section of the Company's consolidated balance
sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the
Company's earnings. Since February 1, 2009, the Company has recognized all changes in the fair values of its derivative
contracts as gains or losses in the earnings of the periods in which they occur.

PIONEER NATURAL RESOURCES COMPANY

The following table summarizes the transfers of deferred hedge gains and losses associated with oil, NGL and gas cash
flow hedges from AOCI – Hedging to oil, NGL and gas revenues for the years ending December 31, 2012, 2011 and 2010 (in
thousands):

Increase (decrease) to oil revenue from AOCI - Hedging transfers ................................ $
Increase to NGL revenue from AOCI - Hedging transfers ..............................................
Increase to gas revenue from AOCI - Hedging transfers.................................................
Total ................................................................................................................................ $

Year Ended December 31,
2011

2012
(3,156) $ 32,918
—
—
(3,156) $ 32,918

—
—

2010
$ 78,052
7,297
3,691
$ 89,040

Deferred revenue. During 2012, 2011 and 2010, the Company's amortization of deferred VPP revenue increased annual
oil revenues by $42.1 million, $45.0 million and $90.2 million, respectively. All VPP production volumes have been delivered
and there are no further obligations under VPP contracts or deferred revenue as of December 31, 2012. See the revenue
recognition section of Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for specific information regarding the Company's deferred revenue.

Interest and other income. The Company's interest and other income from continuing operations totaled $28.3 million,
$66.9 million and $57.0 million during 2012, 2011 and 2010, respectively. The $38.6 million decrease during 2012, as
compared to 2011, is primarily attributable to a $27.9 million decrease in third-party income from vertical integration services,
primarily due to increases in costs of services and idle equipment during the fourth quarter of 2012 and a $9.6 million decrease
in Alaskan Petroleum Production Tax ("PPT") credit recoveries. The $9.9 million increase during 2011, as compared to 2010,
is primarily attributable to a $15.8 million increase in third-party income associated with vertical integration services and a $2.7
million increase in equity earnings from EFS Midstream, partially offset by an $8.7 million decrease in PPT credit recoveries.

Derivative gains (losses), net. The following table summarizes the Company's net derivative gains or losses for the years

ending December 31, 2012, 2011 and 2010 (in thousands):

Unrealized changes in fair value:

Year Ended December 31,
2011

2012

2010

Oil derivative gains ...................................................................................................... $ 217,765
1,209
NGL derivative gains ...................................................................................................
Gas derivative gains (losses) ........................................................................................
Diesel derivative gains (losses) ....................................................................................
Marketing derivative losses .........................................................................................
Interest rate derivative gains (losses) ...........................................................................
Total unrealized derivative gains (losses), net (a) .....................................................

$ 68,376
10,243
(290,058) 179,787
270
—

(270)
(22)

(65,446) 225,470

5,930

(33,206)

$ 41,094
10,690
277,585
—
—
35,040
364,409

Cash settled changes in fair value:

Oil derivative gains (losses) .........................................................................................
NGL derivative gains (losses) ......................................................................................
Gas derivative gains .....................................................................................................
Diesel derivative gains .................................................................................................
Marketing derivative gains (losses) .............................................................................
Interest rate derivative gains (losses) ...........................................................................
Total cash derivative gains, net .................................................................................

(28,359)
395,697
Total derivative gains, net ....................................................................................... $ 330,251

4,139
13,403
402,981
3,497
36

(36,664)
(15,418)

183,010
67
(17)

36,304
167,282
$ 392,752

(27,305 )
(7,180 )
119,417
—
—
(907 )
84,025
$ 448,434

__________________
(a) Unrealized changes in fair value are subject to continuing market risk.

Gain (loss) on disposition of assets. The Company recorded net gains of $58.1 million and $19.1 million during 2012

and 2010, respectively, and a net loss on the disposition of assets of $3.6 million during 2011.

PIONEER NATURAL RESOURCES COMPANY

During 2012, the Company recorded a $12.6 million pretax gain on the sale of its interest in the Cosmopolitan Unit in
the Cook Inlet of Alaska and a $42.6 million pretax gain on the sale of a portion of its interest in an unproved oil and gas
property in the Eagle Ford Shale field. During 2011, the net loss was primarily associated with losses on the sales of excess
materials and supplies inventory, partially offset by gains on the sale of certain unproved properties. During 2010, the
Company recorded a $17.3 million net gain associated with the sale of proved and unproved oil and gas properties in the
Uinta/Piceance area and a $6.0 million net gain associated with the Eagle Ford Shale joint venture transaction, partially offset
by net losses primarily associated with the sale of excess lease and well equipment inventory.

Hurricane activity, net. The Company recorded net hurricane activity gains of $1.5 million and $138.9 million during
2011 and 2010. The Company did not record any hurricane activity in 2012. As a result of Hurricane Rita in September 2005,
the Company's East Cameron 322 facility, located on the Gulf of Mexico shelf, was completely destroyed. Operations to
reclaim and abandon the East Cameron 322 facility began in 2006 and were completed during 2011. In 2007, the Company
commenced legal actions against its insurance carriers regarding policy coverage issues for the cost of reclamation and
abandonment of the East Cameron 322 facility. During the fourth quarter of 2010, the Company and the insurance carriers
agreed to settle an insurance policy dispute, resulting in an additional payment to the Company of $140.1 million during
November 2010. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's East Cameron platform facilities reclamation and
abandonment activities.

Oil and gas production costs. The Company's oil and gas production costs from continuing operations totaled $635.6
million, $447.1 million and $364.8 million during 2012, 2011 and 2010, respectively. In general, lease operating expenses and
workover expenses represent the components of oil and gas production costs over which the Company has management
control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural
gas plant/gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned
from gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the year ended December 31, 2012 increased by 10 percent as compared
to 2011. The increase in production costs per BOE during 2012 is primarily reflective of increases in lease operating expenses,
third-party transportation charges and net natural gas plant/gathering charges. Lease operating costs increased during 2012
primarily due to a $0.51 per BOE increase in salt water disposal costs (principally comprised of water hauling fees). The $0.19
per BOE increase in third-party transportation charges during 2012 is primarily due to gathering, treating and transportation
costs associated with increasing sales volumes from the Company's successful drilling program in the Eagle Ford Shale field.
Net natural gas plant charges increased by $0.32 per BOE during 2012, primarily due to a reduction in third-party revenues
from processing third-party gas volumes in Company-owned facilities as a result of lower gas and NGL prices being realized
on the volumes retained as a processing fee.

During 2011, total production costs per BOE increased by six percent as compared to 2010. The increase in production
costs per BOE is primarily due to (i) increased third-party transportation and processing charges associated with increasing
Eagle Ford Shale production, (ii) repairs associated with severe winter weather disruptions encountered during the first quarter
of 2011 and (iii) inflation in well servicing costs, partially offset by reductions in VPP delivery commitments and decreased
workover costs.

The following table provides the components of the Company's total production costs per BOE for 2012, 2011 and 2010:

Year Ended December 31,
2011

2012

2010

Lease operating expenses ................................................................................................ $
Third-party transportation charges ..................................................................................
Net natural gas plant/gathering charges...........................................................................
Workover costs ................................................................................................................
Total production costs ..................................................................................................... $

8.53
1.31
0.47
0.85
11.16

8.08
1.12
0.15
0.82
10.17

7.74
0.87
0.08
0.92
9.61

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $187.8 million during
2012, as compared to $147.7 million and $112.1 million for 2011 and 2010, respectively. In general, production taxes and ad
valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year
commodity prices, whereas production taxes are based upon current year commodity prices. During 2012, the Company's
production taxes per BOE decreased by three percent as compared to 2011, primarily reflecting the impact of lower oil and
NGL prices on production taxes. On a per BOE basis, ad valorem taxes increased two percent as compared to 2011. During
2011, the Company's production taxes per BOE increased 44 percent over 2010, primarily reflecting the impact of higher oil

PIONEER NATURAL RESOURCES COMPANY

and NGL prices on production taxes, while ad valorem taxes decreased by 17 percent, which is primarily a result of an increase
in sales volumes from new wells first brought on production during 2011.

The following table provides the Company's production and ad valorem taxes per BOE from continuing operations and

total production and ad valorem taxes per BOE from continuing operations for 2012, 2011 and 2010:

Year Ended December 31,
2011

2012

2010

Production taxes .............................................................................................................. $
Ad valorem taxes .............................................................................................................
Total ad valorem and production taxes............................................................................ $

2.04
1.26
3.30

2.11
1.24
3.35

1.47
1.49
2.96

Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing operations
was $810.2 million ($14.23 per BOE), $578.3 million ($13.16 per BOE), and $499.9 million ($13.19 per BOE) for 2012, 2011
and 2010, respectively. Depletion expense on oil and gas properties, the largest component of DD&A expense, was $13.61,
$12.55 and $12.40 per BOE during 2012, 2011 and 2010, respectively.

During 2012, the eight percent increase in per BOE depletion expense was primarily due to (i) increased drilling
expenditures on proved undeveloped locations, primarily in the Spraberry field and (ii) declines in proved gas reserves due to
lower first-day-of-the-month gas prices during the 12-month period ending on December 31, 2012, partially offset by (iii) the
impairment effects of reducing carrying values of the Barnett Shale field and the South Texas Edwards Trend/Austin Chalk
fields during 2012 and 2011, respectively (see the discussion below for more information on the Company's impairment
charges).

During 2011, the one percent increase in per BOE depletion expense was primarily due to modest inflation in drilling
costs in the Spraberry field in West Texas and the Barnett Shale field, partially offset by the cost containment associated with
employed integrated services and increasing production in the Eagle Ford Shale play where portions of the Company's drilling
costs were carried by a third party.

Impairment of oil and gas properties and other long-lived assets. 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 commodity price outlooks represent longer-term outlooks that are developed based on observable third-
party futures price outlooks as of a measurement date ("Management's Price Outlooks"). During 2012 and 2011, declines in
Management's Price Outlooks provided indications of possible impairment of the Company's predominantly dry gas properties
in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in
southeastern Colorado. As a result of management's assessments, during 2012 and 2011, the Company recognized pretax
noncash impairment charges of $532.6 million and $354.4 million to reduce the carrying values of the Barnett Shale field and
the South Texas Edwards Trend/Austin Chalk fields, respectively, to their estimated fair values.

The Company's estimates of undiscounted future net cash flows attributable to the Raton field's oil and gas properties
indicated on December 31, 2012 that its carrying amounts are expected to be recovered, but continues to be at risk for
impairment if estimates of future cash flows decline. For example, the Company estimates that the carrying value of the Raton
field may become partially impaired if the average gas price in Management's Price Outlooks, of $4.92 per MCF as of
December 31, 2012, were to decline by approximately $0.60 to $0.80 per MCF. The Company's Raton field is a relatively long-
lived asset that had a carrying value of $2.2 billion as of December 31, 2012. If the Raton field were to become impaired in a
future period, the Company would recognize noncash, pretax impairment charges in that period that could range from $1.3
billion to $1.7 billion.

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

See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and

Supplementary Data" for additional information about the Company's impairment assessments.

PIONEER NATURAL RESOURCES COMPANY

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs,
exploratory dry holes expense and leasehold abandonments and other exploration expense from continuing operations for 2012,
2011 and 2010 (in thousands):

Geological and geophysical ............................................................................................. $ 80,456
30,637
Exploratory dry holes ......................................................................................................
95,198
Leasehold abandonments and other .................................................................................
$ 206,291

2012

Year Ended December 31,
2011
$ 73,552
3,112
44,656
$ 121,320

2010
$ 58,016
91,922
39,659
$ 189,597

During 2012, the Company's exploration and abandonment expense was primarily attributable to $80.5 million of
geological and geophysical costs, of which $52.4 million was geological and geophysical administrative costs; $30.6 million
were dry hole provisions, $21.6 million was associated with the Company's unsuccessful Sikumi #1 well that was drilled to test
the Ivishak zone on the west side of the Company's Oooguruk unit in Alaska; and $94.7 million was leasehold abandonment
expense, which included $72.5 million associated with the Company's unproved properties in the Barnett Shale and other
unproved property abandonments. The other significant components of the Company's 2012 leasehold abandonment expense
included $9.5 million in the Eagle Ford Shale area, $4.8 million in the Rockies area and $4.7 million in the Permian Basin.
During 2012, the Company completed and evaluated 229 exploration/extension wells, 223 of which were successfully
completed as discoveries.

During 2011, the Company's exploration and abandonment expense was primarily attributable to $73.6 million of
geological and geophysical costs, of which amount $42.5 million was geological and geophysical administrative costs, and
$44.2 million of leasehold abandonment expense. The significant components of the Company's 2011 leasehold abandonment
expense included dry gas unproved acreage abandonments of $14.5 million in the Barnett Shale area, $9.3 million in the South
Texas area and $9.1 million in the Rockies area. During 2011, the Company completed and evaluated 168
exploration/extension wells, 167 of which were successfully completed as discoveries.

During 2010, the Company's exploration and abandonment expense was primarily attributable to $58.0 million of
geological and geophysical costs, of which amount $39.9 million was geological and geophysical administrative costs, $96.7
million of dry hole and leasehold abandonment expense resulting from the Company's decision not to pursue development of
the Cosmopolitan Unit in the Cook Inlet of Alaska and other dry hole provisions and unproved property abandonments. Other
significant components of the Company's 2010 unproved abandonments included $6.3 million in the Raton Basin area, $6.0
million in the Permian Basin area and $4.9 million in the Barnett Shale area. During 2010, the Company completed and
evaluated 37 exploration/extension wells, 34 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense from continuing operations totaled $248.3
million, $193.2 million and $164.3 million during 2012, 2011 and 2010, respectively. The increase in 2012, as compared to
2011, is primarily due to increases of $46.6 million and $4.7 million in compensation and occupancy expenses, respectively,
related to staffing increases in support of the Company's capital expansion and integrated services initiatives.

The increase in general and administrative expense during 2011, as compared to 2010, was primarily due to increases of
$31.9 million and $5.7 million in compensation and occupancy expenses, respectively, related to staffing increases in support
of the Company's capital expansion and integrated services initiatives, partially offset by an increase in producing, drilling and
other overhead recoveries.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from
continuing operations was $9.9 million, $8.3 million and $7.9 million during 2012, 2011 and 2010, respectively. The 19
percent and five percent increases in accretion of discount on asset retirement obligations during 2012 and 2011, respectively,
are primarily due to additional well completions resulting from the Company's drilling activities. See Note I of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $204.2 million, $181.7 million and $183.1 million during 2012, 2011 and 2010,
respectively. The weighted average interest rate on the Company's indebtedness for the year ended December 31, 2012 was 6.0
percent, as compared to 7.2 percent and 7.1 percent for the years ended December 31, 2011 and 2010, respectively.

The $22.5 million increase in interest expense during 2012, as compared to 2011, is primarily due to an $868.9 million
increase in the Company's average outstanding indebtedness, partially offset the 1.2 percent decline in weighted average
interest on indebtedness.

PIONEER NATURAL RESOURCES COMPANY

See Notes G and Q of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and

Supplementary Data" for additional information about the Company's long-term debt and interest expense.

Other expenses. Other expenses from continuing operations were $113.4 million during 2012, as compared to $63.2
million during 2011 and $78.4 million during 2010. The $50.2 million increase in other expense during 2012, as compared to
2011, is primarily due to $15.8 million of contract rig termination fees incurred during 2012, a $13.9 million increase in unused
gas transportation commitment charges and a $13.1 million increase in the time that drilling rigs and fracture stimulation
equipment were not being utilized.

The $15.2 million decrease in other expense during 2011, as compared to 2010, is primarily due to a $30.4 million
decrease in charges recorded associated with contracted rig rates that exceeded market rig rates that were able to be charged to
joint operations and idle drilling rig and fracture stimulation equipment charges and a $7.6 million decrease in inventory
impairments; partially offset by a $21.7 million increase in charges associated with excess gas transportation capacity.

See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary

Data" for additional information regarding the Company's other expenses.

Income tax provision. The Company recognized income tax provisions attributable to earnings from continuing
operations of $92.4 million, $197.6 million and $269.6 million during 2012, 2011 and 2010, respectively. The Company's
effective tax rates on earnings from continuing operations, excluding income from noncontrolling interest, for 2012, 2011 and
2010 were 40 percent, 32 percent and 36 percent, respectively, as compared to the combined United States federal and state
statutory rates of approximately 37 percent. The increase in the Company's 2012 effective tax rate is primarily due to changes
in permanent tax differences and state apportionment factors.

See "Critical Accounting Estimates" below and Note O of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information regarding the Company's income tax rates and
attributes.

Income (loss) from discontinued operations, net of tax. During December 2011, the Company committed to a plan to
exit South Africa and initiated a process to divest Pioneer South Africa. The assets and liabilities of Pioneer South Africa are
classified as discontinued operations held for sale in the Company's accompanying consolidated balance sheet as of
December 31, 2011. During the first quarter of 2012, the Company agreed to sell its net assets in Pioneer South Africa to an
unaffiliated third party, 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 of the Company's South Africa subsidiaries. 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 pretax
gain of $28.6 million. Pioneer South Africa's historical results of operations, and the related gain recorded on the disposition
of Pioneer South Africa, are reported as discontinued operations, net of tax in the Company's accompanying consolidated
statements of operations.

During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011 sold 100 percent
of the Company's share holdings in Pioneer Tunisia for cash proceeds of $802.5 million, excluding cash and cash equivalents
sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company classified the results of operations of Pioneer
Tunisia as income from discontinued operations, net of tax in the accompanying consolidated statements of operations for the
years ended December 31, 2011 and 2010.

The Company recognized income from discontinued operations, net of tax of $55.1 million for 2012 as compared to
income of $423.2 million for 2011 and $134.1 million for 2010. The $368.0 million decrease in income from discontinued
operations during 2012, as compared to 2011 is primarily attributable to the after tax gain on the sale of Pioneer Tunisia
recorded in 2011, partially offset by the after tax gain on the sale of Pioneer South Africa during 2012.

The $289.1 million increase in income from discontinued operations during 2011, as compared to 2010 is primarily
attributable to the after tax gain on the sale of Pioneer Tunisia during 2011, partially offset by Pioneer South Africa and Pioneer
Tunisia operating income classified as discontinued operations during 2010. See Note C of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the
Company's discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interests was $50.5
million, $47.4 million and $40.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. The Company's
net income attributable to noncontrolling interest is primarily associated with the net income of Pioneer Southwest that is
allocated to limited partners. The $3.1 million increase in net income attributable to noncontrolling interest in 2012, as

PIONEER NATURAL RESOURCES COMPANY

compared to 2011, is primarily due to a 10 percent increase in noncontrolling interest in Pioneer Southwest during November
2011 as a result of an offering by Pioneer Southwest of 4.4 million common units, representing limited partnership units, of
which 1.8 million common units were sold by the Company. Partially offsetting the increase in noncontrolling interest in
Pioneer Southwest was a $15.3 million decline in Pioneer Southwest's net income during 2012, as compared to 2011.

The $6.6 million increase in net income attributable to noncontrolling interest in 2011, as compared to 2010, is primarily
due to an increase in Pioneer Southwest's sales volumes and realized oil prices. See Note B of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding Pioneer
Southwest and the Company's noncontrolling interest in consolidated subsidiaries' net income.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures
on oil and gas properties and related vertical integration assets and facilities, payments 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. During 2013, the Company expects that it will
be able to fund its needs for cash (excluding acquisitions) with a combination of internally generated cash flows, cash and cash
equivalents on hand, proceeds from the sale of joint interests, availability under its credit facility and issuances of debt or
equity securities. Although the Company expects that these sources of funding will be adequate to fund 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.

During 2013, the Company plans to continue to focus its capital spending primarily on liquids-rich drilling activities.
The Company's 2013 capital budget totals $3.0 billion (excluding effects of acquisitions, asset retirement obligations,
capitalized interest, geological and geophysical administrative costs and EFS Midstream capital contributions), consisting of
$2.75 billion for drilling operations and $240 million for buildings, expansion of the Company's principal sand mine in Brady,
Texas and vertical integration additions. Based on the Company's current Management Price Outlooks, Pioneer expects its net
cash flows from operating activities, cash and cash equivalents on hand, proceeds from assets sales and/or joint ventures,
availability under the Credit Facility and issuances of debt or equity securities to be sufficient to fund its planned capital
expenditures and contractual obligations.

Investing activities. Net cash used in investing activities during 2012 was $3.3 billion, as compared to net cash used in
investing activities of $1.6 billion and $954.9 million during 2011 and 2010, respectively. The increase in net cash flow used
in investing activities during 2012, as compared to 2011, is primarily due to (i) an $831.1 million increase in additions to oil
and gas properties associated with the Company's capital programs, (ii) a $723.5 million decrease in proceeds from disposition
of assets (primarily attributable to the 2011 sale of Pioneer Tunisia, partially offset by proceeds from the sales of Pioneer
South Africa and a partial interest in certain Eagle Ford Shale unproved leaseholds during 2012) and (iii) the $297.1 million
acquisition of Premier Silica, partially offset by (iv) an $89.6 million decrease in investments in EFS Midstream and (v) a $66.4
million decrease in additions to other assets and other property and equipment. During the year ended December 31, 2012, the
Company's investing activities were funded by net cash provided by operating activities, cash on hand and borrowings under
long-term debt.

The increase in net cash flow used in investing activities during 2011, as compared to 2010, was comprised of a $915.5
million increase in additions to oil and gas properties, an increase of $178.9 million in additions to other assets and other
property and equipment and a $16.8 million increase in investments in unconsolidated subsidiaries, partially offset by an
increase of $505.3 million in proceeds from disposition of assets (primarily related to the sale of Pioneer Tunisia during
February 2011). See "Results of Operations" above and Note C of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional information regarding asset divestitures.

Dividends/distributions. During each of the years ended December 31, 2012, 2011 and 2010, the Board declared
semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $10.0 million, $9.6 million and
$9.5 million, respectively, of aggregate dividends. Future dividends are at the discretion of the Board, and, if declared, the
Board may change the dividend amount based on the Company's liquidity and capital resources at the time.

During January, April, July and October of 2012, 2011 and 2010, the board of directors of the general partner of Pioneer
Southwest (the "Pioneer Southwest Board") declared quarterly distributions aggregating annually to $2.07, $2.03 and $2.00 per
limited partner unit, respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling
unitholders of $35.2 million, $25.6 million and $25.2 million during the years ended December 31, 2012, 2011 and 2010,
respectively. Future distributions of Pioneer Southwest are at the discretion of the Pioneer Southwest Board, and, if declared,

PIONEER NATURAL RESOURCES COMPANY

the Pioneer Southwest Board may change the distribution amount based on Pioneer Southwest's liquidity and capital resources
at the time.

Off-balance sheet arrangements. From time-to-time, the Company enters into off-balance sheet arrangements and
transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2012, the material
off-balance sheet arrangements and transactions that the Company has entered into include (i) undrawn letters of credit,
(ii) operating lease agreements, (iii) drilling and firm transportation 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 and subsequent events that are described in "Financial and Operating Performance," above and in Note Q of
Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data," the Company
has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely
to materially affect the Company's liquidity or availability of or requirements for capital resources. See "Contractual
obligations" below for more information regarding the Company's off-balance sheet arrangements.

Contractual 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,
other liabilities (including postretirement benefit obligations), firm transportation and fractionation commitments and minimum
annual gathering, treating and transportation commitments. Other joint owners in the properties operated by the Company will
incur portions of the costs represented by these commitments.

The following table summarizes by period the payments due by the Company for contractual obligations estimated as of

December 31, 2012:

Payments Due by Year

2013

2014 and 2015 2016 and 2017 Thereafter

(in thousands)

Long-term debt (a) ............................................................................. $ 479,907
24,096
Operating leases (b) ............................................................................
174,169
Drilling commitments (c) ...................................................................
13,416
Derivative obligations (d) ...................................................................
131,727
Open purchase commitments (e) ........................................................
31,056
Other liabilities (f) ..............................................................................
264,213
Firm gathering, processing and transportation commitments (g) .......
$ 1,118,584

—
32,934
131,641
12,307
—
31,580
760,341
$ 968,803

$ 1,540,485
28,455
585
—
—
30,265
725,378
$ 2,325,168

$ 1,749,500
36,967
—
—
—
189,024
1,255,520
$ 3,231,011

_____________________
(a)

Long-term debt includes $479.9 million principal amount of the Convertible Senior Notes. The Company currently
anticipates that it will redeem all Convertible Senior Notes that remain outstanding during 2013. See Notes G and Q of
Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
further information on the conversion of these Convertible Senior Notes. Also, see "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" for information regarding estimated future interest payment obligations
under long-term debt obligations. The amounts included in the table above represent principal maturities only.
See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for more information about the Company's operating leases.

(b)

commitments under contracts to which the Company was a party on December 31, 2012.

(d) Derivative obligations represent net liabilities determined in accordance with master netting arrangements for
commodity and interest rate derivatives that were valued as of December 31, 2012. The ultimate settlement amounts of
the Company's derivative obligations are unknown because they are subject to continuing market risk. See "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's
derivative obligations.

(e) Open purchase commitments primarily represent expenditure commitments for inventory, materials and other property,

plant and equipment ordered, but not received, as of December 31, 2012.

PIONEER NATURAL RESOURCES COMPANY

(f)

The Company's other liabilities represent current and noncurrent other liabilities that are comprised of postretirement
benefit obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for
which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I
and J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"
for additional information regarding the Company's postretirement benefit obligations, asset retirement obligations and
litigation and environmental contingencies, respectively.

(g) Gathering, processing and transportation commitments represent estimated fees on production throughput commitments.
See "Item 2. Properties" and Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the Company's gathering, processing and
transportation commitments.

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 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 the Credit Facility, issue debt or equity securities or obtain capital from other
sources, such as through sales of joint interests or nonstrategic assets.

Operating activities. Net cash provided by operating activities for the years ended December 31, 2012, 2011 and 2010
was $1.8 billion, $1.5 billion and $1.3 billion, respectively. The increases in net cash flow provided by operating activities in
both 2012 and 2011 were primarily due to increases in oil and gas sales and realized derivative gains in each year.

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 consideration of $1.7 billion. At closing, Sinochem will pay $522.0 million in cash
to Pioneer, before normal closing adjustments, and will pay the remaining $1.2 billion by carrying 75 percent of Pioneer's
portion of future drilling and facilities costs attributable to the horizontal Wolfcamp Shale play. This transaction is expected to
close during the second quarter of 2013, subject to governmental and third party approvals.

During the first quarter of 2012, the Company agreed to sell Pioneer South Africa to an unaffiliated third party for $60.0
million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the
Company's South Africa subsidiaries. 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 pretax gain of $28.6 million. During 2011, the Company completed the sale of
Pioneer Tunisia to an unaffiliated party for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting
in a pretax gain of $645.2 million.

In June 2010, the Company entered into an Eagle Ford Shale joint venture. Associated therewith, the Company sold 45
percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million of
cash proceeds. Under the terms of the transaction, the purchaser also paid 75 percent (representing $886.8 million) of the
Company's defined exploration, drilling and completion costs attributable to the Eagle Ford Shale assets during the period from
June 2010 through December 2012.

During the first half of 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance
area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement obligations, resulting in a
pretax gain of $17.3 million.

See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary

Data" for more information regarding the Company's divestitures.

Financing activities. Net cash provided by financing activities during 2012 was $1.1 billion, as compared to net cash
provided by financing activities during 2011 of $457.4 million and net cash used in 2010 of $246.4 million. During 2012, the
significant components of financing activities included $1.2 billion of net borrowings on long-term debt and $45.9 million of
payments associated with dividends and distributions to noncontrolling interests. During 2011, significant components of
financing activities included $484.2 million of net proceeds received from the offering of 5.5 million shares of the Company's
common stock, $123.0 million of net proceeds received from the sale of 4.4 million common units representing limited partner
interests in Pioneer Southwest, partially offset by $98.3 million of net principal payments on long-term debt and $36.3 million
of payments associated with dividends and distributions to noncontrolling interests. During 2010, significant components of
financing activities included $182.9 million of net principal payments on long-term debt and $36.3 million of payments
associated with dividends and distributions to noncontrolling interests.

PIONEER NATURAL RESOURCES COMPANY

The following provides a description of the Company's significant financing activities during 2012, 2011 and 2010:
• During December 2012, the Company amended its Credit Facility with a syndicate of financial institutions to increase

the aggregate loan commitments to $1.5 billion from $1.25 billion and extend its maturity to December 2017;

• During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5

million of offering discounts and costs, of $591.5 million;

• During December 2011, Pioneer Southwest completed the public offering of 4.4 million common units of Pioneer
Southwest, representing limited partnership interests, at a per-unit price of $29.20, before offering costs. Of the
4.4 million common units, Pioneer sold 1.8 million of its Pioneer Southwest common unit holdings for net proceeds of
$50.5 million and Pioneer Southwest issued 2.6 million new common units for net proceeds of $72.5 million, including
offering costs. Pioneer Southwest used its net proceeds to reduce its credit facility borrowings; and

• During November 2011, the Company completed the sale of 5.5 million shares of its common stock for $484.2 million

of net proceeds.

During December 2012, the Company's stock price performance met the average price threshold that causes the
Convertible Senior Notes to become convertible at the option of the holders for the three months ending March 31, 2013.
Associated therewith, in January and February 2013, holders of $240.6 million principal amount of the Convertible Senior
Notes exercised their right to convert their Convertible Senior Notes into cash and shares of common stock. In general, upon
conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior
Note and common stock for the Convertible Senior Note's conversion value in excess of the principal amount. The Company
anticipates redeeming all Notes that remain outstanding during 2013; however, the decision to exercise the redemption option
will depend on market and other conditions, and the Company may choose not to redeem the Notes during 2013 or at all. If the
Company exercises its redemption option, the Convertible Senior Notes will automatically become convertible during the
period between when the Company gives notice of its intent to redeem the Convertible Senior Notes and the date on which the
Convertible Senior Notes are actually redeemed. If the Company exercises its redemption option and the Company's stock
price averages above $72.60 per share during the conversion period, the Company expects that the note holders will exercise
their right to convert the Convertible Senior Notes, receiving cash and shares of common stock, rather than allow their
securities to be redeemed by the Company for cash. If all the outstanding Convertible Senior Notes had been converted on
December 31, 2012, the holders would have received $479.9 million of cash and approximately 3.4 million shares of the
Company's common stock, which were valued at $358.8 million based on the closing price of the common stock on December
31, 2012.

Interest on the principal amount of the Convertible Senior Notes is payable semiannually in arrears on January 15 and
July 15 of each year. Beginning on January 15, 2013, during any six-month period thereafter from January 15 to July 14 and
from July 15 to January 14, if the average trading price (as defined in the Convertible Senior Notes indenture supplement) of a
Convertible Senior Note for the five consecutive trading days immediately preceding the first day of the applicable six-month
interest period equals or exceeds 120 percent of the principal amount of the note, interest on the principal amount of the
Convertible Senior Notes will be 2.375 percent solely for the relevant interest period. The trading price of the Convertible
Senior Notes for the five consecutive trading days preceding January 15, 2013 exceeded 120 percent of the principal amount of
the note and, accordingly, the interest rate in effect during the January 15, 2013 to July 15, 2013 period has been reduced to
2.375 percent.

See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary

Data" for additional information regarding the significant financing activities.

As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt,
convertible securities, preferred stock or common stock. The Company cannot predict the timing or ultimate outcome of any
such actions as they are subject to market conditions, among other factors. 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 and cash equivalents and unused borrowing
capacity under the Credit Facility. As of December 31, 2012, the Company had outstanding borrowings of $474.0 million
under the Credit Facility, leaving $1.0 billion of unused borrowing capacity. The Company was in compliance with all of its
debt covenants. The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt
to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments
not to exceed .60 to 1.0, which is above the Company's December 31, 2012 ratio of .39 to 1.0. 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 the Credit Facility, issuances of debt or
equity securities or other sources, such as sales of joint interests or nonstrategic assets. The Company cannot provide any

PIONEER NATURAL RESOURCES COMPANY

assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company
expects that the combination of internal operating cash flows, cash and cash equivalents on hand, proceeds from the sales of
joint interests or nonstrategic assets, available capacity under the Credit Facility and issuance of debt or equity securities 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 and asset composition and proved reserve mix. A
reduction in the Company's debt ratings could negatively affect the Company's ability to obtain additional financing or the
interest rate, fees and other terms associated with such additional financing. In 2011, the Company achieved an investment
grade rating with one of the credit rating agencies and, in 2012, the Company achieved an investment grade rating with a
second credit rating agency.

Book capitalization and current ratio. The Company's net book capitalization at December 31, 2012 was $9.4 billion,
consisting of $229.4 million of cash and cash equivalents, debt of $3.7 billion and stockholders' equity of $5.9 billion. The
Company's debt to book capitalization increased to 37 percent at December 31, 2012 from 26 percent at December 31, 2011,
primarily due to an increase in indebtedness during 2012. The Company's ratio of current assets to current liabilities was 1.02
to 1.00 at December 31, 2012, as compared to 1.31 to 1.00 at December 31, 2011.

Critical Accounting Estimates

The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See
Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a
comprehensive discussion of the Company's significant accounting policies. GAAP represents a comprehensive set of
accounting and disclosure rules and requirements, the application of which requires management judgments and estimates
including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of the
Company's most critical accounting estimates, judgments and uncertainties that are inherent in the Company's application of
GAAP.

Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and
to restore the land at the end of oil and gas production operations. The Company's removal and restoration obligations are
primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and
requires management to make estimates and judgments because most of the removal obligations are many years in the future
and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs
are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement
amounts, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political
environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement
obligations, a corresponding adjustment is generally made to the oil and gas property balance. See Notes B and I of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding the Company's asset retirement obligations.

Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and
gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net
assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas
producing activities than under the full cost method, particularly during periods of active exploration. The critical difference
between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method,
exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in
which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled
with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense.
During 2012, 2011 and 2010, the Company recognized exploration, abandonment, geological and geophysical expense from
continuing operations of $206.3 million, $121.3 million and $189.6 million, respectively. During 2012, 2011 and 2010, the
Company recognized exploration, abandonment, geological and geophysical expense from discontinued operations of $70
thousand, $4.3 million and $15.9 million, respectively, under the successful efforts method.

Proved reserve estimates. Estimates of the Company's proved reserves included in this Report are prepared in

accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

•
•

the quality and quantity of available data;
the interpretation of that data;

PIONEER NATURAL RESOURCES COMPANY

•
•

the accuracy of various mandated economic assumptions; and
the judgment of the persons preparing the estimate.

The Company's proved reserve information included in this Report as of December 31, 2012, 2011 and 2010 was
prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major
properties. Estimates prepared by third parties may be higher or lower than those included herein.

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results,
reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of
drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the
estimate of proved reserves.

It should not be assumed that the Standardized Measure included in this Report as of December 31, 2012 is the current
market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the 2012
Standardized Measure on a 12-month average of commodity prices on the first day of the month and prevailing costs on the
date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the
estimate. See "Item 1A. Risk Factors" and "Item 2. Properties" for additional information regarding estimates of proved
reserves.

The Company's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves
decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline
may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In
addition, a decline in proved reserve estimates may impact the outcome of the Company's assessment of its proved properties
and goodwill for impairment.

Impairment of proved oil and gas properties. The Company reviews its proved properties to be held and used
whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may
not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future
recoverable proved and risk-adjusted probable and possible reserves, Management's Price Outlooks, production and capital
costs expected to be incurred to recover the reserves; discount rates commensurate with the nature of the properties and net
cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at
which depletion of proved properties is calculated. See Notes B and D of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's impairment assessments.

Impairment of unproved oil and gas properties. At December 31, 2012, the Company carried unproved property costs
of $231.6 million. Management assesses unproved oil and gas properties for impairment on a project-by-project basis.
Management's impairment assessments include evaluating the results of exploration activities, Management's Price Outlooks
and planned future sales or expiration of all or a portion of such projects.

Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final
determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the
results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal
activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets

following the completion of drilling unless both of the following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.

(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the

project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of
time to evaluate the future potential of an exploration project and economics associated with making a determination on its
commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in
technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon
recoverability based on well information, gaining access to other companies' production, transportation or processing facilities
and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly.
Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that
the well has found proved reserves to sanction the project or is noncommercial and is impaired. See Note F of Notes to

PIONEER NATURAL RESOURCES COMPANY

Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding the Company's suspended exploratory well costs.

Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to
determine whether it is more likely than not that its deferred tax assets, if any, will be realized prior to their expiration. Pioneer
monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the
Company's net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their
expiration. There can be no assurance that facts and circumstances will not materially change and require the Company to
establish deferred tax asset valuation allowances in certain jurisdictions in a future period.

Goodwill impairment. The Company reviews its goodwill for impairment at least annually. During the third quarter of
2012, the Company performed a qualitative assessment of goodwill in accordance with Financial Accounting Standards Board
Accounting Standards Update No. 2011-08, Intangibles - Goodwill and Other (Topic 350) which permits an entity to first
assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its
carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The
Company determined that it was not likely that the Company's goodwill was impaired.

For assessments prior to 2012, the Company was required to estimate the fair value of the assets and liabilities of the
reporting units that have goodwill. There is considerable judgment involved in estimating fair values, particularly in
determining the valuation methodologies to utilize, the estimation of proved reserves as described above and the weighting of
different valuation methodologies applied. The carrying value of the Company's goodwill was assessed and found not to be
impaired during the years ended December 31, 2011 and 2010. See Note B of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding goodwill and
assessments of goodwill for impairment.

Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for
ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs
to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the
amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and
regulations, developing information relating to the extent and nature of site contamination and improvements in technology.
Under GAAP, a liability is recorded for these types of contingencies if the Company determines the loss to be both probable
and reasonably estimable. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional information regarding the Company's commitments and contingencies.

Valuation of stock-based compensation. In accordance with GAAP, the Company calculates the fair value of stock-
based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs
necessary to determine fair value. The Company utilizes (a) the Black-Scholes option pricing model to measure the fair value
of stock options, (b) the closing stock price on the day prior to the date of grant for the fair value of restricted stock awards,
(c) the closing stock price at the balance sheet date for restricted stock awards that are expected to be settled wholly or partially
in cash on their vesting date, (d) the Monte Carlo simulation method for the fair value of performance unit awards, and (e) a
probability forecasted fair value method for Series B unit awards issued by Sendero Drilling Company, LLC. See Note H of
Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
information regarding the Company's stock-based compensation.

Valuation of other assets and liabilities at fair value. In accordance with GAAP, the Company periodically measures
and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and
records at fair value include trading securities, commodity derivative contracts and interest rate contracts. The Company also
measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used
by the Company to measure the fair values of these assets and liabilities require considerable management judgment and
estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates
and current volatility factors. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for information regarding the methods used by management to estimate the fair values of
these assets and liabilities.

New Accounting Pronouncements

There are no new accounting pronouncements that are likely of having a material impact on the Company's consolidated

financial statements.

PIONEER NATURAL RESOURCES COMPANY

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about financial instruments to which the Company
was a party as of December 31, 2012, and from which the Company may incur future gains or losses from changes in
commodity prices or interest rates.

The fair values of the Company's derivative contracts are determined based on the Company's valuation models and
applications. As of December 31, 2012, the Company was a party to commodity swap contracts, interest rate swap contracts,
commodity collar contracts and commodity collar contracts with short put options. See Note E of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding
the Company's derivative contracts. The following table reconciles the changes that occurred in the fair values of the
Company's open derivative contracts during 2012:

Commodities

Derivative Contract Net Assets (Liabilities)
Interest Rate
(in thousands)
$

Total

Fair value of contracts outstanding as of December 31, 2011 .................................... $ 389,753
352,679
Changes in contract fair values (a) .............................................................................
(277,462 )
Contract maturities .....................................................................................................
Contract terminations .................................................................................................
(146,593 )
Fair value of contracts outstanding as of December 31, 2012 .................................... $ 318,377
_____________________
(a) At inception, new derivative contracts entered into by the Company generally have no intrinsic value.

(15,654) $ 374,099
330,251
(22,428)
(277,462 )
—
28,358
(118,235 )
(9,724) $ 308,653

Quantitative Disclosures

Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" and Capital Commitments, Capital Resources and Liquidity included in "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations" for information regarding debt transactions.

The following tables provide information about financial instruments to which the Company was a party as of December 31,
2012 that were sensitive to changes in interest rates. For debt obligations, the tables present 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 rates represent the contractual fixed rates that the
Company was obligated to periodically pay on the debt as of December 31, 2012. For variable rate debt, the average interest rate
represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on
February 8, 2013.

PIONEER NATURAL RESOURCES COMPANY

INTEREST RATE SENSITIVITY
DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

Year Ending December 31,

Liability Fair
Value at
December 31,

2013

2014

2015

2016

2017

Thereafter

Total

2012

Total Debt:

Fixed rate principal maturities
(a)............................................ $ 479,907

(in thousands, except percentages)

—

$ —

$ 455,385

$ 485,100

$ 1,749,500

$ 3,169,892

$ (3,939,650 )

Weighted average interest rate

6.12%

6.15%

6.15 %

6.17 %

6.11 %

6.28%

Variable rate principal
maturities:

Pioneer Natural Resources
credit facility ........................... $

—

$ —

—

$ 474,000

—

$ 474,000

(492,485 )

Weighted average interest rate

1.83%

2.01%

2.35 %

2.70 %

2.95 %

—

$ —

—

$ 126,000

—

$ 126,000

(123,635 )

1.96%

2.13%

2.48 %

2.83 %

3.07 %

—

Pioneer Southwest credit
facility ..................................... $
Weighted average interest
rate ..........................................
Interest Rate Swaps:

Notional debt amount ............. $

Fixed rate payable (%) ............

—
—
—

$ —
—
—

$ 250,000

3.21 %

—
—
—

$ 250,000

(9,724 )

Variable rate receivable (%) ...
_______________________
(a) Represents maturities of principal amounts excluding debt issuance discounts and net deferred fair value hedge losses.

3.01 %

Commodity derivative instruments and price sensitivity. The following tables provide information about the Company's oil,
NGL, diesel and gas derivative financial instruments that were sensitive to changes in commodity prices as of December 31, 2012.
Declines in commodity prices would reduce the Company's revenues, although the liquidity effects of such fluctuations would be
mitigated by the Company's derivative activities.

The Company manages commodity price risk with derivative 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 floor-to-
short put price differential.

See Notes B, D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for a description of the accounting procedures followed by the Company relative to its derivative financial
instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to
changes in oil, NGL or gas prices.

PIONEER NATURAL RESOURCES COMPANY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

OIL PRICE SENSITIVITY

Year Ending December 31,
2014

2015

2013

Asset (Liability)
Fair Value at
December 31,
2012
(in thousands)

Oil Derivatives:

Average daily notional BBL volumes:

Swap contracts .......................................................................

Weighted average fixed price per BBL ............................... $

Collar contracts with short puts (a) .......................................

Weighted average ceiling price per BBL ............................ $
Weighted average floor price per BBL ............................... $
Weighted average short put price per BBL ......................... $
Average forward NYMEX oil prices (b) ................................. $
Rollfactor swap contracts (a) .................................................

Weighted average fixed price per BBL (c) ......................... $
Average forward NYMEX rollfactor prices (b) ....................... $
Basis swap contracts (d) ........................................................

Weighted average fixed price per BBL ............................... $
Average forward basis differential prices (e) ........................... $

$
$
$
$

3,000
81.02
71,029
119.76
92.27
74.28
97.24
6,000
0.43
$
(0.14 ) $
2,055
(5.75 ) $
(1.25 ) $

—
—
60,000
117.06
92.67
76.58
95.03
—
—
—
—
—
—

$
$
$
$

$
$

—
—
26,000
104.45
95.00
80.00
91.18
—
—
—
—
—
—

(13,225 )

160,817

1,375

301

_____________________
(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional 2014 (i) collar contracts
with short puts for 9,000 BBLs per day with a ceiling price of $104.13 per BBL, a floor price of $95.00 per BBL and a short
put price of $80.00 per BBL and (ii) rollfactor swap contracts for 15,000 BBLs per day priced at $0.38 per BBL; and (iii)
replaced 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $124.00 per BBL, a floor price of
$90.00 per BBL and short put price of $72.00 per BBL with 5,000 BBLs per day of 2014 collar contracts with short puts with
a ceiling price of $105.74 per BBL, a floor price of $100.00 per BBL and short put price of $80.00 per BBL.
The average forward NYMEX oil prices are based on February 8, 2013 market quotes.

(b)
(c) Represents swaps that fix the difference between (i) each day's price per BBL of WTI for the first nearby month less (ii) the
price per BBL of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per BBL of WTI
for the first nearby month less (iv) the price per BBL of WTI for the third nearby NYMEX month, multiplied by .3333.
(d) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional basis swap contracts for
1,000 BBLs per day of October through December 2013 production with a price differential between Cushing WTI and
Louisiana Light Sweet crude of $7.60 per BBL.
The average forward basis differential prices are based on February 8, 2013 market quotes for basis differentials between
Midland WTI and Cushing WTI.

(e)

PIONEER NATURAL RESOURCES COMPANY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

NGL PRICE SENSITIVITY

Year Ending December 31,
2014
2013

NGL Derivatives:

Average daily notional BBL volumes:

Collar contracts with short puts ...............................................................

Weighted average ceiling price per BBL .............................................. $
Weighted average floor price per BBL ................................................. $
Weighted average short put price per BBL ........................................... $
Average forward NGL prices (a) ............................................................... $

1,064
105.28
89.30
75.20
91.88

$
$
$
$

1,000
109.50
95.00
80.00
84.91

Asset
Fair Value at
December 31,
2012
(in thousands)

1,799

_______________________
(a)

Forward component NGL prices are derived from active-market NGL component price quotes as of February 8, 2013.

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

GAS PRICE SENSITIVITY

Year Ending December 31,
2014

2015

2013

Gas Derivatives:

Average daily notional MMBTU volumes:

Swap contracts .......................................................................

Weighted average fixed price per MMBTU ....................... $

Collar contracts .....................................................................

Weighted average ceiling price per MMBTU ..................... $
Weighted average floor price per MMBTU ........................ $

Collar contracts with short puts .............................................

Weighted average ceiling price per MMBTU ..................... $
Weighted average floor price per MMBTU ........................ $
Weighted average short put price per MMBTU .................. $
Average forward NYMEX gas prices (a) ................................ $
Basis swap contracts ..............................................................

162,500
5.13
150,000
6.25
5.00
—
—
—
—
3.58
162,500

$
$

$
$
$
$

105,000
4.03
—
—
—
25,000
4.70
4.00
3.00
4.04
10,000

$
$

$
$
$
$

Weighted average fixed price per MMBTU ....................... $
Average forward basis differential prices (b) .......................... $

(0.22 ) $
(0.11 ) $

(0.19 ) $
(0.20 ) $

—
—
—
—
—
225,000
5.09
4.00
3.00
4.25
—
—
—

Asset (Liability)
Fair Value at
December 31,
2012
(in thousands)

93,581

81,332

(1,954)

(5,627)

_____________________
(a)
(b)

The average forward NYMEX gas prices are based on February 8, 2013 market quotes.
The average forward basis differential prices are based on February 8, 2013 market quotes for basis differentials between the
relevant index prices and NYMEX-quoted forward prices.

Marketing derivative instruments and price sensitivity. The Company manages commodity price risk and mitigates firm
transportation commitment costs with derivative contracts. Periodically, the Company enters into gas buy and sell marketing
arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may
enter into gas index swaps to mitigate price risk.

PIONEER NATURAL RESOURCES COMPANY

MARKETING GAS PRICE SENSITIVITY

DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2012

Quarter Ending
March 31,
2013

Liability
Fair Value at
December 31,
2012
(in thousands)

Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):

Basis swap contracts:

Index swap volume (a) ............................................................................................................
Price differential ($/MMBTU) ................................................................................................ $
Average forward basis differential prices (b) .......................................................................... $

40,000
0.25
0.26

(22 )

____________________

(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional marketing derivative gas

index swap contracts for 25,000 MMBTU per day for April 2013 volumes with a price differential of $0.35 per MMBTU.

(b) The average forward basis differential prices are based on February 8, 2013 market quotes for basis differentials between

the relevant index prices and NYMEX-quoted forward prices.

Qualitative Disclosures

The Company's primary market risk exposures are to changes in commodity prices and interest rates. These risks did not

change materially from December 31, 2011 to December 31, 2012.

Non-derivative financial instruments. The Company is a borrower under fixed rate and variable rate debt instruments
that give rise to interest rate risk. The Company's objective in borrowing under fixed or variable rate debt is to satisfy capital
requirements while minimizing the Company's costs of capital. See Note G of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company's debt instruments.

Derivative financial instruments. The Company, from time to time, utilizes commodity price and interest rate derivative
contracts to mitigate commodity price and interest rate risks in accordance with policies and guidelines approved by the Board.
In accordance with those policies and guidelines, the Company's executive management determines the appropriate timing and
extent of derivative transactions.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements

Consolidated Financial Statements of Pioneer Natural Resources Company:

Report of Independent Registered Public Accounting Firm ................................................................................................
Consolidated Balance Sheets as of December 31, 2012 and 2011 ......................................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010 ....................................
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010 ...............
Consolidated Statements of Equity for the Years Ended December 31, 2012, 2011 and 2010 ..........................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 ...................................
Notes to Consolidated Financial Statements .......................................................................................................................
Unaudited Supplementary Information ...............................................................................................................................

Page

70
71
73
74
75
77
78
113

REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM

The Board of Directors and Stockholders of
Pioneer Natural Resources Company

We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company (the
"Company") as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income,
equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial
position of Pioneer Natural Resources Company at December 31, 2012 and 2011, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally
accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), Pioneer Natural Resources Company's internal control over financial reporting as of December 31, 2012, based on
criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 13, 2013 expressed an unqualified opinion thereon.

Dallas, Texas
February 13, 2013

/s/ Ernst & Young LLP

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS
(in thousands)

December 31,

2012

2011

Current assets:

ASSETS

Cash and cash equivalents ........................................................................................................... $
Accounts receivable:

229,396

537,484

Trade, net of allowance for doubtful accounts of $848 and $806 as of December 31,
2012 and December 31, 2011, respectively ........................................................................
Due from affiliates.....................................................................................................................
Income taxes receivable ...............................................................................................................
Inventories ...................................................................................................................................
Prepaid expenses ..........................................................................................................................
Discontinued operations held for sale ..........................................................................................
Other current assets:

316,854
3,299
7,447
197,056
13,438
—

275,991
7,822
3
241,609
14,263
73,349

Derivatives ................................................................................................................................
Other ..........................................................................................................................................
Total current assets .................................................................................................................

279,119
3,746
1,050,355

238,835
12,936
1,402,292

Property, plant and equipment, at cost:

Oil and gas properties, using the successful efforts method of accounting:

Proved properties ....................................................................................................................... 14,259,708
231,555
Unproved properties ..................................................................................................................
(4,412,913 )
Accumulated depletion, depreciation and amortization ...............................................................

Total property, plant and equipment ....................................................................................... 10,078,350
298,142
1,217,694

Goodwill ..........................................................................................................................................
Other property and equipment, net ..................................................................................................
Other assets:

12,013,805
235,527
(3,648,465 )
8,600,867
298,142
573,075

Investment in unconsolidated affiliate .........................................................................................
Derivatives ...................................................................................................................................

204,129
55,257

169,532
243,240

Other, net of allowance for doubtful accounts of $629 and $340 as of December 31, 2012
and December 31, 2011, respectively ...................................................................................

165,103
$ 13,069,030

160,008
$ 11,447,156

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (Continued)

(in thousands, except share data)

LIABILITIES AND EQUITY

December 31,

2012

2011

Current liabilities:

Accounts payable:

Trade ....................................................................................................................................... $
Due to affiliates .......................................................................................................................
Interest payable ..........................................................................................................................
Income taxes payable .................................................................................................................
Deferred income taxes ...............................................................................................................
Discontinued operations held for sale ........................................................................................
Other current liabilities:

Derivatives ..............................................................................................................................
Deferred revenue .....................................................................................................................
Other ........................................................................................................................................
Total current liabilities ..........................................................................................................
Long-term debt ..............................................................................................................................
Derivatives ....................................................................................................................................
Deferred income taxes ...................................................................................................................
Other liabilities ..............................................................................................................................
Equity:

Common stock, $.01 par value; 500,000,000 shares authorized; 134,966,740 and
133,121,092 shares issued at December 31, 2012 and 2011, respectively .........................
Additional paid-in capital ..........................................................................................................
Treasury stock, at cost: 11,611,093 and 11,264,936 shares at December 31, 2012 and
2011, respectively ...............................................................................................................
Retained earnings .......................................................................................................................
Accumulated other comprehensive loss—net deferred hedge losses, net of tax ........................
Total equity attributable to common stockholders ..................................................................
Noncontrolling interest in consolidating subsidiaries ................................................................
Total equity .............................................................................................................................
Commitments and contingencies ...................................................................................................

729,942
96,935
68,083
208
86,481
—

647,455
68,756
57,240
9,788
57,713
75,901

13,416
—
39,725
1,034,790
3,721,193
12,307
2,140,416
293,016

74,415
42,069
36,174
1,069,511
2,528,905
33,561
1,942,446
221,595

1,350
3,683,934

1,331
3,613,808

(510,570)
2,514,640
—
5,689,354
177,954
5,867,308

(458,281 )
2,335,066
(3,130 )
5,488,794
162,344
5,651,138

$ 13,069,030

$ 11,447,156

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)

Year Ended December 31,
2011

2010

2012

Revenues and other income:

Oil and gas .............................................................................................................. $ 2,811,660
28,310
Interest and other ....................................................................................................
330,251
Derivative gains, net ...............................................................................................
58,087
Gain (loss) on disposition of assets, net ..................................................................
—
Hurricane activity, net.............................................................................................
3,228,308

$ 2,294,063
66,880
392,752

(3,644)
1,454
2,751,505

$ 1,718,297
56,972
448,434
19,074
138,918
2,381,695

Costs and expenses:

Oil and gas production ............................................................................................
Production and ad valorem taxes ............................................................................
Depletion, depreciation and amortization ...............................................................
Impairment of oil and gas properties ......................................................................
Exploration and abandonments ...............................................................................
General and administrative .....................................................................................
Accretion of discount on asset retirement obligations ............................................
Interest ....................................................................................................................
Other .......................................................................................................................

Income from continuing operations before income taxes ...........................................
Income tax provision ..................................................................................................
Income from continuing operations ............................................................................
Income from discontinued operations, net of tax .......................................................
Net income .................................................................................................................
Net income attributable to noncontrolling interests ................................................

635,644
187,757
810,191
532,589
206,291
248,282
9,887
204,222
113,388
2,948,251
280,057
(92,384 )
187,673
55,149
242,822
(50,537 )

447,142
147,664
578,268
354,408
121,320
193,215
8,256
181,660
63,166
2,095,099
656,406
(197,644)
458,762
423,152
881,914
(47,425)

364,764
112,141
499,856
—
189,597
164,332
7,945
183,084
78,404
1,600,123
781,572
(269,627 )
511,945
134,050
645,995
(40,787 )
$ 605,208

Net income attributable to common stockholders ...................................................... $ 192,285
Basic earnings per share:

$ 834,489

Income from continuing operations attributable to common stockholders ............. $
Income from discontinued operations attributable to common stockholders ..........
Net income attributable to common stockholders ................................................... $

Diluted earnings per share:

Weighted average shares outstanding:

1.10
0.44
1.54

1.07
0.43
1.50

3.45
3.56
7.01

3.39
3.49
6.88

4.00
1.14
5.14

3.96
1.12
5.08

Basic .......................................................................................................................
Diluted ....................................................................................................................

122,966
126,320

116,904
119,215

115,062
116,330

Amounts attributable to common stockholders:

Income from continuing operations ........................................................................ $ 137,136
55,149
Income from discontinued operations, net of tax ....................................................
Net income .............................................................................................................. $ 192,285

$ 411,337
423,152
$ 834,489

$ 471,158
134,050
$ 605,208

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

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)

Net income ................................................................................................................. $ 242,822
Other comprehensive activity:

$ 881,914

$ 645,995

Year Ended December 31,
2011

2010

2012

(32,636)
8,407
(24,229)
857,685
(33,687)

(84,877 )
23,648
(61,229 )
584,766
(23,206 )
$ 561,560

Net hedge (gains) losses included in continuing operations ...................................
Income tax (benefit) provision ................................................................................
Other comprehensive activity ...............................................................................
Comprehensive income ..............................................................................................
Comprehensive income attributable to the noncontrolling interests .......................

4,855
(1,725 )
3,130
245,952
(50,537 )

Comprehensive income attributable to common stockholders ................................... $ 195,415

$ 823,998

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

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6
7

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

Cash flows from operating activities:

Net income ................................................................................................................. $ 242,822
Adjustments to reconcile net income to net cash provided by operating activities:

$ 881,914

$ 645,995

Year Ended December 31,
2011

2010

2012

Depletion, depreciation and amortization ................................................................
Impairment of oil and gas properties .......................................................................
Exploration expenses, including dry holes ..............................................................
Hurricane activity, net .............................................................................................
Deferred income taxes .............................................................................................
(Gain) loss on disposition of assets, net ..................................................................
Accretion of discount on asset retirement obligations .............................................
Discontinued operations ..........................................................................................
Interest expense .......................................................................................................
Derivative related activity .......................................................................................
Amortization of stock-based compensation ............................................................
Amortization of deferred revenue............................................................................
Other noncash items ................................................................................................

Change in operating assets and liabilities:

Accounts receivable, net ..........................................................................................
Income taxes receivable ..........................................................................................
Inventories ...............................................................................................................
Prepaid expenses .....................................................................................................
Other current assets .................................................................................................
Accounts payable ....................................................................................................
Interest payable .......................................................................................................
Income taxes payable ..............................................................................................
Other current liabilities ............................................................................................
Net cash provided by operating activities .............................................................

Cash flows from investing activities:

Proceeds from disposition of assets, net of cash sold ................................................
Payments for acquisition, net of cash acquired ..........................................................
Investment in unconsolidated subsidiary ...................................................................
Additions to oil and gas properties ............................................................................
Additions to other assets and other property and equipment, net ..............................
Net cash used in investing activities ........................................................................

Cash flows from financing activities:

810,191
532,589
125,376
—
85,459
(58,087 )
9,887
(19,344 )
35,563
68,604
62,567
(42,069 )
(39,599 )

578,268
354,408
47,231
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3,644
8,256
(376,717)
31,483
(221,899)
41,442
(44,951)
6,725

499,856
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4,508
259,763
(19,074 )
7,945
77,158
30,472
(419,809)
39,854
(90,216 )
25,102

(28,206 )
(5,953 )
33,059
1,447
14,291
46,038
10,842
(9,580 )
(38,320 )

(47,331)
29,406
(137,401)
(3,415)
1,957
136,296

(1,768)
(7,623)
61,210
1,529,714

36,653
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(26,281 )
(3,874 )
(14,270 )
128,927
11,999
4,007
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1,285,023

1,837,577

819,044
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313,780
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(2,758,073 ) (1,926,965) (1,011,442 )
(184,330)
(954,856)

(363,246)
(3,256,410 ) (1,560,787)

(296,809 )

(89,620)

—

1,776,618
(612,001 )

Borrowings under long-term debt ..............................................................................
Principal payments on long-term debt .......................................................................
Proceeds from issuance of common stock, net of issuance costs ...............................
Proceeds from issuance of partnership common units, net of issuance costs ............
Contributions from noncontrolling interests ..............................................................
Distributions to noncontrolling interests ....................................................................
Payments of other liabilities ......................................................................................
Exercise of long-term incentive plan stock options and employee stock purchases ..
Purchase of treasury stock .........................................................................................
Excess tax benefit (provision) from share-based payment arrangements ..................
Payment of financing fees ..........................................................................................
Dividends paid ...........................................................................................................
1,110,745
Net cash provided by (used in) financing activities .................................................
(308,088 )
Net increase (decrease) in cash and cash equivalents ....................................................
Cash and cash equivalents, beginning of period ............................................................
537,484
Cash and cash equivalents, end of period ...................................................................... $ 229,396

(35,903 )
(1,153 )
7,271
(63,325 )
58,486
(9,227 )
(10,021 )

—
—
—

196,616
(294,883)
484,160
122,976
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(26,702)
(901)
3,696
(40,355)
31,087
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(9,556)

292,342
(475,252)
—
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(26,837 )
(21,329 )
7,375
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(153 )
(145 )
(9,488 )
(246,375)
83,792
27,368
$ 111,160

457,397
426,324
111,160
$ 537,484

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

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 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 Alaska. The Company's objective is to maximize
shareholder investment returns by maintaining financial flexibility, capital allocation discipline and enhancing net asset value
through accretive drilling programs, joint ventures and acquisitions.

NOTE B. Summary of Significant Accounting Policies

Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-
owned and majority-owned subsidiaries since their acquisition or formation. In accordance with generally accepted accounting
principles in the United States ("GAAP"), the Company proportionately consolidates certain affiliate partnerships that are less
than wholly-owned and are involved in oil and gas producing activities. All material intercompany balances and transactions
have been eliminated.

Certain reclassifications have been made to the 2011 and 2010 financial statement and footnote amounts in order to

conform them to the 2012 presentations.

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

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

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial
statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts
of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill
and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and
gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves
and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for
impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others,
estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and
assumptions utilized.

Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and

marketable securities with original issuance maturities of 90 days or less.

Accounts receivable. As of December 31, 2012 and 2011, the Company had accounts receivable – trade, net of
allowances for bad debts, of $316.9 million and $276.0 million, respectively. The Company's accounts receivable – trade are
primarily comprised of oil and gas sales receivable, joint interest receivables and other receivables for which the Company does
not require collateral security.

As of December 31, 2012 and 2011, the Company's allowances for doubtful accounts totaled $1.5 million and $1.1
million, respectively. The Company establishes allowances for bad debts equal to the estimable portions of accounts and notes
receivables for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables
for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances
surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the
receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated
statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be
probable.

Inventories. The Company's inventories consist of materials and supplies and commodities. The Company's materials
and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to
fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials
and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower
of cost or market, on a first-in, first-out cost basis. "Market," in the context of inventory valuation, represents net realizable
value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which
the Company is a party. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to the
carrying values of the materials and supply inventories in the Company's consolidated balance sheets and as other expense in
the accompanying consolidated statements of operations.

Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company's
commodities inventories consist of oil held in storage and natural gas liquids ("NGLs") and gas pipeline fill volumes. Any
valuation allowances of commodities inventories are recorded as reductions to the carrying values of the commodities
inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated
statements of operations.

The following table presents the Company's materials and supplies and commodities inventories as of December 31,

2012 and 2011:

Year Ended December 31,

2012

2011

(in thousands)

Materials and supplies (a) ........................................................................................................ $ 258,962 $ 297,910
4,453
Commodities ............................................................................................................................
Less: Noncurrent materials and supplies (b) ............................................................................

(67,352 )

5,446

(60,754 )
$ 197,056 $ 241,609

____________________

(a) As of December 31, 2012 and 2011, the Company's materials and supplies inventories were net of valuation reserve

allowances of $4.6 million and $0.9 million, respectively.

(b) Included in other noncurrent assets in the Company's accompanying consolidated balance sheet.

Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties.
Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while
nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest
on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects
are ready for their intended use. For large development projects requiring significant upfront development costs to support the
drilling and production of a planned group of wells, the Company continues to capitalize interest on the portion of the
development costs attributable to the planned wells yet to be drilled.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets

following the completion of drilling unless both of the following conditions are met:

(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.

(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the

project.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

recoverability based on well information, gaining access to other companies' production data in the area, transportation or
processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are
being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a
decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is
charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended
exploratory well costs.

The Company owns interests in four gas processing plants and ten treating facilities. The Company is the operator of two
of the gas processing plants and all ten of the treating facilities. The Company's ownership interests in the gas processing plants
and treating facilities is primarily to accommodate handling the Company's gas production and thus are considered a
component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity
at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating
facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating
facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants
and treating facilities for the three years ended December 31, 2012, 2011 and 2010 were $39.4 million, $46.0 million and $34.0
million, respectively. Third party expenses attributable to the processing plants and treating facilities for the same respective
periods were $27.1 million, $22.7 million and $14.3 million. The capitalized costs of the plants and treating facilities are
included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized
costs of the field that they service.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves.
Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from
depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is
determined.

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are
credited and charged, respectively, to accumulated depletion, depreciation and amortization. Generally, no gain or loss is
recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire
amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in
the depletion base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties
accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is
less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount
by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information
regarding the Company's proved property impairment provisions.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These
impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or
expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not
expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at
that time. See Note D for additional information regarding impairment of Barnett Shale unproved properties.

Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the
cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP,
goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that
impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is
determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in
which it is determined to be impaired. During the third quarter of 2012, the Company performed a qualitative assessment of
goodwill. Financial Accounting Standards Board ("FASB") Accounting Standards Update No. 2011-08, Intangibles - Goodwill
and Other (Topic 350) permits an entity to first assess qualitative factors to determine whether it is more likely than not that the
fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the
two-step goodwill impairment test. Based upon the results of the assessment, the Company determined that it was not likely
that the Company's goodwill was impaired.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2012 and 2011,

respectively, the net carrying value of other property and equipment consisted of the following:

Year Ended December 31,

2012 (a)

2011 (a)

(in thousands)

Proved and unproved sand properties ................................................................................................ $ 457,033 $
Equipment and rigs (b) ......................................................................................................................

Land and buildings ............................................................................................................................

Transportation equipment ..................................................................................................................

Furniture and fixtures ........................................................................................................................

Leasehold improvements ...................................................................................................................

—
329,157
160,795
28,108
34,567
20,448
$ 1,217,694 $ 573,075

385,887
259,629
44,928
43,614
26,603

____________________

(a) At December 31, 2012 and 2011, other property and equipment was net of accumulated depreciation of $395.9 million

and $297.6 million, respectively.

(b) Includes drilling rigs, well servicing rigs and equipment and fracture stimulation equipment.

The Company's proved and unproved sand properties include sand mines, sales facilities and unproved leaseholds that
primarily provide the Company and other unrelated customers with proppant used in the fracture stimulation of oil and gas
wells. See Note C for additional information about the Company's sand mine operations. The Company's equipment and rigs
include assets owned by subsidiaries that provide drilling, pumping and well services on Company-operated properties. The
primary purposes of the Company's sand mines and drilling, pumping and well services operations are to accommodate the
Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than
being dependent on third-party availability, and to contain associated costs. As of December 31, 2012, the Company owned 15
drilling rigs, ten fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation
tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. All intercompany gains
or losses of the Company's sand mines and drilling, pumping and well services operations are eliminated. Earnings from sales
of proppant and from providing drilling, pumping and well services to third-party customers and working interest owners in
Company-operated properties are included in interest and other income in the accompanying consolidated statements of
operations.

The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand
reserves. Equipment items are generally depreciated by individual component on a straight line basis over their economic
useful lives, which are generally from two to 12 years. Leasehold improvements are amortized over the lesser of their economic
useful lives or the underlying terms of the associated leases.

The Company evaluates other property and equipment for potential impairment whenever indicators of impairment are
present. Circumstances that could indicate potential impairment include: significant adverse changes in industry trends and the
economic outlook; legal actions; regulatory changes; and significant declines in utilization rates or oil and gas prices. If it is
determined that other property and equipment is potentially impaired, the Company performs an impairment evaluation by
estimating the future undiscounted net cash flow from the use and eventual disposition of other property and equipment
grouped at the lowest level that cash flows can be identified. If the sum of the future undiscounted net cash flows is less than
the net book value of the property, an impairment loss is recognized for the excess, if any, of the assets' net book value over its
estimated fair value.

Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to
own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas.
During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party for $46.4
million of cash proceeds. Associated therewith, the Company recorded a $46.2 million deferred gain that is being amortized as
a reduction in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver
production volumes through EFS Midstream handling and gathering facilities. The deferred gain is included in other current
and noncurrent liabilities in the Company's accompanying consolidated balance sheet.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

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

The Company's equity interest in the net income or loss of EFS Midstream is recorded in interest and other income, net
of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS
Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the
net income or loss of EFS Midstream for the years ended December 31, 2012, 2011 and 2010.

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the
period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are generally
capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet
the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.

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 and expenditures are classified as cash used in
operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the
Company's asset retirement obligations.

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is

reduced by the average purchase price per share of the aggregate treasury shares held.

Noncontrolling interest in consolidated subsidiaries. At December 31, 2012, the Company owned a 0.1 percent general
partner interest and a 52.4 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in proved
and unproved 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. On December 12, 2011, Pioneer
Southwest completed the public offering of 4.4 million common units of Pioneer Southwest, representing limited partnership
interests, at a per-unit offering price to the public of $29.20. Of the 4.4 million common units, Pioneer sold 1.8 million of its
Pioneer Southwest common unit holdings and Pioneer Southwest issued 2.6 million of new common units. The common unit
sale resulted in the Company's limited partnership interest in Pioneer Southwest decreasing from 61.9 percent to 52.4 percent.

In accordance with GAAP, the Company records transfers of any gains or losses, net of taxes, from noncontrolling
interests in consolidated subsidiaries to additional paid in capital proportionate to the ownership after giving effect to the sale of
common units. The following table presents the Company's net income or loss attributable to common stockholders adjusted
for transfers from noncontrolling interest in consolidated subsidiaries to additional paid in capital attributable to Pioneer
Southwest's common unit offerings:

Year Ended December 31,

2012

2011

2010

Net income attributable to common stockholders ................................................ $ 192,285
Transfers from the noncontrolling interest in consolidated subsidiaries:

(in thousands)
$ 834,489

$ 605,208

Increase in additional paid in capital from the sale of 1.8 million Pioneer
Southwest common units during 2011, net of tax of $15.4 million ..................

Increase in additional paid in capital from Pioneer Southwest's offering of
2.6 million common units during 2011, net of tax of $23.7 million .................
Decrease in additional paid in capital for deferred taxes recognized
attributable to Pioneer Southwest's 2008 initial public offering of 9.5 million
common units ...................................................................................................

—

(49,072 )

Net transfers from noncontrolling interest ........................................................

(49,072 )

26,915

8,104

—
35,019

—

—
—

Net income attributable to common stockholders and transfers from
noncontrolling interest .......................................................................................... $ 143,213

$ 869,508

$ 605,208

During January 2010, Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the
Company) formed Sendero Drilling Company, LLC ("Sendero"). Sendero was formed to own and operate land-based drilling

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

rigs in the United States. As of December 31, 2012, Sendero owned 15 drilling rigs operating under contract to Pioneer USA in
the Spraberry field. Pioneer USA is the majority owner of Sendero.

The Company also owns the majority interests in certain other subsidiaries with operations in the United States.
Noncontrolling interests in the net assets of consolidated subsidiaries totaled $178.0 million and $162.3 million as of December
31, 2012 and 2011, respectively. The Company recorded net income attributable to the noncontrolling interests of $50.5
million, $47.4 million and $40.8 million for the years ended December 31, 2012, 2011 and 2010 (principally related to Pioneer
Southwest), respectively.

Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are
considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred
or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably
assured.

The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of
the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other
assets in the accompanying consolidated balance sheets.

The Company had no material oil or NGL entitlement assets or liabilities as of December 31, 2012 or 2011. The
following table presents the Company's gas entitlement assets and liabilities with their associated volumes as of December 31,
2012 and 2011. Gas volumes are presented in millions of cubic feet ("MMCF").

December 31,

2012

2011

Amount

Volume

Amount

Volume

Gas entitlement assets ......................................................................... $
Gas entitlement liabilities ................................................................... $

6.8
1.9

(dollars in millions)

2,870
582

$
$

7.6
2.6

3,024
650

The Company recognized revenue of $42.1 million, $45.0 million and $90.2 million during 2012, 2011 and 2010,
respectively from volumetric production payment ("VPP") agreements which represented limited-term overriding royalty
interests in oil reserves that: (i) entitled the purchaser to receive production volumes over a period of time from specific lease
interests, (ii) were free and clear of all associated future production costs and capital expenditures associated with the reserves,
(iii) were nonrecourse to the Company (i.e., the purchaser's only recourse was to the reserves acquired), (iv) transferred title of
the reserves to the purchaser and (v) allowed the Company to retain the remaining reserves after the VPPs volumetric quantities
had been delivered. All VPP production volumes have been delivered and thus there are no further obligations under VPP
contracts or deferred revenue as of December 31, 2012.

Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value.
Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. The
effective portions of the discontinued deferred hedges as of February 1, 2009 were included in accumulated other
comprehensive income (loss) – net deferred hedge gains (losses), net of tax ("AOCI - Hedging") and were transferred to
earnings during the same periods in which the forecasted hedged transactions were recognized in the Company's earnings.
During 2012, the remaining AOCI - Hedging was transferred to earnings. Since discontinuing hedge accounting, the Company
has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which
they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting
arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case
may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative
counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the
Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the
Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United
States Treasury Bill yield curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on
independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing
Pioneer Southwest's estimated borrowing rate. See Note E for additional information about the Company's derivative
instruments.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

Hurricane activity, net. As a result of Hurricane Rita in September 2005, the Company's East Cameron 322 facility,
located on the Gulf of Mexico shelf, was completely destroyed. Operations to reclaim and abandon the East Cameron 322
facility began in 2006 and were completed during 2011.

In 2007, the Company commenced legal actions against its insurance carriers regarding policy coverage issues for the
cost of reclamation and abandonment of the East Cameron 322 facility. During 2010, the Company and the insurance carriers
agreed to settle the insurance policy dispute, resulting in an additional payment to the Company of $140.1 million during
November 2010. Hurricane activity reclamation and abandonment charges were recorded when changes occurred in
management's estimates of total reclamation and abandonment costs. Associated insurance recoveries were credited to net
hurricane activity in the accompanying consolidated statement of operations in the periods in which claims recoveries were
received.

Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future
economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic
benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental
contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when
environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are
undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities
normally involve estimates that are subject to revision until settlement occurs.

Stock-based compensation. For stock-based compensation awards granted or modified, stock-based compensation
expense is being recognized in the Company's financial statements on a straight line basis over the awards' vesting periods
based on their fair values on the dates of grant. The stock-based compensation awards generally vest over a period not
exceeding three years. The amount of stock-based compensation expense recognized at any date is at least equal to the portion
of the grant date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model
to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair value of
restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled in the
Company's common stock or Pioneer Southwest common units ("Equity Awards"), (iii) the Monte Carlo simulation method for
the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for Series B unit awards issued
by Sendero.

Stock-based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather
than in equity shares or units ("Liability Awards"). Stock-based Liability Awards are recorded as accounts payable—affiliates
based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are
updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases
or decreases to stock-based compensation expense.

Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may
earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated
by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based upon how the Company is organized and managed, the Company has only one reportable operating segment,
which is oil and gas exploration and production. The Company considers its vertical integration services as ancillary to its oil
and gas exploration and producing activities and manages these services to support such activities. In addition, the Company
has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial
performance as a single enterprise.

Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria,
the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the
assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and
liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell.

In addition, after determining that held for sale criteria has been met, the Company considers whether the held for sale
assets meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued
operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued
operations, net of tax, in the accompanying consolidated statements of operations for the current period and all prior periods.
See Note C for additional information about the Company's divestitures.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

During April 2012, a wholly-owned subsidiary of Pioneer acquired 100 percent of the share capital of Industrial Sands
Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC (the "Sand Acquisition").
Subsequent to the acquisition, the Company changed the name of Oglebay Norton Industrial Sands, LLC to Premier Silica LLC
("Premier Silica"). Premier Silica's core business is the operation of mines and processing facilities that produce, process and
sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the
United States. Premier Silica's business is supportive to the Company's vertical integration strategy of controlling major cost
components of the Company's drilling and production activities in the areas where the Company has a significant inventory of
drilling locations. The aggregate purchase price of Premier Silica was $297.1 million, including normal closing adjustments,
and was funded from available cash and borrowings under the Company's credit facility.

The Sand Acquisition was accounted for as a business combination which, among other things, requires that assets
acquired and liabilities assumed be measured at their acquisition date fair values. The fair value of the assets acquired totaled
$474.9 million and were primarily comprised of proved sand reserves, probable sand reserves and mine processing facilities
and equipment of $460.3 million. The fair value of liabilities assumed totaled $177.8 million and were primarily comprised of
deferred income taxes of $151.0 million.

The Company recognized $2.3 million of acquisition-related costs associated with the Sand Acquisition that were
expensed during the year ended December 31, 2012. These costs are included in other expense in the accompanying
consolidated statements of operations for the year ended December 31, 2012, as presented in Note N.

Discontinued Operations

Barnett Shale. During the third quarter of 2012, the Company committed to a plan to divest of its net assets in the
Barnett Shale field in North Texas. The Company classified its (i) Barnett Shale assets and liabilities as discontinued
operations held for sale in the consolidated balance sheet as of September 30, 2012, and (ii) Barnett Shale results of operations
as income or loss from discontinued operations, net of tax, in the consolidated statements of operations for the three and nine
months ended September 30, 2012 and 2011 (representing a recasting of the Barnett Shale results of operations for the three
and nine months ended September 30, 2011, which were originally classified as continuing operations).

The Company retained a capital markets advisor during the third quarter of 2012 and actively solicited offers from
interested purchasers of the Barnett Shale field assets. Those efforts were unsuccessful in attracting binding offers under
acceptable terms to the Company. Since the Company was unable to dispose of its Barnett Shale field assets under acceptable
terms, in December 2012, the Company decided to retain the assets; therefore, the Barnett Shale assets and liabilities no longer
qualified as held for sale or discontinued operations. Accordingly, all amounts related to the Barnett Shale that were previously
reported as (i) discontinued operations held for sale were reclassified to continuing operations at December 31, 2012, (ii)
results from the Barnett Shale operations was recorded to continuing operations for the quarter ended December 31, 2012 and
results included in discontinued operations were reclassified to income from continuing operations for the nine months ended
September 30, 2012, and (iii) amounts in periods prior to 2012 that were reflected in discontinued operations were reclassified
to continuing operations.

Assets classified as held for sale must be assessed for impairment at the point in time when they no longer qualify as
held for sale and their carrying values (adjusted for any depreciation, depletion or amortization that would have been
recognized had the asset been continuously classified as held and used) cannot exceed the lower of fair value or carrying value.
Accordingly, the Company assessed its Barnett Shale field proved and unproved oil and gas properties for impairment during
the fourth quarter of 2012. As a result of those assessments, the Company reduced the carrying value of its Barnett Shale field
proved properties by $87.7 million and its Barnett Shale field unproved properties by $71.8 million. The reductions in the
carrying values of the proved and unproved properties are included in impairment of oil and gas properties and exploration
abandonments, respectively, in the Company's accompanying consolidated statements of operations for the year ended
December 31, 2012. See Note D for further information about the fair values used to calculate the Barnett Shale impairment.

South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to
divest its net assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell its
net assets in Pioneer South Africa to an unaffiliated third party, 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 of the Company's South Africa
subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million,

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the
sale, resulting in a pretax gain of $28.6 million. The Company classified (i) Pioneer South Africa's assets and liabilities as
discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2011 and (ii)
Pioneer South Africa's results of operations prior to the completion of the sale as income from discontinued operations, net of
tax, in the accompanying consolidated statements of operations.

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

The following table represents the components of the Company's discontinued operations for the years ended December
31, 2012, 2011 and 2010 (principally related to the divestitures of the Company's net assets in Pioneer South Africa and
Pioneer Tunisia):

Year Ended December 31,

2012

2011
(in thousands)

2010

Revenues and other income:

Oil and gas .............................................................................................................. $
Interest and other (a) ...............................................................................................
Gain on disposition of assets, net (b) ......................................................................

Costs and expenses:

Oil and gas production ...........................................................................................
Depletion, depreciation and amortization (b) .........................................................
Exploration and abandonments ..............................................................................
General and administrative .....................................................................................
Accretion of discount on asset retirement obligations (b) ......................................
Interest ....................................................................................................................
Other .......................................................................................................................

Income from discontinued operations before income taxes .......................................
Current tax provision ..............................................................................................
Deferred tax (provision) benefit (b)........................................................................
Income from discontinued operations ........................................................................ $
____________________

49,192 $ 100,275 $ 236,343
49,076
36
285,455

6,193
645,241
751,709

95
28,546
77,833

14,754
5,519
2,254
98,495
41,916
—
15,908
4,268
70
5,697
10,286
1,975
2,923
2,686
1,521
—
773
—
13,898
5,159
1,196
151,675
70,607
7,016
133,780
681,102
70,817
(25,486 )
(43,897 )
(7,720 )
25,756
(214,053 )
(7,948 )
55,149 $ 423,152 $ 134,050

(a) Primarily comprised of (i) $35.3 million of interest on excess royalty payments received from Bureau of Ocean

Energy Management, Regulation, and Enforcement during the second quarter of 2010, (ii) $2.0 million of additional
interest received during the first quarter of 2011 associated with the 2010 recovery of the aforementioned excess
royalties and (iii) $2.8 million of interest income associated with Pioneer Tunisia operations during the first quarter of
2011.

(b) Represents significant noncash components of discontinued operations.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

As of December 31, 2011, the carrying values of Pioneer South Africa assets and liabilities, respectively, were included
in discontinued operations held for sale in the accompanying consolidated balance sheet and were comprised of the following:

December 31, 2011
(in thousands)

Composition of assets included in discontinued operations held for sale:

Current assets (excluding cash and cash equivalents) ............................................................................. $
Property, plant and equipment .................................................................................................................
Deferred tax assets...................................................................................................................................
Other assets, net .......................................................................................................................................

Total assets ............................................................................................................................................ $

Composition of liabilities included in discontinued operations held for sale:

Current liabilities ..................................................................................................................................... $
Deferred revenue .....................................................................................................................................
Other liabilities ........................................................................................................................................

Total liabilities ...................................................................................................................................... $

10,465
53,025
9,816
43
73,349

11,689
34,320
29,892
75,901

As of December 31, 2012, there are no assets and liabilities held for sale.

Divestitures Recorded in Continuing Operations

The Company recorded net gains on disposition of assets in continuing operations of $58.1 million and $19.1 million
during the years ended December 31, 2012 and 2010, respectively, and a net loss on disposition of assets in continuing
operations of $3.6 million during the year ended December 31, 2011. The following describes the significant divestitures of
continuing operations:

• Alaska. In August 2012, the Company completed the sale of its interest in the Cosmopolitan Unit in the Cook Inlet of
Alaska to unaffiliated third parties for cash proceeds of $10.1 million, which, together with certain Company obligations
assumed by the purchasers, resulted in a pretax gain of $12.6 million.

• Eagle Ford Shale. In January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the
Eagle Ford Shale play to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a pretax gain of
$42.6 million.

In June 2010, the Company entered into an Eagle Ford Shale joint venture and associated therewith the Company sold 45
percent of its Eagle Ford Shale proved and unproved oil and gas properties to an unaffiliated third party for $212.0 million
of cash proceeds, resulting in a pretax gain of $6.0 million in 2010.

• Uinta/Piceance. During 2010, the Company sold certain proved and unproved oil and gas properties in the Uinta/Piceance
area for net proceeds of $11.8 million and the assumption by the purchaser of certain asset retirement obligations, resulting
in a pretax gain of $17.3 million.

• Other Assets. During 2012, 2011 and 2010, the Company sold unproved leaseholds, inventory and other property and

equipment and recorded a pretax net loss of $1.1 million, $5.1 million and $4.2 million, respectively.

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. 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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

• 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 tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of

December 31, 2012 and 2011 for each of the fair value hierarchy levels:

Fair Value Measurements at the End of the Reporting Period
Using
Significant Other
Observable
Inputs
(Level 2)

Quoted Prices in
Active Markets for
Identical Assets
(Level 1)

Significant
Unobservable
Inputs
(Level 3)

Fair Value at
December 31, 2012

Assets:

Trading securities ................................................... $
Commodity derivatives ..........................................
Deferred compensation plan assets ........................
Total assets ..........................................................

Liabilities:

Commodity derivatives ..........................................
Interest rate derivatives ..........................................
Total liabilities .....................................................
Total recurring fair value measurements .............. $

(in thousands)

124
—
49,685
49,809

—
—
—
49,809

154
334,376
—
334,530

15,999
9,724
25,723
308,807

—
—
—
—

278
334,376
49,685
384,339

15,999
9,724
25,723
358,616

Fair Value Measurements at the End of the Reporting Period
Using
Significant Other
Observable
Inputs
(Level 2)

Quoted Prices in
Active Markets for
Identical Assets
(Level 1)

Significant
Unobservable
Inputs
(Level 3)

Fair Value at
December 31, 2011

Assets:

Liabilities:

(in thousands)

257
—
39,904
40,161

—
—
—
40,161

168
482,075
—
482,243

92,322
15,654
107,976
374,267

—
—
—
—

425
482,075
39,904
522,404

92,322
15,654
107,976
414,428

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 December 31, 2012 and 2011, substantially all of the

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

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, NGL and gas swap contracts, collar
contracts and collar contracts with short puts. The Company's oil, NGL and gas swap, collar and collar contracts with short puts
asset and liability measurements represent Level 2 inputs in the hierarchy priority. The Company utilizes discounted cash flow
and option-pricing models for valuing its commodity derivatives.

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

Interest rate derivatives. The Company's interest rate derivative liabilities as of December 31, 2012 and 2011 represent
interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net
derivative values attributable to the Company's interest rate derivative contracts as of December 31, 2012 and 2011 are based
on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward
active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's
interest rate derivative liability measurements represent Level 2 inputs in the hierarchy priority.

Assets and liabilities measured at fair value on a nonrecurring basis. During 2012 and 2011, reductions in
management's longer-term commodity price outlooks ("Management's Price Outlooks") provided indications of possible
impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas,
the Barnett Shale field in North Texas and the Raton field in southeastern Colorado. As a result of management's assessments,
during June 2012 and December 2011, the Company recognized impairment charges to reduce the carrying values of the
Barnett Shale field and the Edwards Trend/Austin Chalk fields, respectively, to their fair values.

As discussed in Note C, during December 2012, the Barnett Shale field assets were reclassified from held for sale to
held and used. This reclassification triggered an additional assessment to determine whether an impairment charge was
necessary to adjust the carrying value of Barnett Shale field proved and unproved properties to the lower of their fair value or
carrying value. Based upon this assessment, the Company recognized impairment charges to reduce the carrying value of the
Barnett Shale field proved and unproved properties to their fair values during December 2012.

The Company calculated the fair values of the Barnett Shale field and the Edwards Trend/Austin Chalk fields proved
properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted
future cash flows included Management's Price Outlooks and management's outlooks for (i) production costs, (ii) capital
expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price
Outlooks are developed based on third-party commodity 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 fair value. The following table presents the fair
value and impairment (in millions) for each of the Company's 2012 and 2011 proved property impairments, as well as the oil
price per barrel ("BBL") and gas price per British thermal unit ("MMBTU") utilized in respective Management's Price
Outlooks:

Fair
Value

Management's Price Outlooks

Impairment

Oil

Gas

Edwards Trend/Austin Chalk ......................... December 2011

Barnett Shale ..................................................

June 2012

Barnett Shale .................................................. December 2012

189.9
128.7
184.8

354.4
444.9
87.7

92.69
87.09
87.10

5.14
4.64
4.92

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.

During December 2012, the Company recorded an impairment charge to reduce the carrying value of unproved
properties in the Barnett Shale field of $71.8 million. The Company calculated the estimated fair value of the Barnett Shale

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

unproved properties using significant Level 3 assumptions based on average lease bonuses per acre for its Barnett liquid-rich
acreage, allocating no value to dry gas acreage as the Company does not intend to develop that acreage.

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 December 31, 2012 and 2011 are as follows:

December 31, 2012

December 31, 2011

Carrying
Value

Fair
Value

Carrying
Value

Fair
Value

(in thousands)

Long-term debt .......................................................................... $ 3,721,193

$ 4,555,770

$ 2,528,905

$ 3,105,585

Long term debt includes the Company's credit facility, the Pioneer Southwest credit facility and the Company's senior

notes. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

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

Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The

fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.

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

Concentrations of credit risk. As of December 31, 2012, the Company's primary concentration of credit risks are the
risks of collecting accounts receivable – trade and the risk of counterparties' failure to perform under derivative obligations. See
Note L for information regarding the Company's major customers.

The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with
each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with
rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby
the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables
from the defaulting party. See Note E for additional information regarding the Company's derivative activities and information
regarding derivative net assets and liabilities by counterparty.

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.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

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

The following table sets forth the volumes per day in BBLs that were outstanding as of December 31, 2012 under the

Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:

Swap contracts:

Volume (BBL) ........................................................................................................
Average price per BBL ........................................................................................... $

3,000
81.02

—
—

2013

2014

2015

Collar contracts with short puts:

Volume (BBL) (a) ...................................................................................................
Average price per BBL:

Ceiling .................................................................................................................. $
Floor ..................................................................................................................... $
Short put ............................................................................................................... $

Rollfactor adjustment swap contracts:

Volume (BBL) (a) ...................................................................................................
NYMEX roll price (b) ............................................................................................ $

Basis swap contracts:

71,029

60,000

26,000

119.76
92.27
74.28

6,000
0.43

$
$
$

117.06
92.67
76.58

—
—

$
$
$

104.45
95.00
80.00

—
—

Index swap volume (BBL) (c) ................................................................................
Average price per BBL (d) ..................................................................................... $

2,055
(5.75 ) $

____________________
(a) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional 2014 (i) collar
contracts with short puts for 9,000 BBLs per day with a ceiling price of $104.13 per BBL, a floor price of $95.00 per
BBL and a short put price of $80.00 per BBL and (ii) rollfactor swap contracts for 15,000 BBLs per day priced at $0.38
per BBL; and (iii) replaced 5,000 BBLs per day of 2014 collar contracts with short puts with a ceiling price of $124.00
per BBL, a floor price of $90.00 per BBL and short put price of $72.00 per BBL with 5,000 BBLs per day of 2014 collar
contracts with short puts with a ceiling price of $105.74 per BBL, a floor price of $100.00 per BBL and short put price
of $80.00 per BBL.

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

(c) During the period from January 1, 2013 to February 8, 2013, the Company entered into additional basis swap contracts
for 1,000 BBLs per day of October through December 2013 production with a price differential between Cushing WTI
and Louisiana Light Sweet crude of $7.60 per BBL.

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

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are

tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL product component posted prices.

As of December 31, 2012, the Company had NGL collar contracts with short put derivatives for 1,064 BBLs per day of
2013 production with a ceiling price of $105.28 per BBL, a floor price of $89.30 per BBL and short put price of $75.20 per
BBL and 1,000 BBLs per day of 2014 production with a ceiling price of $109.50 per BBL, a floor price of $95.00 per BBL and
short put price of $80.00 per BBL.

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

25,000

225,000

4.70
4.00
3.00

$
$
$

5.09
4.00
3.00

—
—

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

The following table sets forth the volumes per day in MMBTUs that were outstanding as of December 31, 2012 under

the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:

2013

2014

2015

Swap contracts:

Volume (MMBTU) .................................................................................................
Price per MMBTU .................................................................................................. $

162,500
5.13

105,000
4.03

Collar contracts:

Volume (MMBTU) .................................................................................................
Price per MMBTU:

150,000

—

6.25
5.00

$
$

—
—

$
$

—
—

—

—
—

Collar contracts with short puts:

Volume (MMBTU) .................................................................................................
Price per MMBTU:

—

—
—
—

$
$
$

Basis swap contracts:

162,500

10,000

(0.22 ) $

(0.19 ) $

Marketing and basis transfer derivative activities. Periodically, the Company enters into gas buy and sell marketing
arrangements to utilize unused firm pipeline transportation commitments. Associated with these gas marketing arrangements,
the Company may enter into gas index swaps to mitigate the related price risk.

As of December 31, 2012 the Company had marketing derivative gas index swap contracts outstanding for 40,000
MMBTU of January through March 2013 volumes with a price differential of $0.25 per MMBTU. During the period from
January 1, 2013 to February 8, 2013, the Company entered into additional marketing derivative gas index swap contracts for
25,000 MMBTU per day of April 2013 volumes with a price differential of $0.35 per MMBTU.

Interest rates. As of December 31, 2012, the Company was a party to interest rate derivative contracts that lock in a
fixed forward annual interest rate of 3.21 percent, for a 10-year period ending in December 2025, on a notional amount of $250
million. These derivative contracts mature and settle by their terms during December 2015.

Tabular disclosure of derivative fair value. Since February 2009, all of the Company's derivatives have been accounted
for as non-hedge derivatives. The following tables provide disclosure of the Company's derivative instruments for the years
ended December 31, 2012 and 2011:

Fair Value of Derivative Instruments as of December 31, 2012

Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet
Location

Derivatives not designated as hedging instruments

Commodity price derivatives ....... Derivatives - current
Commodity price derivatives ....... Derivatives - noncurrent
Interest rate derivatives ................ Derivatives - noncurrent

Fair Value
(in thousands)

286,805
61,618
—
348,423

Balance Sheet
Location

Derivatives - current
Derivatives - noncurrent
Derivatives - noncurrent

Fair Value
(in thousands)

21,102
8,944
9,724
39,770

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

Fair Value of Derivative Instruments as of December 31, 2011

Asset Derivatives (a)

Liability Derivatives (a)

Type

Balance Sheet Location

Fair Value
(in thousands)

Balance Sheet Location

Fair Value
(in thousands)

Derivatives not designated as hedging instruments

Commodity price derivatives ....... Derivatives - current
Commodity price derivatives ....... Derivatives - noncurrent
Interest rate derivatives ................ Derivatives - current

248,809
257,368
—
506,177

Derivatives - current
Derivatives - noncurrent
Derivatives - current

68,735
47,689
15,654
132,078

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

Derivatives in Cash Flow Hedging Relationships

Location of Gain/(Loss)
Reclassified from AOCI
into Earnings

Amount of Gain/(Loss) Reclassified
from AOCI into Earnings
Year Ended December 31,
2011
(in thousands)

2010

2012

Interest rate derivatives ................................ Interest expense
Interest rate derivatives ................................ Derivative gains, net
Commodity price derivatives ....................... Oil and gas revenue
Total .............................................................

(1,699 ) $
—
(3,156 )
(4,855 ) $

(282) $
—
32,918
32,636

(1,698 )
(2,465 )
89,040
84,877

Derivatives Not Designated as Hedging Instruments

Location of Gain (Loss)
Recognized in Earnings on Derivatives

Interest rate derivatives ................................ Derivative gains, net
Commodity price derivatives ....................... Derivative gains, net
Total .............................................................

2012

Amount of Gain (Loss) Recognized in
Earnings on Derivatives
Year Ended December 31,
2011
(in thousands)
3,098
389,654
$ 392,752

36,597
414,302
$ 450,899

(22,428 ) $
352,679
$ 330,251

2010

AOCI - Hedging. The effective portions of discontinued cash flow hedge gains and losses, net of associated taxes, were
reflected in AOCI - Hedging as of December 31, 2011 and 2010, and were transferred to oil revenue and to interest expense in
the same periods in which the hedged transactions were recorded in earnings.

As of December 31, 2011, AOCI - Hedging was $3.1 million of net deferred losses. The AOCI - Hedging balance as of
December 31, 2011 was comprised of $3.2 million and $1.7 million of net deferred losses on the effective portions of
discontinued commodity and interest rate hedges, respectively, offset partially by $1.7 million of associated net deferred tax
benefits. During 2012, the remaining net deferred hedge losses in AOCI - Hedging were transferred to earnings.

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

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2012:

Citibank, N.A. ........................................................................................................................................ $
JP Morgan Chase ....................................................................................................................................
Barclays Capital .....................................................................................................................................
BMO Financial Group ............................................................................................................................
Credit Suisse ...........................................................................................................................................
J. Aron & Company ...............................................................................................................................
BNP Paribas ...........................................................................................................................................
Toronto Dominion ..................................................................................................................................
Merrill Lynch .........................................................................................................................................
Morgan Stanley ......................................................................................................................................
Den Norske Bank ...................................................................................................................................
Societe Generale .....................................................................................................................................
Wells Fargo Bank, N.A. .........................................................................................................................
Macquarie Bank .....................................................................................................................................
Royal Bank of Canada ............................................................................................................................
Deutsche Bank........................................................................................................................................
Credit Agricole .......................................................................................................................................
UBS ........................................................................................................................................................

Net Assets (Liabilities)
(in thousands)

72,218
48,606
36,736
26,560
21,196
20,138
19,420
18,802
17,136
13,893
7,487
5,700
5,024
380
(97 )
(327 )
(1,991 )
(2,228 )

Total ....................................................................................................................................................... $

308,653

NOTE F. Exploratory Well Costs

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

The following table reflects the Company's capitalized exploratory well and project activity during each of the years

ended December 31, 2012, 2011 and 2010:

2012

2010

Year Ended December 31,
2011
(in thousands)
96,193
$
524,313
(480,716)
(28,938)
(3,256)

$ 127,574
238,905
(160,879)
(17,601 )
(91,806 )
96,193

Beginning capitalized exploratory well costs ................................................................ $ 107,596
926,084
(790,373 )

Additions to exploratory well costs pending the determination of proved reserves ..
Reclassification due to determination of proved reserves ..........................................
Disposition of assets sold ...........................................................................................
Exploratory well costs charged to exploration and abandonment expense ................

(30,637 )

—

Ending capitalized exploratory well costs ..................................................................... $ 212,670

$ 107,596

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

The following table provides an aging, as of December 31, 2012, 2011 and 2010 of capitalized exploratory costs and the
number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date
drilling was completed:

2012

Year Ended December 31,
2011
(in thousands, except well counts)

2010

Capitalized exploratory well costs that have been suspended:

One year or less ...................................................................................................... $ 190,678
21,992
More than one year .................................................................................................
$ 212,670

$ 107,596
—
$ 107,596

70,635
25,558
96,193

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

—

Alaska - Oooguruk. As of December 31, 2012, the Company has $22.0 million 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, sub-surface damages were sustained. The Company currently expects to recomplete the well in mid-
2013.

NOTE G. Long-term Debt and Interest Expense

Long-term debt, including the effects of net deferred fair value hedge losses and issuance discounts, consisted of the

following components at December 31, 2012 and 2011:

December 31,

2012

2011

(in thousands)

Outstanding debt principal balances:

Pioneer credit facility ..................................................................................................................... $ 474,000
126,000
Pioneer Southwest credit facility ...................................................................................................
455,385
5.875% senior notes due 2016 .......................................................................................................
485,100
6.65% senior notes due 2017 .........................................................................................................
449,500
6.875 % senior notes due 2018 ......................................................................................................
450,000
7.500 % senior notes due 2020 ......................................................................................................
600,000
3.95% senior notes due 2022 .........................................................................................................
250,000
7.20% senior notes due 2028 .........................................................................................................
479,907
2.875% convertible senior notes due 2038 ....................................................................................
3,769,892

Issuance discounts .............................................................................................................................
Net deferred fair value hedge losses ..................................................................................................
Total long-term debt .......................................................................................................................... $ 3,721,193

(47,309)
(1,390)

—
32,000
455,385
485,100
449,500
450,000
—
250,000
479,930
2,601,915
(71,301 )
(1,709 )
$ 2,528,905

Credit Facility. During December 2012, the Company entered into the First Amendment to the Second Amended and
Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that extended the
maturity to December 20, 2017, unless extended in accordance with the terms of the Credit Facility, and increased the
aggregate loan commitments from $1.25 billion to $1.5 billion. The Company accounted for the entry into the Credit Facility as
a modification of the prior agreement and capitalized the debt issuance costs along with those unamortized issuance costs that
remained from the issuance of the prior agreement. As of December 31, 2012, the Company had outstanding borrowings of
$474.0 million under the Credit Facility and $2.2 million of undrawn letters of credit, all of which were commitments under the
Credit Facility, leaving the Company with $1.0 billion of unused borrowing capacity under the Credit Facility.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding
swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the
Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo
Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the
Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread
margin, which is currently 0.5 percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to
LIBOR, plus a margin (the "Applicable Margin"), which is currently 1.50 percent and is also determined by the Company's
debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal
funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under
the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also
pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating
(currently 0.25 percent). Borrowings under the Credit Facility are general unsecured obligations.

The Credit Facility requires the maintenance of a ratio of total debt to book capitalization less intangible assets,
accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. As of December 31,
2012, the Company was in compliance with all of its debt covenants.

During March 2012, Pioneer Southwest entered into a $300 million Amended and Restated 5-Year Revolving Credit
Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that matures in March 2017,
unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility
replaced Pioneer Southwest's 5-Year Revolving Credit Agreement entered into in May 2008. As of December 31, 2012, there
were $126 million of outstanding borrowings under the Pioneer Southwest Credit Facility. Borrowings under the Pioneer
Southwest Credit Facility are general unsecured obligations.

The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital
expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate
loans, base rate committed loans or swing line loans. Eurodollar rate loans bear interest annually at LIBOR, plus a margin (the
"Applicable Rate") (currently 1.625 percent) that is determined by a reference grid based on Pioneer Southwest's consolidated
leverage ratio. Base rate committed loans bear interest annually at a base rate equal to the higher of (i) the Federal Funds Rate
plus 0.5 percent (ii) the one-month Eurodollar rate plus .01 or (iii) the Bank of America prime rate (the "Base Rate") plus a
margin (currently 0.625 percent). Swing line loans bear interest annually at the Base Rate plus the Applicable Rate.

The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end
consolidated leverage ratio (representing a ratio of consolidated indebtedness of Pioneer Southwest to consolidated earnings
before depreciation, depletion and amortization; impairment of long-lived assets; exploration expense; accretion of discount on
asset retirement obligations; interest expense; income taxes; gain or loss on the disposition of assets; noncash commodity
derivative related activity; noncash equity-based compensation; and other noncash items) of not more than 3.5 to 1.0 and
(ii) the maintenance of a ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas
assets to total debt of at least 1.75 to 1.0. As of December 31, 2012, Pioneer Southwest was in compliance with all of its debt
covenants.

The net present value covenant limits Pioneer Southwest's available borrowing capacity under the Pioneer Southwest
Credit Facility to $134.7 million as of December 31, 2012, and may further limit Pioneer Southwest's borrowing capacity in the
future. The variables on which the calculation of net present value is based (including assumed commodity prices and discount
rate) are subject to adjustment by the lenders. As a result, a sustained decline in commodity prices could reduce Pioneer
Southwest's borrowing capacity under the Pioneer Southwest Credit Facility. In addition, the Pioneer Southwest Credit Facility
contains various covenants that limit, among other things, Pioneer Southwest's ability to grant liens, incur additional
indebtedness, engage in a merger, enter into transactions with affiliates, pay distributions or repurchase equity, and sell its
assets. If any default or event of default (as defined in the Pioneer Southwest Credit Facility) were to occur, the Pioneer
Southwest Credit Facility would prohibit Pioneer Southwest from making distributions to unitholders. Such events of default
include, among others, nonpayment of principal or interest, violations of covenants, bankruptcy and material judgments and
liabilities.

Pioneer Southwest pays a commitment fee on the unused portion of the Pioneer Southwest Credit Facility. The
commitment fee is variable based on Pioneer Southwest's consolidated leverage ratio. For the twelve months ended December
31, 2012, the commitment fee was 0.275 percent.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

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

Convertible senior notes. During January 2008, the Company issued $500 million of 2.875% Convertible Senior Notes
due 2038 (the "Convertible Senior Notes"). The Convertible Senior Notes mature on January 15, 2038 but are convertible under
certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock
pursuant to a formula. In general, upon conversion of a Convertible Senior Note, the holder of such note will receive cash equal
to the principal amount of the Convertible Senior Note and the Company's common stock for the Convertible Senior Note's
conversion value in excess of such principal amount. If at the time of conversion the applicable price of the Company's
common stock exceeds the base conversion price, holders will receive up to an additional 8.9532 shares of the Company's
common stock per $1,000 principal amount of notes, as determined pursuant to a specified formula.

The Company may redeem the Convertible Senior Notes for cash at any time on or after January 15, 2013 at a price
equal to full principal amount plus accrued and unpaid interest. Holders of the Convertible Senior Notes may require the
Company to purchase their Convertible Senior Notes for cash at a price equal to 100 percent of the principal amount plus
accrued and unpaid interest if certain defined fundamental changes occur, as defined in the agreement, or on January 15, 2013,
2018, 2023, 2028 or 2033. On January 15, 2013, certain holders put $8 thousand principal amount of the Convertible Senior
Notes to the Company and the Company paid $8 thousand, including accrued and unpaid interest, to settle the Convertible
Senior Notes. Additionally, holders may convert their notes at their option in the following circumstances:

•

Following defined periods during which the reported sales prices of the Company's common stock exceeds 130
percent of the base conversion price (initially $72.60 per share, which is equivalent to an initial base conversion
rate of 13.7741 common shares per $1,000 principal amount of Convertible Senior Notes);

• During five-day periods following defined circumstances when the trading price of the Convertible Senior Notes is

less than 97 percent of the price of the Company's common stock times a defined conversion rate;

• Upon notice of redemption by the Company; and
• During the period beginning October 15, 2037, and ending at the close of business on the business day immediately

preceding the maturity date.

The Company's stock prices during each of December 2012, September 2012, March 2012 and March 2011 met the
price threshold that caused the Convertible Senior Notes to become convertible at the option of the holders during the three
months ended March 31, 2013, December 31, 2012, June 30, 2012 and June 30, 2011, respectively. Associated therewith,
certain holders tendered $111 thousand and $70 thousand principal amount of the Convertible Senior Notes for conversion
during the twelve months ended December 31, 2012 and 2011, respectively. During 2012 and 2011, the Company paid the
tendering holders of the Convertible Senior Notes a total of $23 thousand and $71 thousand of cash and issued to the tendering
holders 112 shares and 340 shares of the Company's common stock in accordance with the terms of the Convertible Senior
Notes indenture supplement, respectively. For the remaining notes tendered during 2012, the Company paid $88 thousand in
cash and issued 707 shares in 2013.

In January and February 2013, holders of $240.6 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. In general, upon
conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of the Convertible Senior
Note and shares of the Company's common stock for the Convertible Senior Note's conversion value in excess of the principal
amount. If all outstanding Convertible Senior Notes had been converted on December 31, 2012, the holders would have
received $479.9 million of cash and approximately 3.4 million shares of the Company's common stock, which were valued at
$358.8 million based on the closing price of the common stock on December 31, 2012.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

As of December 31, 2012 and 2011, the Convertible Senior Notes had an unamortized discount, which is being
amortized ratably through January 2013, of $753 thousand and $18.5 million, respectively, and a net carrying value of $479.2
million and $461.5 million, respectively. For the years ended December 31, 2012, 2011 and 2010, the Company recorded $33.5
million, $32.3 million and $31.1 million, respectively, of interest expense relating to the Convertible Senior Notes, which had
an effective interest rate of 6.75 percent. As of December 31, 2012 and 2011, $49.5 million is recorded in Additional Paid-in
Capital as the equity component of the Convertible Senior Notes.

The Company's senior notes and convertible senior notes are general unsecured obligations ranking equally in right of
payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and
future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations
through subsidiaries; consequently, the senior notes and Convertible Senior Notes are structurally subordinated to all
obligations of its subsidiaries. Interest on the Company's senior notes and Convertible Senior Notes is payable semiannually.

Principal maturities. Principal maturities of long-term debt at December 31, 2012, are as follows (in thousands):

479,907
2013 ........................................................................................................................................................................ $
—
2014 ........................................................................................................................................................................ $
—
2015 ........................................................................................................................................................................ $
2016 ........................................................................................................................................................................ $
455,385
2017 ........................................................................................................................................................................ $ 1,085,100
Thereafter ............................................................................................................................................................... $ 1,749,500

The principal maturities during 2013 in the preceding table represent the Convertible Senior Notes, which were subject
to repurchase at the option of both the holders and the Company in 2013. As the Company had the intent and ability to fund
any required cash payments upon the conversion, redemption or repurchase of the Convertible Senior Notes with borrowing
capacity under the Credit Facility, the Convertible Senior Notes are classified as long-term debt in the accompanying balance
sheets.

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended

December 31, 2012, 2011 and 2010:

Cash payments for interest ......................................................................................... $ 168,665
27,351
Accretion/amortization of discounts or premiums on loans .......................................
—
Accretion of discount on derivative obligations .........................................................
2,018
Amortization of net deferred hedge losses (a) ............................................................
257
Accretion of discount on postretirement benefit obligations ......................................
Amortization of capitalized loan fees .........................................................................
5,937
10,842
Net changes in accruals ..............................................................................................
215,070
Interest incurred ..........................................................................................................
Less capitalized interest..............................................................................................
(10,848 )
Total interest expense ................................................................................................. $ 204,222
__________________
(a) Includes interest rate derivative hedges of $1.7 million, $282 thousand, and $1.7 million for the periods ended December
31, 2012, 2011 and 2010, respectively, that were reclassified from AOCI - Hedging into earnings upon expiration (see Note E).

$ 155,854
23,304
521
517
433
5,698
11,999
198,326
(15,242 )
$ 183,084

195,022
(13,362)

$ 181,660

2012

2010

Year Ended December 31,
2011
(in thousands)
$ 165,307
25,210
—
573
315
5,385
(1,768)

NOTE H. Incentive Plans

Retirement Plans

Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of
directors (the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the
Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

annual bonus. The Company will provide a matching contribution of 100 percent of the officer's and key employee's
contribution limited to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The
Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the
contributions made under this retirement plan. The Company's matching contributions were $2.4 million, $2.2 million and $1.9
million for the years ended December 31, 2012, 2011 and 2010, respectively.

401(k) plan. The Pioneer USA 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established
under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to
participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount
up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by
Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five
percent of the participant's base compensation (the "Matching Contribution"). Each participant's account is credited with the
participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in
their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to
Matching Contributions, which proportionately vest over a four-year period that begins with the participant's date of hire.
During the years ended December 31, 2012, 2011 and 2010, the Company recognized compensation expense of $24.7 million,
$18.3 million and $13.4 million, respectively, as a result of Matching Contributions.

Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense,
equal to the fair value of share-based payments, ratably over the vesting periods of the Long-Term Incentive Plan ("LTIP")
awards, the Series B unit awards issued by Sendero, the Pioneer Southwest Long-Term Incentive Plan ("Pioneer Southwest
LTIP") awards and for payments associated with the Company's Employee Stock Purchase Plan ("ESPP").

The following table reflects stock-based compensation expense recorded for each type of incentive award and the

associated income tax benefit for the years ended December 31, 2012, 2011 and 2010:

Restricted stock-equity awards (a) ......................................................................... $
Restricted stock-liability awards ............................................................................
Stock options (b) ....................................................................................................
Performance unit awards ........................................................................................
Pioneer Southwest LTIP ........................................................................................
Sendero Series B units ...........................................................................................
ESPP ......................................................................................................................
Total .......................................................................................................................... $
Income tax benefit ..................................................................................................... $
_____________________
(a)

2012

Year Ended December 31,
2011
(in thousands)
32,861
$
10,882
2,936
4,500
761
1,020
125
53,085
22,084

48,876
22,419
4,110
6,162
1,098
982
2,437
86,084
27,901

$
$

2010

31,712
4,900
1,522
4,635
475
1,020
1,034
45,298
14,019

For the year ended December 31, 2010, stock-based compensation expense included a charge of $1.3 million for the
modification of equity awards associated with termination agreements made with 12 employees affected by the
divestiture of the Company's Tunisian subsidiaries. The modification accelerated vesting of all unvested equity awards
for the 12 participants to the closing date of the transaction. The $1.3 million charge, net of the associated tax benefit, is
included in income from discontinued operations, net of tax, in the accompanying consolidated statements of operations
for the year ended December 31, 2010.

(b) Cash proceeds received from stock option exercises during 2012, 2011 and 2010 amounted to $3.1 million, $619

thousand and $4.8 million, respectively.

As of December 31, 2012, there was $131.1 million of unrecognized stock-based compensation expense related to
unvested share and unit based compensation plans, including $24.5 million attributable to Liability Awards. The stock-based
compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a
period of less than three years on a weighted average basis.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

Pioneer Long-Term Incentive Plan

In May 2006, the Company's stockholders approved the LTIP, which provides for the granting of various forms of
awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to
directors, officers and employees of the Company. The LTIP provides for the issuance of 9.1 million shares pursuant to awards
under the plan. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares,
(ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the
open market.

The following table shows the number of shares available for issuance pursuant to awards under the Company's LTIP at

December 31, 2012:

Approved and authorized awards ...........................................................................................................................
Awards issued after May 3, 2006 ...........................................................................................................................
Awards available for future grant ...........................................................................................................................

9,100,000
(6,134,118 )
2,965,882

Restricted stock awards. During 2012, the Company awarded 1,153,029 restricted shares or units of the Company's
common stock as compensation to directors, officers and employees of the Company (including 240,486 shares or units
representing Liability Awards). The Company's issued shares, as reflected in the consolidated balance sheets as of December
31, 2012 do not include 304,260 of issued, but unvested shares awarded under stock-based compensation plans that have voting
rights.

The following table reflects the restricted stock award activity for the year ended December 31, 2012:

Outstanding at beginning of year .............................................................
Shares granted ......................................................................................
Shares forfeited ....................................................................................
Shares vested ........................................................................................
Outstanding at end of year .......................................................................

Equity Awards

Liability Awards

Number of
Shares
$
1,857,612
912,543
$
(28,011 ) $
(1,229,382 ) $
$
1,512,762

Weighted
Average Grant-
Date Fair
Value

39.95
113.02
101.91
23.75
96.22

Number of Shares
322,925
240,486
(29,060 )
(128,435 )
405,916

The weighted average grant-date fair value of restricted stock equity awards awarded during 2012, 2011 and 2010 was
$113.02, $97.52 and $48.32, respectively. The fair value of shares for which restrictions lapsed during 2012, 2011 and 2010
was $137.2 million, $98.6 million and $42.9 million, respectively, based on the market price on the vesting date.

As of December 31, 2012 and 2011, accounts payable – due to affiliates in the accompanying consolidated balance sheet
includes $18.8 million and $9.2 million of liabilities attributable to the Liability Awards, representing the fair value of
employee services performed under outstanding awards as of that date. The fair value of shares for which restrictions lapsed
during 2012 and 2011 was $14.2 million and $6.7 million, respectively, based on the market price on the vesting date. There
were no Liability Awards that vested during 2010.

Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock
with an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock
option awards is determined using the Black-Scholes option-pricing model. Option awards have a ten-year contract life. The
expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was
estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free
interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the option. The
dividend yield was based upon a seven-year average dividend yield.

100

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

The Company used the following weighted-average assumptions to estimate the fair value of stock options granted

during the years ended December 31, 2012, 2011 and 2010:

Expected option life – years ......................................................................
Volatility ....................................................................................................
Risk-free interest rate ................................................................................
Dividend yield ...........................................................................................

2012

2011

2010

7.0
49.4 %
1.5 %
0.4 %

7.0
47.6%
2.9%
0.4%

7.0
46.8 %
3.4 %
0.4 %

A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2012 is

presented below:

Number
of Shares

Weighted
Average
Exercise Price

Weighted
Average
Remaining
Contractual
Life
(in years)

Aggregate
Intrinsic Value
(in thousands)

Outstanding at beginning of year .............................
Options awarded ......................................................
Options exercised .....................................................
Outstanding and expected to vest, at end of year ........
Exercisable at end of year ............................................

$
564,044
$
98,819
(195,377) $
$
467,486
$
171,644

34.90
113.76
15.62
59.63
16.72

7.39 $
6.17 $

22,663
15,425

The weighted average grant-date fair value of options awarded during 2012, 2011 and 2010 was $56.29, $49.61 and
$23.79, respectively, using the Black-Scholes option-pricing model. The intrinsic value of options exercised during 2012, 2011
and 2010 was $17.2 million, $1.5 million and $6.9 million, respectively, based on the difference between the market price at the
exercise date and the option exercise price.

101

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

Performance unit awards. During 2012, 2011 and 2010, the Company awarded performance units to certain of the
Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the
Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the
performance period. The performance unit awards vest over a 34-month service period. The grant-date fair values per unit of
the 2012, 2011 and 2010 performance unit awards are $172.57, $134.68 and $63.52, respectively, which amounts were
determined using the Monte Carlo simulation method and are being recognized as stock-based compensation expense ratably
over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability
of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities
utilized in the model were estimated using a historical period consistent with the remaining performance period of
approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate
with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit
awards granted during 2012, 2011 and 2010:

Risk-free interest rate ..................................................
Range of volatilities .....................................................

0.40%
33.6 % -49.0%

1.32%
50.2 % -84.1%

1.36%
50.4% -83.0%

2012

2011

2010

The following table summarizes the performance unit activity for the year ended December 31, 2012:

Number of
Units (a)

Weighted Average
Grant-Date
Fair Value

$
114,128
$
47,875
(70,633) $
$
91,370

90.64
172.57
63.52
154.53

Beginning performance unit awards .....................................................................................
Units granted .....................................................................................................................
Units vested (b) .................................................................................................................
Ending performance unit awards ..........................................................................................
_____________________
(a)

These amounts reflect the number of performance units granted. The actual payout of shares may be between zero
percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the
Company compared to peer companies at the vesting date.

(b) On December 31, 2012, the service period lapsed on 70,633 of these performance unit awards. The lapsed units earned

2.5 shares for each vested award representing 176,585 aggregate shares of common stock issued in 2012.

The fair value of shares for which restrictions lapsed during 2012, 2011 and 2010 was $18.8 million, $44.7 million and

$27.4 million, respectively, based on the market price on the vesting date.

Pioneer Southwest Long-Term Incentive Plan

In May 2008, the board of directors of the general partner (the "General Partner") of Pioneer Southwest adopted the
Pioneer Southwest LTIP, which provides for the granting of various forms of unit-based awards, including options, unit
appreciation rights, phantom units, restricted units, unit awards and other unit-based awards, to directors, employees and
consultants of the General Partner and its affiliates who perform services for Pioneer Southwest. The Pioneer Southwest LTIP
limits the number of units that may be delivered pursuant to unit-based awards granted under the plan to 3.0 million common
units.

102

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

The following table shows the number of awards available under the Pioneer Southwest LTIP at December 31, 2012:

Approved and authorized awards .........................................................................................................................
Awards issued after May 6, 2008 .........................................................................................................................
Awards available for future grant .........................................................................................................................

3,000,000
(151,235 )
2,848,765

During 2012, the General Partner awarded 7,496 restricted common units as compensation to directors of the General
Partner under the Pioneer Southwest LTIP, which vest in May 2013. During 2011, the General Partner awarded 6,812
restricted common units as compensation to directors of the General Partner under the Pioneer Southwest LTIP, which vested in
May 2012. During 2010, the General Partner awarded 8,744 restricted common units to directors of the General Partner under
the Pioneer Southwest LTIP, which vested in May 2011.

Restricted Unit Awards

Phantom Unit Awards

Outstanding at beginning of year ..........................................................
Units granted .....................................................................................
Lapse of restrictions ..........................................................................
Outstanding at end of year ....................................................................

Number
of Units

$
7,492
7,496
$
(7,492 ) $
$
7,496

Weighted
Average
Grant-Date
Fair Value
28.47
26.68
28.47
26.68

Number of
Units
65,157
37,487
—
102,644

Weighted
Average
Grant-Date
Fair Value
27.08
28.00
—
27.42

$
$
$
$

The weighted average grant-date fair value of restricted common units awarded during 2012, 2011 and 2010 was $26.68,
$29.35 and $22.87, respectively. The fair value of common units for which restrictions lapsed on the restricted common units
during 2012, 2011 and 2010 was $200 thousand, $342 thousand and $324 thousand, respectively, based on the market price at
the vesting date.

During 2012, 2011 and 2010, the General Partner awarded phantom units to certain members of management of the
General Partner under Pioneer Southwest's LTIP. The phantom units entitle the recipients to common units of Pioneer
Southwest after a three-year vesting period. The weighted average grant-date fair value of phantom common units awarded
during 2012, 2011 and 2010 was $28.00, $32.16 and $22.74, respectively. No restrictions have lapsed on the phantom units
outstanding.

Subsidiary Issuances of Unit-Based Compensation

During 2010, Sendero entered into restricted unit agreements with two key employees, granting 1,000 Series B units in
Sendero. The Series B unit awards had a grant date fair value of $5.1 million, vest ratably over a five year service period and do
not earn equity rights unless certain defined performance conditions are achieved by Sendero.

Employee Stock Purchase Plan

The Company has an ESPP that allows eligible employees to annually purchase the Company's common stock at a
discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to
15 percent of an employee's pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to
August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing
sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing
sales price is lower.

103

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

The following table shows the number of shares available for issuance under the ESPP at December 31, 2012:

Approved and authorized shares .............................................................................................................................
Shares issued ..........................................................................................................................................................
Shares available for future issuance .......................................................................................................................

1,250,000
(678,882 )
571,118

Postretirement Benefit Obligations

At December 31, 2012 and 2011, the Company had $9.7 million and $7.5 million, respectively, of unfunded accumulated
postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and
other liabilities, 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 two funded plans that
the Company assumed sponsorship of in conjunction with the acquisition of Premier Silica. Other than the Company's
retirement plan and the two legacy-Premier Silica plans, the participants of these plans are not current employees of the
Company.

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

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related
facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the
Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table
summarizes the Company's asset retirement obligation activity during the years ended December 31, 2012, 2011 and 2010:

Liabilities assumed in acquisitions .........................................................................
New wells placed on production .............................................................................
Changes in estimates (a) .........................................................................................
Liabilities reclassified to discontinued operations held for sale .............................
Disposition of wells ................................................................................................
Liabilities settled .....................................................................................................
Accretion of discount on continuing operations .....................................................
Accretion of discount from integrated services (b) .................................................
Accretion of discount on discontinued operations ..................................................

Beginning asset retirement obligations ...................................................................... $ 136,742
10,498
9,593
51,536
—
(2,536 )
(18,066 )
9,887
100
—
Ending asset retirement obligations ............................................................................ $ 197,754
_____________________
(a)

2012

2010

Year Ended December 31,
2011
(in thousands)
$ 152,291
6
9,233
7,490
(29,892)
(448)
(12,880)
8,256
—
2,686
$ 136,742

$ 166,434
6
5,218
24,075
(5,779 )
(30,693 )
(17,838 )
7,945
—
2,923
$ 152,291

The changes in the 2012, 2011 and 2010 estimates are primarily due to increases in abandonment cost estimates based in
part on recent actual costs incurred and declines in credit-adjusted risk-free discount rates used to value increases in asset
retirement obligations. The increase in the 2012 estimate was also impacted by declines in oil, NGL and gas prices used
to calculate proved reserves, which had the effect of shortening the economic life of certain wells and increasing what
would otherwise have been the present value of future retirement obligations. The increases in 2011 and 2010 estimates
were partially offset by higher oil and NGL prices, which had the effect of lengthening the economic life of certain wells
and decreasing what would otherwise have been the present value of future retirement obligations. The increase in
commodity prices was less substantial in 2011 as compared to 2010.

104

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

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

As of December 31, 2012 and 2011, the current portions of the Company's asset retirement obligations were $13.3

million $14.2 million, respectively.

NOTE J. Commitments and Contingencies

Severance agreements. The Company has entered into severance and change in control agreements with its officers and
certain key employees. The current annual salaries for the officers and key employees covered under such agreements total
$43.9 million.

Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents
with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain
litigation.

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

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain
indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject
to defined limitations, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The
Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures,
including the sale of its Canadian assets in 2007, the sale of Pioneer Tunisia in February 2011 and the sale of Pioneer South
Africa in August 2012, and in connection with sales of joint interests. The Company does not believe that these obligations are
probable of having a material impact on its liquidity, financial position or future results of operations.

Drilling commitments. The Company periodically enters into contractual arrangements under which the Company is
committed to expend funds to drill wells in the future. The Company also enters into agreements to secure drilling rig services,
which require the Company to make future minimum payments to the rig operators. The Company records drilling
commitments in the periods in which the well is drilled or rig services are performed.

Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the
years ended December 31, 2012, 2011 and 2010 were $48.0 million, $35.4 million and $38.3 million, respectively. These
payments include $67 thousand, $513 thousand and $7.2 million associated with discontinued operations for the years ended
December 31, 2012, 2011 and 2010, respectively, which are included in income from discontinued operations, net of tax, in the
accompanying consolidated statements of operations.

Future minimum lease commitments under noncancellable operating leases at December 31, 2012 are as follows (in

thousands):

2013 .............................................................................................................................................................................. $ 24,096
2014 .............................................................................................................................................................................. $ 17,434
2015 .............................................................................................................................................................................. $ 15,500
2016 .............................................................................................................................................................................. $ 14,202
2017 .............................................................................................................................................................................. $ 14,253
Thereafter ..................................................................................................................................................................... $ 36,967

Gathering, processing and transportation agreements. The Company from time to time enters into, and as of December
31, 2012 is a party to, contractual commitments with midstream service companies and pipeline carriers for the future
gathering, processing, transportation and fractionation. These commitments are normal and customary for the Company's

105

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

business activities. Future minimum gathering, processing, transportation and fractionation commitments at December 31,
2012 are as follows (in thousands):

2013 .......................................................................................................................................................................... $ 264,213
2014 .......................................................................................................................................................................... $ 355,451
2015 .......................................................................................................................................................................... $ 404,890
2016 .......................................................................................................................................................................... $ 418,484
2017 .......................................................................................................................................................................... $ 306,894
Thereafter ................................................................................................................................................................. $ 1,255,520

Certain future minimum gathering, processing, transportation and fractionation fees are based upon rates and tariffs

subject to change over the lives of the commitments.

NOTE K. Related Party Transactions

The Company, through a wholly-owned subsidiary, (i) serves as operator of properties in which it and its affiliated
partnerships have an interest and (ii) owns a noncontrolling interest in its unconsolidated affiliate, EFS Midstream, which it
manages. Through these relationships, the Company is a party to transactions with the affiliated partnerships and EFS
Midstream that represent related party transactions.

Transactions with affiliated partnerships. The Company receives producing well overhead and other fees related to the
operation of the properties in which it and its affiliated partnerships have an interest. The affiliated partnerships also reimburse
the Company for their allocated share of general and administrative charges. Reimbursements of fees are recorded as
reductions to general and administrative expenses in the Company's consolidated statements of operations.

The related party transactions with affiliated partnerships are summarized below for the years ended December 31, 2012,

2011 and 2010:

2012

Year Ended December 31,
2011
(in thousands)

2010

Receipt of lease operating and supervision charges in accordance with standard
industry operating agreements .................................................................................... $
Reimbursement of general and administrative expenses ............................................ $

2,437
342

$
$

2,104
313

$
$

2,184
344

Transactions with EFS Midstream. The Company, through a wholly-owned subsidiary, (i) provides certain services as
the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) is the operator of Eagle Ford Shale
properties for which EFS Midstream provides certain services under a Hydrocarbon Gathering and Handling Agreement (the
"HGH Agreement").

Master Services Agreement. The terms of the Master Services Agreement provide that the Company will perform certain
manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to
expenses incurred by employees whose time is substantially dedicated to EFS Midstream's business. During 2012, 2011 and
2010, the Company received $2.3 million, $2.2 million and $1.1 million of fixed payments and $11.8 million, $8.4 million and
$1.9 million of variable payments, respectively, from EFS Midstream. The Company also paid $1.9 million to purchase rights
of way from EFS Midstream during 2011 and received $1.1 million of proceeds from the sale of an amine plant to EFS
Midstream during 2010.

Hydrocarbon Gathering and Handling Agreement. During June 2010, the Company entered into the HGH Agreement
with EFS Midstream. In accordance with the terms of the HGH Agreement, EFS Midstream is obligated to construct certain
equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale
properties operated by the Company. The HGH Agreement also obligates the Company and its Eagle Ford Shale working
interest partners to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with
the terms of the HGH Agreement, the Company paid EFS Midstream $58.5 million, $21.3 million and $404 thousand of
gathering and treating fees during 2012, 2011 and 2010, respectively. Such amounts were expensed as oil and gas production
costs in the accompanying consolidated statements of operations.

106

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

NOTE L. Major Customers

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the
Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of
accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require
purchasers to provide collateral or otherwise secure their accounts.

The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and
gas revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2012.
The loss of any one significant purchaser could have a material adverse effect on the ability of the Company to sell its oil and
gas production. The table provides the percentages of the Company's consolidated oil, NGL and gas revenues represented by
the purchasers during the periods presented:

Plains Marketing LP ...................................................................................................
Enterprise Products Partners L.P. ...............................................................................
Occidental Energy Marketing Inc. .............................................................................

26 %
15 %
14 %

16%
12%
14%

12%
10%
8%

NOTE M. Interest and Other Income

The following table provides the components of the Company's interest and other income during the years ended

December 31, 2012, 2011 and 2010:

Year Ended December 31,

2012

2011

2010

2012

Year Ended December 31,
2011
(in thousands)
38,939
$
7,684
1,925
1,657
697
15,978
66,880

29,342
5,382
2,183
1,872
1,465
(11,934 )
28,310

2010

47,652
4,565
(819 )
1,228
4,177
169
56,972

Alaskan Petroleum Production Tax credits and refunds (a) ....................................... $
Other income ..............................................................................................................
Equity interest in income (loss) of EFS Midstream ....................................................
Deferred compensation plan income ..........................................................................
Interest income ...........................................................................................................
Income (loss) from vertical integration services (b) ...................................................
Total interest and other income .................................................................................. $
______________________
(a)

(b)

The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The
Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in
production and ad valorem taxes if realizable as offsets to PPT expense.
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 years ended December 31, 2012,
2011 and 2010, these net margins include $247.8 million, $50.9 million and $946 thousand of gross vertical integration
revenues, respectively and $259.7 million, $34.9 million and $777 thousand of total vertical integration costs and
expenses, respectively.

107

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

NOTE N. Other Expense

The following table provides the components of the Company's other expense during the years ended December 31,

2012, 2011 and 2010:

Transportation commitment charge (a) ...................................................................... $
37,144
Above market and idle drilling and well service equipment rates (b) ........................
33,211
Other ...........................................................................................................................
18,297
Terminated drilling rig contract charges (c) ...............................................................
15,747
Inventory impairment (d) ...........................................................................................
6,174
Premier Silica acquisition costs ..................................................................................
2,337
478
Contingency and environmental accrual adjustments ................................................
Total other expense .................................................................................................... $ 113,388
____________________
(a)
(b)

Primarily represents firm transportation payments on excess pipeline capacity commitments.
Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that were above market
rates and idle drilling rig and fracture stimulation fleet fees, neither of which were chargeable to joint operations.
Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.

2012

Year Ended December 31,
2011
(in thousands)
23,248
$
20,132
12,603
—
3,126
—
4,057
63,166

2010

1,589
50,581
9,924
—
10,729
—
5,581
78,404

NOTE O. Income Taxes

The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain
subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions
for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable
income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. The Company
made current and estimated tax payments of $32.3 million, $22.3 million and $36.6 million (net of tax refunds) during 2012,
2011 and 2010, respectively. These payments and net refunds include tax payments related to Pioneer Tunisia's and Pioneer
South Africa's operations of $9.8 million, $12.2 million and $17.8 million during 2012, 2011 and 2010, respectively.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not
that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and
worldwide economic factors and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and
other deferred tax attributes in the United States, state, local and foreign tax jurisdictions will be utilized prior to their
expiration.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax
position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. As of
December 31, 2012, the Company had no unrecognized tax benefits. With respect to income taxes, the Company's policy is to
account for interest charges as interest expense and any penalties as other expense in the consolidated statements of operations.
The Company files income tax returns in the United States federal jurisdiction, and various state and foreign jurisdictions.

108

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

As of December 31, 2012, there are no proposed adjustments or uncertain positions in any jurisdiction that would have a
significant effect on the Company's future results of operations or financial position. The Company's earliest open years in its
key jurisdictions are as follows:

United States ...................................................................................................................................................................
Various U.S. states ..........................................................................................................................................................
Tunisia .............................................................................................................................................................................
South Africa ....................................................................................................................................................................

2011
2007
2006
2006

The Company's income tax provision and amounts separately allocated were attributable to the following items for the

years ended December 31, 2012, 2011 and 2010:

2012

Year Ended December 31,
2011
(in thousands)

2010

Income tax provision from continuing operations ......................................................... $
Income tax (provision) benefit from discontinued operations .......................................
Changes in goodwill – tax benefits related to stock-based compensation .....................
Changes in stockholders' equity:

Net deferred hedge (loss) gain ...................................................................................
Excess tax benefit (provision) related to stock-based compensation .........................

Tax attributable to 2008 Pioneer Southwest initial public offering ....................
Tax attributable to 2009 and 2011 issuance of Pioneer Southwest common
units ....................................................................................................................

Tax on Pioneer Southwest common units sold by the Company during 2011 ...

(92,384 ) $ (197,644) $ (269,627)
270
(257,950)
(15,668 )
453

—

(1,725 )
58,486
(49,072 )

8,407
31,087
—

—
—

(23,711)

(15,381)

23,648
(153 )
—

—
—

The Company's income provision attributable to income from continuing operations consisted of the following for the

years ended December 31, 2012, 2011 and 2010:

Current:

U.S. federal ............................................................................................................. $
U.S. state .................................................................................................................

Deferred:

U.S. federal .............................................................................................................
U.S. state .................................................................................................................

Income tax provision from continuing operations ...................................................... $

2012

Year Ended December 31,
2011
(in thousands)

2010

(5,573 ) $
(1,352 )
(6,925 )

—
(9,065)
(9,065)

—
(9,864 )
(9,864 )

(263,063 )
(207,146)
(78,790 )
3,300
18,567
(6,669 )
(85,459 )
(259,763 )
(188,579)
(92,384 ) $ (197,644) $ (269,627 )

109

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income from

continuing operations are as follows for the years ended December 31, 2012, 2011 and 2010:

2012

Year Ended December 31,
2011
(in thousands, except percentages)

2010

Income from continuing operations before income taxes ............................................ $ 280,057
(50,537)
Less: Net income attributable to noncontrolling interests ..........................................
Income from continuing operations attributable to parent before income taxes ..........
229,520
Federal statutory income tax rate ................................................................................
Provision for federal income taxes ..............................................................................
State income taxes (net of federal tax benefit) ............................................................
Other ............................................................................................................................

(80,332)
(5,214)
(6,838)
Income tax provision from continuing operations ................................................... $ (92,384)

$ 656,406
(47,425)
608,981

$ 781,572
(40,787 )
740,785

(213,143)
6,176
9,323
$ (197,644)

35 %
(259,275 )
(4,267 )
(6,085 )
$ (269,627 )

35%

Effective income tax rate, excluding income attributable to the noncontrolling
interest .................................................................................................................

40%

32%

36 %

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax

liabilities related to continuing operations are as follows as of December 31, 2012 and 2011:

Deferred tax assets:

Net operating loss carryforward (a) ......................................................................................... $
Asset retirement obligations ....................................................................................................
Incentive plans .........................................................................................................................
Other ........................................................................................................................................
Total deferred tax assets (b) ..................................................................................................

498,441
69,214
48,575
104,714
720,944

—
47,860
36,610
46,218
130,688

Deferred tax liabilities:

December 31,

2012

2011

(in thousands)

Oil and gas properties, principally due to differences in basis, depletion and the
deduction of intangible drilling costs for tax purposes .....................................................
Other property and equipment, principally due to the deduction of bonus depreciation
for tax purposes ................................................................................................................
State taxes and other ................................................................................................................
Net deferred hedge gains .........................................................................................................
Total deferred tax liabilities...................................................................................................

(102,351 )
(191,621 )
(144,558 )
(2,130,847 )
Net deferred tax liability .............................................................................................................. $ (2,226,897) $ (2,000,159)
Reflected in accompanying consolidated balance sheets as:

(255,943)
(285,313)
(165,504)
(2,947,841)

(2,241,081)

(1,692,317 )

Current deferred income tax liability ....................................................................................... $
Noncurrent deferred income tax liability .................................................................................

(57,713)
(1,942,446 )
Total ...................................................................................................................................... $ (2,226,897) $ (2,000,159)

(2,140,416)

(86,481) $

____________________
(a)
(b)

All net operating loss carryforwards as of December 31, 2012 expire in 2032.
The Company had no deferred tax valuation allowances at December 31, 2012 and 2011.

NOTE P. Net Income Per Share Attributable To Common Stockholders

In the calculation of basic net income per share attributable to common stockholders, participating securities are
allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income
attributable to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do

110

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net
income per share attributable to common stockholders reflects the potential dilution that could occur if securities or other
contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of
common stock that would then share in the earnings of the Company. During periods in which the Company realizes a loss
from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not
be dilutive to net loss per share and conversion into common stock is assumed not to occur. Diluted net income per share is
calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is
presented. For each of the three years in the period ended December 31, 2012, the two-class method of calculating the
Company's diluted net income per share was more dilutive than the treasury stock method.

The Company's basic net income per share attributable to common stockholders is computed as (i) net income
attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted
average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is
computed as (i) basic net income attributable to common stockholders, (ii) plus diluted adjustments to participating
undistributed earnings (iii) divided by weighted average diluted shares outstanding (excluding shares held in treasury).

The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net
income attributable to common stockholders and to diluted net income attributable to common stockholders for the years ended
December 31, 2012, 2011 and 2010:

Net income attributable to common stockholders ...................................................... $ 137,136

Participating basic earnings (a) ...............................................................................
Basic income attributable to common stockholders .............................................
Reallocation of participating earnings (a) ...............................................................

134,976
115
Diluted income attributable to common stockholders .......................................... $ 135,091

(2,160 )

54,280
46
54,326

(869)

$ 192,285
(3,029 )
189,256
161
$ 189,417

Continuing
Operations

Year Ended December 31, 2012
Discontinued
Operations
(in thousands)
55,149
$

Total

Net income attributable to common stockholders ...................................................... $ 411,337

403,855
190
Diluted income attributable to common stockholders .......................................... $ 404,045

(7,482 )

415,456
195
$ 415,651

(7,696)

$ 834,489
(15,178 )
819,311
385
$ 819,696

Continuing
Operations

Year Ended December 31, 2011
Discontinued
Operations
(in thousands)
$ 423,152

Total

Net income attributable to common stockholders ...................................................... $ 471,158

Participating basic earnings (a) ...............................................................................
Basic net income attributable to common stockholders .......................................
Reallocation of participating earnings (a) ...............................................................

(10,818 )
460,340
140
Diluted income attributable to common stockholders .......................................... $ 460,480

130,972
40
$ 131,012

(3,078)

$ 605,208
(13,896 )
591,312
180
$ 591,492

Continuing
Operations

Year Ended December 31, 2010
Discontinued
Operations
(in thousands)
$ 134,050

Total

______________________
(a) Unvested restricted stock awards and Pioneer Southwest phantom unit awards represent participating securities because
they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer
Southwest, as applicable. Participating share- and unit-based earnings represent the distributed and undistributed

111

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012, 2011 and 2010

earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit
awards do not participate in undistributed net losses as they are not contractually obligated to do so.

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted

average common shares outstanding for the years ended December 31, 2012, 2011 and 2010:

2012

Year Ended December 31,
2011
(in thousands)

2010

Weighted average common shares outstanding:

Basic .......................................................................................................................
Dilutive common stock options (a) .........................................................................
Contingently issuable—performance shares...........................................................
Convertible Senior Notes dilution (b) .....................................................................

Diluted ....................................................................................................................

122,966
183
180
2,991

126,320

116,904
190
424
1,697

119,215

115,062
212
646
410

116,330

______________________
(a) Options to purchase 129,918 shares of the Company's common stock were excluded from the diluted income per share
calculations for the year ended December 31, 2012 because they would have been anti-dilutive to the calculation.
(b) Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted
if the Convertible Senior Notes had qualified for and been converted during the years ended December 31, 2012, 2011
and 2010, respectively.

NOTE Q. Subsequent Events

As discussed in Note G, in January and February 2013, holders of $240.6 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. In general, upon conversion of a Convertible Senior Note, the holder will receive cash equal to the principal amount of
the Convertible Senior Note and shares of the Company's common stock for the Convertible Senior Note's conversion value in
excess of the principal amount. In addition, pursuant to the terms of the Convertible Senior Notes, the annual interest rate for
the Convertible Senior Notes has been reduced from 2.875 percent to 2.375 percent per annum for the six-month period from
January 15, 2013 to July 14, 2013 because the Notes met certain trading price conditions.

112

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2012, 2011 and 2010

Oil & Gas Exploration and Production Activities

The Company has operations in one business and geographic segment, that being oil and gas exploration and
production. See the Company's accompanying statements of operations for information about results of operations for oil and
gas producing activities.

Capitalized Costs

December 31,

2012

2011 (a)

(in thousands)

Oil and gas properties:
Proved ........................................................................................................................................... $ 14,259,708
231,555
Unproved .......................................................................................................................................
14,491,263
Capitalized costs for oil and gas properties ...............................................................................
(4,412,913)
Less accumulated depletion, depreciation and amortization .........................................................

Net capitalized costs for oil and gas properties .......................................................................... $ 10,078,350

$ 12,373,848
235,527
12,609,375
(3,955,483 )
$ 8,653,892

_____________________
(a)

Includes $360.0 million of proved property and $307.0 million of accumulated depletion, depreciation and amortization
related to Pioneer South Africa, which was classified as held for sale at December 31, 2011.

Costs Incurred for Oil and Gas Producing Activities (a)

Property acquisition costs:

2012

Year Ended December 31,
2011
(in thousands)

2010

Proved ............................................................................................................
Unproved ........................................................................................................
Exploration costs ................................................................................................
Development costs .............................................................................................
Total costs incurred ............................................................................................
___________________
(a) The costs incurred for oil and gas producing activities includes the following amounts of asset retirement obligations:

16,962 $
140,515
966,828
1,881,459

6,566
175,007
277,656
727,326
$ 1,186,555

124,326
567,196
1,474,393

$ 2,173,486

$ 3,005,764

7,571 $

Proved property acquisition costs ....................................................................... $
Exploration costs ................................................................................................
Development costs .............................................................................................
Total ................................................................................................................... $

2012

Year Ended December 31,
2011
(in thousands)
6
1,222
18,274
19,502

24
2,200
56,648
58,872

2010

6
6,820
14,369
21,195

Reserve Quantity Information

The estimates of the Company's proved reserves as of December 31, 2012, 2011, and 2010 were based on evaluations
prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major
properties and prepared by the Company's engineers with respect to all other properties. Proved reserves were estimated in
accordance with guidelines established by the United States Securities and Exchange Commission (the "SEC") and the FASB,
which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of
the first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for
price and cost escalations except by contractual arrangements.

113

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2012, 2011 and 2010

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of
subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the
volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company
emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise
than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional
information becomes available in the future.

114

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5
1
1

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2012, 2011 and 2010

Revisions of previous estimates. At December 31, 2012, revisions of previous estimates are comprised of 82 MMBOE of
negative price revisions and 27 MMBOE of negative revisions due to updated performance profiles and cost estimates. The
December 31, 2012 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $94.84 per barrel
of oil and $2.76 per Mcf of gas, compared to $96.13 per barrel of oil and $4.12 per Mcf of gas at December 31, 2011.

At December 31, 2011, revisions of previous estimates were comprised of 28 MMBOE of negative price revisions and
10 MMBOE of negative revisions due to updated performance profiles and cost estimates. The December 31, 2011 NYMEX
price used for oil and gas reserve preparation based upon SEC guidelines increased $16.85 per barrel of oil and decreased $0.25
per Mcf of gas from $79.28 per barrel of oil and $4.37 per Mcf of gas at December 31, 2010.

At December 31, 2010, revisions of previous estimates of 66 MBOE were comprised of 59 MMBOE of positive price
revisions and 7 MMBOE of positive technical revisions. The December 31, 2010 NYMEX price for oil and gas reserves
preparation based upon SEC guidelines increased $18.14 per barrel of oil and $0.50 per Mcf of gas from $61.14 per barrel of
oil and $3.87 per Mcf of gas at December 31, 2009.

Extensions and discoveries. Extensions and discoveries at December 31, 2012 and 2011 are primarily comprised of
discoveries and extensions in the Spraberry field and discoveries in the Eagle Ford Shale and Barnett Shale Combo plays. At
December 31, 2010 extensions and discoveries were primarily due to extensions in the Spraberry field and discoveries in the
Eagle Ford Shale and Tunisia.

Sales of minerals-in-place. Sales of minerals-in-place in 2012, 2011 and 2010 are primarily related to the divestment of
Pioneer South Africa, Pioneer Tunisia and certain proved properties in the Eagle Ford Shale, respectively. See Note C for
corresponding information regarding the Company's discontinued operations.

Purchases of minerals-in-place. Purchases of minerals-in-place during all years are primarily attributable to acquisitions

in the Company's Spraberry field.

Improved recovery. Additions from improved recovery during 2012, 2011 and 2010 relate to recognizing secondary

recovery reserves attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

The following table provides the Company's proved developed and proved undeveloped reserves for January 1, 2010 and

for the years ended December 31, 2012, 2011 and 2010.

Proved Developed Reserves:

January 1, 2010 ...............................................................................
December 31, 2010 .........................................................................
December 31, 2011 .........................................................................
December 31, 2012 .........................................................................

144,263
172,816
190,206
230,700

93,015
108,785
120,405
134,637

1,719,722
1,775,611
1,853,363
1,605,209

523,899
577,537
619,506
632,872

Oil
(MBBLs)

NGLs
(MBBLs)

Gas
(MMCF)

Total
(MBOE)

Proved Undeveloped Reserves:

181,073
207,993
239,799
256,138

63,819
75,433
90,630
97,939

779,079
898,911
677,675
592,271

374,737
433,244
443,375
452,789

Oil
(MBBLs)

NGLs
(MBBLs)

Gas
(MMCF)

Total
(MBOE)

116

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2012, 2011 and 2010

The following table summarizes the Company's proved undeveloped reserves activity during the year ended December

31, 2012 (in MBOE).

Beginning proved undeveloped reserves .............................................................................................................
Revisions of previous estimates .......................................................................................................................
Extensions and discoveries ..............................................................................................................................
Sales of minerals-in-place ................................................................................................................................
Purchases of minerals-in-place ........................................................................................................................
Improved recovery ...........................................................................................................................................
Transfers to proved developed .........................................................................................................................
Ending proved undeveloped reserves ..................................................................................................................

443,375
(64,919 )
116,742
(1,544 )
8,844
5,155
(54,864 )
452,789

As of December 31, 2012, the Company had 3,810 proved undeveloped well locations as compared to 4,599 and 4,727
at December 31, 2011 and 2010, respectively. The Company has 505 proved undeveloped well locations (representing 53
MMBOE of proved reserves) that are scheduled to be drilled more than five years from their original date of booking. All of
these wells are scheduled to be drilled within five years of the December 31, 2009 effective date of the Commission's Final
Rule on the Modernization of Oil and Gas Reporting.

The changes in proved undeveloped reserves during 2012 are comprised of the following items:

Revisions of previous estimates. Revisions of previous estimates are comprised of 27 MMBOE of negative price
revisions associated with proved dry gas reserves that are no longer planned to be drilled in the next five years and 38 MMBOE
of negative technical revisions, primarily in the Spraberry field.

Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions and discoveries in the
Wolfcamp, Strawn, Atoka and Mississippian horizons in the Spraberry field and discoveries in the Eagle Ford Shale and
Barnett Shale Combo plays.

Sales of minerals-in-place. Sales of minerals-in-place are primarily related to sales in the Barnett Shale Combo play.

Purchases of minerals-in-place. Purchases of minerals-in-place are primarily attributable to acquisitions in the

Company's Spraberry field.

Improved recovery. Additions from improved recovery relate to recognizing secondary recovery reserves attributable to

waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

Transfers to proved developed. Transfers to proved developed reserves represents those undeveloped proved reserves
that moved to proved developed as a result of development drilling during 2012. During 2012, the Company incurred $1.4
billion of development costs and developed 12 percent of its proved undeveloped reserves. See the table below for the
Company's firm plans for future development expenditures.

As of December 31, 2012, the Company had 31 MMBOE of proved undeveloped reserves for locations that are more
than one location removed from developed locations in the Spraberry field, 16 MMBOE of which were recorded during 2012.
Within the Spraberry field, the Company uses both public and proprietary geologic data to establish continuity of the formation
and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole log
information (both vertical and horizontally collected) and petrophysical analysis of the log data; mud logs; gas sample analysis;
drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores and data measured from the
Company's internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing
producing wells was conducted to generate areas of reasonable certainty at distances from established production. As a result of
this analysis, proved undeveloped reserves for drilling locations within these areas of reasonable certainty were recorded during
2012.

117

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2012, 2011 and 2010

While the Company expects, based on Management's Price Outlooks, that future operating cash flows will provide
adequate funding for future development of its proved undeveloped reserves over the next five years, it may also use any
combination of internally-generated cash flows, cash and cash equivalents on hand, availability under its credit facility,
proceeds from the sale of joint interests and nonstrategic assets or external financing sources to fund these and other capital
expenditures, including exploratory drilling and acquisitions. The following table represents the estimated timing and cash
flows of developing the Company's proved undeveloped reserves as of December 31, 2012 (dollars in thousands):

Year Ended December 31, (a)
2013 ....................................................................
2014 ....................................................................
2015 ....................................................................
2016 ....................................................................
2017 ....................................................................
Thereafter (b)......................................................

Estimated
Future
Production
(MBOE)

6,296
16,922
24,660
32,171
35,831
336,909
452,789

Future Cash
Inflows
423,745
1,043,836
1,458,550
1,963,717
2,199,003
20,538,278
$ 27,627,129

Future
Production
Costs
52,029
139,260
228,735
317,856
383,555
7,150,373
$ 8,271,808

Future
Development
Costs
$ 1,445,947
1,491,933
1,783,818
2,117,725
1,595,912
259,965
$ 8,695,300

Future Net
Cash Flows
$ (1,074,231)
(587,357 )
(554,003 )
(471,864 )
219,536
13,127,940
$ 10,660,021

______________________
(a)

Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved
undeveloped drilling.
The $260.0 million of future development costs includes (i) $35.9 million and $3.9 million of completion costs
forecasted in 2018 and 2019, respectively, and (ii) $220.2 million of net abandonment costs in future years.

(b)

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying commodity prices used in
determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to
the estimated future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be
incurred in developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the
estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to
the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the
difference. The discounted future cash flow estimates do not include the effects of the Company's commodity derivative
contracts. Utilizing the first-day-of-the-month commodity prices during the 12-month period ending on December 31, 2012,
held constant over each derivative contract's term, the net present value of the Company's derivative contracts discounted at ten
percent was an asset of $388.7 million at December 31, 2012.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of
oil and gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future
commodity prices, interest rates, changes in development and production costs and risks associated with future production.
Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

118

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2012, 2011 and 2010

The following tables provide the standardized measure of discounted future cash flows as of December 31, 2012, 2011

and 2010, as well as a rollforward in total for each respective year:

Oil and gas producing activities:

2012

December 31,
2011
(in thousands)

2010

Future cash inflows ........................................................................................ $ 56,692,889
Future production costs ..................................................................................
Future development costs (a) .........................................................................
Future income tax expense ............................................................................

$ 45,995,152
$ 59,220,357
(23,977,062) (21,154,016) (17,540,241 )
(6,769,787 )
(7,235,123 )
14,450,001
(9,037,992 )
$ 5,412,009

(9,803,698 )
(6,600,395 )
16,311,734
(9,958,336 ) (12,205,396)

(8,466,407)
(9,581,515)

$ 7,813,023

20,018,419

10% annual discount factor ............................................................................

Standardized measure of discounted future cash flows (b) ............................... $ 6,353,398
__________________
(a)

Includes $840.0 million, $785.0 million and $823.5 million of undiscounted future asset retirement expenditures
estimated as of December 31, 2012, 2011 and 2010, respectively, using current estimates of future abandonment costs.
See Note I for corresponding information regarding the Company's discounted asset retirement obligations.
Includes $40.7 million and $565.4 million as of December 31, 2011 and 2010, respectively, attributable to discontinued
operations in South Africa and Tunisia. Also includes $282.6 million and $378.6 million attributable to a 48 percent
noncontrolling interest in Pioneer Southwest for 2012 and 2011, respectively, and $214.2 million attributable to a 38
percent noncontrolling interest in Pioneer Southwest for 2010.

(b)

Changes in Standardized Measure of Discounted Future Net Cash Flows

Oil and gas sales, net of production costs ............................................................. $ (2,038,353) $ (1,755,153) $ (1,373,943 )
Revisions of previous estimates:

2012

Year Ended December 31,
2011
(in thousands)

2010

(3,069,880 )
(1,649,417 )
(1,126,865 )
1,109,022
743,212
1,731,465
1,399,731

Net changes in prices and production costs ......................................................
Changes in future development costs ...............................................................
Revisions in quantities ......................................................................................
Accretion of discount ........................................................................................
Changes in production rates, timing and other (a) ............................................
Extensions, discoveries and improved recovery ...................................................
Development costs incurred during the period .....................................................
Sales of minerals-in-place ....................................................................................
Purchases of minerals-in-place .............................................................................
Change in present value of future net revenues ....................................................
Net change in present value of future income taxes .............................................

(38,106 )
172,474
(2,766,717 )
1,307,092
(1,459,625 )
Balance, beginning of year ...................................................................................
7,813,023
Balance, end of year ............................................................................................. $ 6,353,398
__________________
(a)

2,615,481
(1,280,213)
(442,120)
800,468
1,660,419
1,676,866
750,268
(1,021,513)
81,036
3,085,539
(684,525)
2,401,014
5,412,009
$ 7,813,023

2,098,422
(952,508 )
626,693
437,523
1,415,999
1,017,597
380,754
(42,043 )
20,957
3,629,451
(1,547,996 )
2,081,455
3,330,554
$ 5,412,009

The Company's changes in Standardized Measure attributable to production rates, timing and other primarily represent
changes in the Company's estimates of when proved reserve quantities will be realized. During the twelve months ended
December 31, 2012, 2011 and 2010, the Company increased its development drilling capital plans, which had the effect
of accelerating the estimated timing of development and realization of undeveloped proved reserves.

119

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2012, 2011 and 2010

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, 2012 and 2011:

Quarter

First

Second

Third

Fourth

(in thousands, except per share data)

Year Ended December 31, 2012:
Oil and gas revenues:

As reported ..................................................................................... $ 718,956
—
Plus discontinued operations (a) .....................................................
Adjusted ....................................................................................... $ 718,956

$ 641,737
—
$ 641,737

$ 695,422
20,905
$ 716,327

$ 734,640
—
$ 734,640

Total revenues:

As reported (b) ................................................................................ $ 876,210
—
Plus discontinued operations (a) .....................................................
Adjusted ....................................................................................... $ 876,210

$ 917,975
—
$ 917,975

$ 594,922
20,515
$ 615,437

$ 818,686
—
$ 818,686

Total costs and expenses:

As reported ..................................................................................... $ 548,244
—
Plus discontinued operations (a) .....................................................
Adjusted (c) .................................................................................. $ 548,244
Net income (loss) ............................................................................... $ 220,958
Net income (loss) attributable to common stockholders .................... $ 214,619
Net income (loss) attributable to common stockholders per share:

$ 1,014,615
—
$ 1,014,615
$
$

(39,537 ) $
(70,392 ) $

$ 599,487
15,932
$ 615,419
21,699
19,224

$ 769,973
—
$ 769,973
39,702
$
28,834
$

Basic ............................................................................................... $
Diluted ............................................................................................ $

1.73 $
$
1.68

(0.57 ) $
(0.57 ) $

0.15
0.15

$
$

0.23
0.22

Year Ended December 31, 2011:

Oil and gas revenues ....................................................................... $ 475,728
257,264
Total revenues (b) ...........................................................................
381,249
Total costs and expenses (d) ...........................................................
343,804
Net income (loss) ...............................................................................
Net income (loss) attributable to common stockholders ....................
348,594
Net income (loss) attributable to common stockholders per share:

$ 562,412
804,500
395,593
265,700
245,577

$ 591,147
1,000,538
438,338
385,598
351,464

$ 664,776
689,203
879,919
(113,188 )
(111,146 )

Basic ...............................................................................................
Diluted ............................................................................................

2.96
2.96

2.07
2.03

2.96
2.95

(0.93 )
(0.93 )

_____________________
(a) During the third quarter of 2012, the Company committed to a plan to sell the Company's Barnett Shale assets and
classified the results of operations as discontinued operations. As discussed in Note B, during the fourth quarter of 2012,
the Company reclassified the Barnett Shale field to continuing operations. Accordingly, the Barnett Shale results of
operations are classified as continuing operations in all quarters presented.
The Company's total revenues include derivative gains and (losses), net, of $91.8 million, $275.8 million, $(124.0)
million and $86.7 million during the first through fourth quarters of 2012, respectively, and $(244.4) million, $229.5
million, $401.1 million and $6.6 million during the first through fourth quarters of 2011, respectively.

(b)

(c) During the second quarter and fourth quarters of 2012, the Company's total costs and expenses include noncash pretax
charges of $444.9 million and $159.5 million, respectively, to impair the carrying value of proved and unproved oil and
gas properties in the Barnett Shale field.

(d) During the fourth quarter of 2011, the Company's total costs and expenses include pretax charges of $354.4 million to
impair the carrying value of proved oil and gas properties in the Edwards and Austin Chalk fields of South Texas and a
$30.4 million charge for the abandonment of unproved dry gas properties.

120

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A. 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
December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the Company's internal control
over financial reporting.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial
reporting. The Company's internal control over financial reporting is a process designed by or under the supervision of the
Company's principal executive officer and principal financial officer and effected by the Board, management and other
personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's
financial statements for external purposes in accordance with generally accepted accounting principles.

The Company's management, with the participation of its principal executive officer and principal financial officer
assessed the effectiveness, as of December 31, 2012, of the Company's internal control over financial reporting based on the
criteria for effective internal control over financial reporting established in "Internal Control — Integrated Framework," issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management
determined that the Company maintained effective internal control over financial reporting at a reasonable assurance level as of
December 31, 2012, based on those criteria.

Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements
of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the
Company's internal control over financial reporting as of December 31, 2012. The report, which expresses an unqualified
opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2012, is included in
this Item under the heading "Report of Independent Registered Public Accounting Firm."

121

REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM

The Board of Directors and Stockholders of
Pioneer Natural Resources Company

We have audited Pioneer Natural Resources Company's (the "Company") internal control over financial reporting as of
December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the COSO criteria). Pioneer Natural Resources Company's
management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the
effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal
Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial
reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding
of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design
and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Pioneer Natural Resources Company maintained, in all material respects, effective internal control over

financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), the consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2012 and 2011 and the
related consolidated statements of operations, comprehensive income, equity and cash flows for each of the three years in the
period ended December 31, 2012, and our report dated February 13, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas
February 13, 2013

122

PIONEER NATURAL RESOURCES COMPANY

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the

annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the

annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about the Company's equity compensation plans as of December 31, 2012:

Number of securities
to be issued upon exercise
of
outstanding options,
warrants and rights (a)

Weighted-average
exercise price of
outstanding
options, warrants
and rights

Number of securities re
maining
available for future
issuance under equity
compensation
plans (excluding
securities reflected in
first column) (b)

Equity compensation plans approved by security holders:

Pioneer Natural Resources Company:

2006 Long-Term Incentive Plan (c) ...........................
Long-Term Incentive Plan ..........................................
Employee Stock Purchase Plan ..................................

Equity compensation plans not approved by security
holders ..........................................................................
Total: ................................................................................
_______________________
(a)

171,644
—
—

—
171,644

16.72
—
—

—
16.72

2,965,882
—
571,118

—
3,537,000

There are no outstanding warrants or equity rights awarded under the Company's equity compensation plans. The
securities listed do not include restricted stock awarded under the Company's previous Long-Term Incentive Plan and
the Company's 2006 Long-Term Incentive Plan.
In May 2006, the stockholders of the Company approved the 2006 Long-Term Incentive Plan, which provided for the
issuance of up to 9.1 million awards, as was supplementally approved by the stockholders of the Company during May
2009. Awards under the 2006 Long-Term Incentive Plan can be in the form of stock options, stock appreciation rights,
performance units, restricted stock and restricted stock units. No additional awards may be made under the prior Long-
Term Incentive Plan. The number of remaining securities available for future issuance under the Company's Employee
Stock Purchase Plan is based on the original authorized issuance of 750,000 shares plus an additional 500,000 shares
supplementally approved less 678,882 cumulative shares issued through December 31, 2012. See Note H of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description
of each of the Company's equity compensation plans.
The number of securities remaining for future issuance has been reduced by the maximum number of shares that could
be issued pursuant to outstanding grants of performance units at December 31, 2012.

(b)

(c)

The remaining information required in response to this Item will be set forth in the Company's definitive proxy

statement for the annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

123

PIONEER NATURAL RESOURCES COMPANY

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the

annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the

annual meeting of stockholders to be held during May 2013 and is incorporated herein by reference.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Listing of Financial Statements

Financial Statements

PART IV

The following consolidated financial statements of the Company are included in "Item 8. Financial Statements and

Supplementary Data":

• Report of Independent Registered Pubic Accounting Firm
• Consolidated Balance Sheets as of December 31, 2012 and 2011
• Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010
• Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010
• Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2012, 2011 and 2010
• Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010
• Notes to Consolidated Financial Statements
• Unaudited Supplementary Information

(b) Exhibits

The exhibits to this Report that are required to be filed pursuant to Item 15(b) are included in the Company's Form 10-K

filed with the SEC on February 13, 2013.

(c)

Financial Statement Schedules

No financial statement schedules are required to be filed as part of this Report or they are inapplicable.

124

SHAREHOLDER INFORMATION

Stock Exchange Listing – Common Stock

Information Requests

New York Stock Exchange: PXD

To receive additional copies of the Annual

Corporate Headquarters

Pioneer Natural Resources Company

5205 N. O’Connor Blvd., Suite 200

Irving, TX 75039

(972) 444-9001

www.pxd.com

Report on Form 10-K as ﬁled with the SEC or

to obtain other Pioneer publications, please

contact:

Pioneer Natural Resources Company

Investor Relations

5205 N. O’Connor Blvd., Suite 200

Stock Transfer Agent and Registrar

Communication concerning the transfer or

exchange of shares, dividends, lost certiﬁcates

Irving, TX 75039

(972) 969-3583

Email: ir@pxd.com

or change of address should be directed to:

Investor Relations/Media Contact

Continental Stock Transfer & Trust Company

17 Battery Place, 8th Floor

New York, NY 10004

(888) 509-5586

www.continentalstock.com

Email: pioneer@continentalstock.com

Annual Meeting

The Annual Meeting of stockholders will be

held at 5205 N. O’Connor Blvd., Suite 250,

Irving, Texas 75039, on Thursday, May 23, 2013,

at 9:00 a.m. Central Time.

Shareholders, portfolio managers, brokers

and securities analysts seeking information

concerning Pioneer’s operations or ﬁnancial

results are encouraged to contact Frank

Hopkins, Senior Vice President, Investor

Relations at (972) 444-9001. Media inquiries

should be directed to Susan Spratlen, Vice

President, Communication at (972) 444-9001.

Pioneer Natural Resources Company

5205 N. O’Connor Blvd.
Suite 200
Irving, Texas 75039
(972) 444-9001
NYSE: PXD
www.pxd.com